[Federal Register Volume 89, Number 47 (Friday, March 8, 2024)]
[Rules and Regulations]
[Pages 16820-17227]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-00366]



[[Page 16819]]

Vol. 89

Friday,

No. 47

March 8, 2024

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; Final Rule

Federal Register / Vol. 89 , No. 47 / Friday, March 8, 2024 / Rules 
and Regulations

[[Page 16820]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2021-0317; FRL-8510-01-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: Final rule.

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

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

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

FOR FURTHER INFORMATION CONTACT: Ms. Amy Hambrick, Sector Policies and 
Programs Division (E143-05), Office of Air Quality Planning and 
Standards, U.S. Environmental Protection Agency, 109 T.W. Alexander 
Drive, P.O. Box 12055, Research Triangle Park, North Carolina, 27711; 
telephone number: (919) 541-0964; email address: <a href="/cdn-cgi/l/email-protection#b1d9d0dcd3c3d8d2da9fd0dcc8f1d4c1d09fd6dec7"><span class="__cf_email__" data-cfemail="254d444847574c464e0b44485c654055440b424a53">[email protected]</span></a>.

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

AMEL alternative means of emission limitation
ANSI American National Standards Institute
API American Petroleum Institute
ARPA-E Advanced Research Projects Agency-Energy
ASME American Society of Mechanical Engineers
ASTM ASTM, International
AVO audible, visual, and olfactory
AWP alternative work practice
bbl barrels of crude oil
BLM Bureau of Land Management
boe barrels of oil equivalents
BOEM Bureau of Ocean Energy Management
BSER best system of emission reduction
Btu/scf British thermal units per standard cubic foot
[deg]C degrees Celsius
CAA Clean Air Act
CBI Confidential Business Information
CCR Code of Colorado Regulations
CDX EPA's Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CO carbon monoxide
CO<INF>2</INF> carbon dioxide
CO<INF>2</INF> Eq. carbon dioxide equivalent
COS carbonyl sulfide
CRA Congressional Review Act
CS<INF>2</INF> carbon disulfide
CVS closed vent systems
D.C. Circuit U.S. Court of Appeals for the District of Columbia 
Circuit
DOE Department of Energy
EAV equivalent annual value
EDF Environmental Defense Fund
EG emission guidelines
EIA U.S. Energy Information Administration
EJ environmental justice
E.O. Executive Order
EPA Environmental Protection Agency
ESD emergency shutdown devices
[deg]F degrees Fahrenheit
FEAST Fugitive Emissions Abatement Simulation Toolkit
FR Federal Register
FrEDI EPA's Framework for Evaluating Damages and Impacts model
FRFA final regulatory flexibility analysis
g/hr grams per hour
GHG greenhouse gas
GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks
GHGRP Greenhouse Gas Reporting Program
GOR gas-to-oil ratio
H<INF>2</INF>S hydrogen sulfide
HAP hazardous air pollutant(s)
ICR information collection request
IRFA initial regulatory flexibility analysis
IWG Interagency Working Group on the Social Cost of Greenhouse Gases
kg kilograms
kg/hr kilograms per hour
kt kilotons
lb/yr pounds per year
low-E low emission
LDAR leak detection and repair
LPE legally and practicably enforceable
Mcf thousand cubic feet
MW megawatt
NAAQS national ambient air quality standards
NAICS North American Industry Classification System
NDE no detectable emissions
NIE no identifiable emissions
NESHAP national emission standards for hazardous air pollutants
NGO non-governmental organization
NHV net heating value
NO<INF>X</INF> nitrogen oxides
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
O<INF>2</INF> oxygen
OAQPS Office of Air Quality Planning and Standards
OGI optical gas imaging
OMB Office of Management and Budget
PM particulate matter
PM<INF>2.5</INF> particulate matter with a diameter of 2.5 
micrometers or less
ppb parts per billion
ppm parts per million
PRA Paperwork Reduction Act
PSD prevention of significant deterioration
PTE potential to emit
PV present value
REC reduced emissions completion
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
RTC response to comments
RULOF remaining useful life and other factors
SBAR Small Business Advocacy Review
SC-CH<INF>4</INF> social cost of methane
SC-CO<INF>2</INF> social cost of carbon dioxide
SC-GHG social cost of greenhouse gases
SC-N<INF>2</INF>O social cost of nitrous oxide
scf standard cubic feet
scfh standard cubic feet per hour
scfm standard cubic feet per minute
SIP State Implementation Plan
SO2 sulfur dioxide
SPeCS State Planning Electronic Collaboration System
tpy tons per year
the court U.S. Court of Appeals for the District of Columbia Circuit

[[Page 16821]]

TAR Tribal Authority Rule
TIP Tribal Implementation Plan
TSD technical support document
UMRA Unfunded Mandates Reform Act
U.S. United States
VCS voluntary consensus standards
VOC volatile organic compound(s)
VRU vapor recovery unit

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

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document and other related 
information?
    C. Judicial Review and Administrative Review
II. Executive Summary
    A. Purpose of the Regulatory Actions
    B. Summary of the Major Provisions of This Regulatory Action
    C. Costs and Benefits
III. Air Emissions From the Crude Oil and Natural Gas Sector and 
Public Health and Welfare
    A. Impacts of GHGs, VOCs, and SO<INF>2</INF> Emissions on Public 
Health and Welfare
    B. Profile of the Oil and Natural Gas Industry and Its Emissions
IV. Statutory Background and Regulatory History
    A. Statutory Background of CAA Sections 111(b), 111(d), and 
General Implementing Regulations
    B. What is the regulatory history and litigation background of 
NSPS and EG for the oil and natural gas industry?
    C. Congressional Review Act (CRA) Joint Resolution of 
Disapproval
V. Legal Basis for Final Rule Scope
    A. Introduction
    B. Overview
    C. Comments
    D. Response to Comments and Discussion
VI. Other Actions and Related Efforts
    A. Related State Actions and Other Federal Actions Regulating 
Oil and Natural Gas Sources
    B. Industry and Voluntary Actions To Address Climate Change
    C. Methane Emissions Reduction Program
VII. Summary of Engagement With Pertinent Stakeholders
VIII. Overview of Control and Control Costs
    A. Control of Methane and VOC Emissions in the Crude Oil and 
Natural Gas Source Category--Overview
    B. How does the EPA evaluate control costs in this final action?
IX. Interaction of the Rules and Response to Significant Comments 
Thereon
    A. What date defines a new, modified, or reconstructed source 
for purposes of the final NSPS OOOOb?
    B. What date defines an existing source for purposes of the 
final EG OOOOc?
    C. How will the final EG OOOOc impact sources already subject to 
NSPS KKK, NSPS OOOO, or NSPS OOOOa?
X. Summary of Final Standards NSPS OOOOb and EG OOOOc
    A. Fugitive Emissions From Well Sites, Centralized Production 
Facilities, and Compressor Stations
    B. Advanced Methane Detection Technology Work Practices
    C. Super Emitter Program
    D. Process Controllers
    E. Pumps
    F. Wells and Associated Operations
    G. Centrifugal Compressors
    H. Combustion Control Devices
    I. Reciprocating Compressors
    J. Storage Vessels
    K. Covers and Closed Vent Systems
    L. Equipment Leaks at Natural Gas Processing Plants
    M. Sweetening Units
    N. Electronic Reporting
    O. Prevention of Significant Deterioration and Title V 
Permitting
XI. Significant Comments and Changes Since Supplemental Proposal for 
NSPS OOOOb and EG OOOOc
    A. Fugitive Emissions from Well Sites, Centralized Production 
Facilities, and Compressor Stations
    B. Advanced Methane Detection Technology Work Practices
    C. Super Emitter Program
    D. Process Controllers
    E. Pumps
    F. Wells and Associated Operations
    G. Centrifugal Compressors
    H. Combustion Control Devices
    I. Reciprocating Compressors
    J. Storage Vessels
    K. Covers and Closed Vent Systems
    L. Equipment Leaks at Natural Gas Processing Plants
    M. Sweetening Units
XII. Significant Comments and Changes Since Proposal for NSPS OOOOa 
and NSPS OOOO
    A. Low Production Well Site Exemption Rescission
    B. Compressor Station Quarterly Monitoring
    C. Delay-of-Repair Provisions
    D. Applicability/Scope of the Rule
XIII. Significant Comments and Changes to Emission Guidelines for 
State, Tribal, and Federal Plan Development for Existing Sources
    A. Overview
    B. Components of EG
    C. Establishing Standards of Performance in State Plans
    D. Components of State Plan Submission
    E. Timing of State Plan Submissions and Compliance Times
    F. EPA Action on State Plans and Promulgation of Federal Plans
    G. Tribes and the Planning Process Under CAA Section 111(d)
XIV. Use of Optical Gas Imaging in Leak Detection (Appendix K) and 
Response to Significant Comments
    A. Changes Since Supplemental Proposal
    B. Summary of Requirements
XV. Prevention of Significant Deterioration and Title V Permitting
XVI. Summary of Cost, Environmental, and Economic Impacts
    A. What are the air quality impacts?
    B. What are the secondary impacts?
    C. What are the cost impacts?
    D. What are the economic impacts?
    E. What are the benefits?
    F. What analyses of environmental justice did we conduct?
XVII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 14094: Modernizing Regulatory Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act (NTTAA) and 
1 CFR Part 51
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations and Executive Order 14096: Revitalizing Our Nation's 
Commitment to Environmental Justice for All
    K. Congressional Review Act (CRA)

I. General Information

A. Does this action apply to me?

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

[[Page 16822]]



                         Table 1--Industrial Source Categories Affected by NSPS Actions
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              Category                 NAICS Code\1\                 Examples of regulated entities
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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 and Local Government.........           . . . .  Not affected.
Tribal Government..................            921150  American Indian and Alaska Native Tribal Governments.
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\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 the NSPS 
actions. Other types of entities not listed in the table could also be 
affected by these NSPS actions. To determine whether your entity is 
affected by any of the NSPS actions, you should carefully examine the 
applicability criteria found in the final NSPS rules. If you have 
questions regarding the applicability of the NSPS rules to a particular 
entity, consult the person listed in the FOR FURTHER INFORMATION 
CONTACT section, your state air pollution control agency with delegated 
authority for NSPS, or your EPA Regional Office.
    The issuance of CAA section 111(d) final EG does not impose binding 
requirements directly on existing sources. The EG codified in 40 CFR 
part 60, subpart OOOOc, applies to states in the development, 
submittal, and implementation of state plans to establish performance 
standards to reduce emissions of GHGs from designated facilities that 
are existing sources on or before December 6, 2022. Under the Tribal 
Authority Rule (TAR), eligible Tribes may seek approval to implement a 
plan under CAA section 111(d) in a manner similar to a state. See 40 
CFR part 49, subpart A. Tribes may, but are not required to, seek 
approval for treatment in a manner similar to a state for purposes of 
developing a Tribal implementation plan (TIP) implementing the EG 
codified in 40 CFR part 60, subpart OOOOc. The TAR authorizes Tribes to 
develop and implement their own air quality programs, or portions 
thereof, under the CAA. However, it does not require Tribes to develop 
a CAA program. Tribes may implement programs that are most relevant to 
their air quality needs. If a Tribe does not seek and obtain the 
authority from the EPA to establish a TIP, the EPA has the authority to 
establish a Federal CAA section 111(d) plan for designated facilities 
that are located in areas of Indian country.\1\ A Federal plan would 
apply to all designated facilities located in the areas of Indian 
country covered by the Federal plan unless and until the EPA approves a 
TIP applicable to those facilities.
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    \1\ See the EPA's website, https://www.epa.gov/tribal/tribes-approved-treatment-state-tas, for information on those Tribes that 
have treatment as a state for specific environmental regulatory 
programs, administrative functions, and grant programs.
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B. Where can I get a copy of this document and other related 
information?

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

C. Judicial Review and Administrative Review

    Under Clean Air Act (CAA) section 307(b)(1), judicial review of 
this final rulemaking is available only by filing a petition for review 
in the United States Court of Appeals for the District of Columbia 
Circuit by May 7, 2024. Under CAA section 307(b)(2), the requirements 
established by this final rulemaking may not be challenged separately 
in any civil or criminal proceedings brought by the EPA to enforce the 
requirements.
    Section 307(d)(7)(B) of the CAA further provides that ``[o]nly an 
objection to a rule or procedure which was raised with reasonable 
specificity during the period for public comment (including any public 
hearing) may be raised during judicial review.'' This section also 
provides a mechanism for the EPA to convene a proceeding for 
reconsideration, ``[i]f the person raising an objection can demonstrate 
to the EPA that it was impracticable to raise such objection within 
[the period for public comment] or if the grounds for such objection 
arose after the period for public comment, (but within the time 
specified for judicial review) and if such objection is of central 
relevance to the outcome of the rule.'' Any person seeking to make such 
a demonstration to us should submit a Petition for Reconsideration to 
the Office of the Administrator, U.S. Environmental Protection Agency, 
Room 3000, WJC West Building, 1200 Pennsylvania Ave. NW, Washington, DC 
20460, with a copy to both the person(s) listed in the preceding FOR 
FURTHER INFORMATION CONTACT section, and the Associate General Counsel 
for the Air and Radiation Law Office, Office of General Counsel (Mail 
Code 2344A), U.S. Environmental Protection Agency, 1200 Pennsylvania 
Ave. NW, Washington, DC 20460.

II. Executive Summary

A. Purpose of the Regulatory Actions

    On November 15, 2021, the EPA published a proposed rule (``November 
2021 Proposal'') to mitigate climate-destabilizing pollution and 
protect human health by reducing greenhouse gas (GHG) and VOC emissions 
from the oil and natural gas industry,\2\ specifically the Crude Oil 
and Natural Gas source category.<SUP>3 4</SUP> In the November

[[Page 16823]]

2021 Proposal, the EPA proposed new standards of performance under 
section 111(b) of the CAA for GHGs (in the form of methane limitations) 
and VOC emissions from new, modified, and reconstructed sources in this 
source category, as well as revisions to standards of performance 
already codified at 40 CFR part 60, subparts OOOO and OOOOa. The EPA 
also proposed EG under section 111(d) of the CAA for GHGs emissions (in 
the form of methane limitations) from existing sources (designated 
facilities).\5\ The new CAA section 111 NSPS and EG would be codified 
in 40 CFR part 60 at subpart OOOOb (NSPS OOOOb) and subpart OOOOc (EG 
OOOOc), respectively. The EPA also proposed several related actions 
stemming from the joint resolution of Congress, adopted on June 30, 
2021, under the CRA disapproving the EPA's final rule titled, ``Oil and 
Natural Gas Sector: Emission Standards for New, Reconstructed, and 
Modified Sources Review,'' September 14, 2020 (``2020 Policy Rule''). 
Lastly, in the November 2021 Proposal the EPA proposed a protocol under 
the general provisions for OGI.
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    \2\ 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.
    \3\ ``Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review.'' Proposed rule. 86 FR 63110, 
November 15, 2021.
    \4\ 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.''
    \5\ The term ``designated facility'' means ``any existing 
facility which emits a designated pollutant and which would be 
subject to a standard of performance for that pollutant if the 
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
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    On December 6, 2022, the EPA published a supplemental proposed rule 
(``December 2022 Supplemental Proposal'') that was composed of two main 
additions.\6\ First, the EPA updated, strengthened, and expanded on the 
NSPS OOOOb standards proposed in November 2021 under CAA section 111(b) 
for GHGs (in the form of methane limitations) and VOC emissions from 
new, modified, and reconstructed facilities. Second, the EPA updated, 
strengthened, and expanded the presumptive standards proposed for EG 
OOOOc in the November 2021 Proposal as part of the CAA section 111(d) 
EG for GHGs emissions (in the form of methane limitations) from 
designated facilities. For purposes of EG OOOOc, the EPA also proposed 
the implementation requirements for state plans developed to limit GHGs 
pollution (in the form of methane limitations) from designated 
facilities in the Crude Oil and Natural Gas source category under CAA 
section 111(d).
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    \6\ ``Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review.'' Supplemental notice of 
proposed rulemaking. 87 FR 74702, December 6, 2022.
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    The purpose of this final rulemaking is to finalize these multiple 
actions to reduce air emissions from the Crude Oil and Natural Gas 
source category. First, the EPA finalizes NSPS OOOOb regulating GHG (in 
the form of a limitation on emissions of methane) and VOCs emissions 
for the Crude Oil and Natural Gas source category pursuant to CAA 
section 111(b)(1)(B). Second, the EPA finalizes the presumptive 
standards in EG OOOOc to limit GHGs emissions (in the form of methane 
limitations) from designated facilities in the Crude Oil and Natural 
Gas source category, as well as requirements under the CAA section 
111(d) for states to follow in developing, submitting, and implementing 
state plans to establish performance standards. Third, the EPA 
finalizes several related actions stemming from the joint resolution of 
Congress, adopted on June 30, 2021, under the CRA, disapproving the 
2020 Policy Rule. Fourth, the EPA finalizes a protocol under the 
general provisions of 40 CFR part 60 for OGI.
    These final actions stem from the EPA's authority and obligation 
under CAA section 111 to directly regulate categories of new stationary 
sources that cause or contribute to endangerment from air pollution and 
to promulgate EG for states to follow in regulating existing sources 
(designated facilities) in the source category. This final rulemaking 
takes a significant step forward in mitigating climate-destabilizing 
pollution and protecting human health by reducing GHG and VOC emissions 
from the oil and natural gas industry, specifically the Crude Oil and 
Natural Gas source category. These mitigations are based on proven, 
cost-effective technologies already required by prior EPA regulations 
or states' regulations or deployed by industry leaders to reduce this 
dangerous pollution. The final rules will also encourage the deployment 
of innovative technologies that currently exist to rapidly and cost-
effectively detect and reduce methane pollution and promote further 
innovation that is already under way to find even more efficient and 
effective ways to mitigate this pollution. Because methane is the main 
component of natural gas, the rules also result in more saleable 
product.
    The oil and natural gas industry is the United States' largest 
industrial emitter of methane, a highly potent GHG. Emissions of 
methane from human activities are responsible for about one-third of 
the warming due to well-mixed GHGs and constitute the second most 
important warming agent arising from human activity after carbon 
dioxide (CO<INF>2</INF>).\7\ According to the Intergovernmental Panel 
on Climate Change (IPCC), strong, rapid, and sustained methane 
reductions are critical to reducing near-term disruption of the climate 
system as well as a vital complement to reductions in other GHGs that 
are needed to limit the long-term extent of climate change and its 
destructive impacts. The oil and natural gas industry also emits other 
harmful pollutants in varying concentrations and amounts, including 
CO<INF>2</INF>, VOC, sulfur dioxide (SO<INF>2</INF>), nitrogen oxides 
(NO<INF>X</INF>), hydrogen sulfide (H<INF>2</INF>S), carbon disulfide 
(CS<INF>2</INF>), and carbonyl sulfide (COS), as well as benzene, 
toluene, ethylbenzene, and xylenes (this group is commonly referred to 
as ``BTEX''), and n-hexane.
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    \7\ 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.
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    Under the authority of CAA section 111, this rulemaking finalizes 
comprehensive standards of performance for GHG emissions (in the form 
of methane limitations) and VOC emissions for new, modified, and 
reconstructed sources in the Crude Oil and Natural Gas source category, 
including sources located in the production, processing, and 
transmission and storage segments. For designated facilities, this 
rulemaking finalizes EG containing presumptive standards for GHG in the 
form of methane limitations. States must follow these EG to submit to 
the EPA plans that establish standards of performance for designated 
facilities and provide for implementation and enforcement of such 
standards. The EPA will provide support for states in developing their 
plans to reduce methane emissions from designated facilities within the 
Crude Oil and Natural Gas source category. Under the TAR, eligible 
Tribes may seek approval to implement a plan under CAA section 111(d) 
in a manner similar to a state. See 40 CFR part 49, subpart A. Tribes 
may, but are not required to, seek approval for treatment in a manner 
similar to a state for purposes of developing a TIP implementing the EG 
codified in 40 CFR part 60, subpart OOOOc. The TAR authorizes Tribes to 
develop and implement one or more of their own air quality programs, or 
portions thereof, under the CAA. However, it does not require Tribes to 
develop a CAA program. Tribes may implement programs that are most 
relevant to their air quality needs. If a Tribe does not seek and 
obtain the authority from the EPA to establish a TIP, the EPA has the 
authority to establish a Federal CAA section 111(d)

[[Page 16824]]

plan for designated facilities that are located in areas of Indian 
country.\8\ A Federal plan would apply to all designated facilities 
located in the areas of Indian country covered by the Federal plan 
unless and until the EPA approves a TIP applicable to those facilities.
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    \8\ See the EPA website, https://www.epa.gov/tribal/tribes-approved-treatment-state-tas, for information on those Tribes that 
have treatment as a state for specific environmental regulatory 
programs, administrative functions, and grant programs.
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    The EPA is finalizing these actions in accordance with its legal 
obligations and authorities following a review directed by Executive 
Order (E.O.) 13990, ``Protecting Public Health and the Environment and 
Restoring Science to Tackle the Climate Crisis,'' issued on January 20, 
2021. These final actions address the harmful consequences of climate 
change, which is already resulting in severe and growing human and 
economic costs within the United States (and globally too). According 
to the IPCC AR6 assessment, ``It is unequivocal that human influence 
has warmed the atmosphere, ocean and land. Widespread and rapid changes 
in the atmosphere, ocean, cryosphere and biosphere have occurred.'' The 
IPCC AR6 assessment states that these changes have led to increases in 
heat waves and wildfire weather, reductions in air quality, more 
intense hurricanes and rainfall events, and rising sea level. These 
changes, along with future projected changes, endanger the physical 
survival, health, economic well-being, and quality of life of people 
living in the United States (U.S.), especially those in the most 
vulnerable communities.
    Methane is both the main component of natural gas and a potent GHG. 
Using one standard metric (the 100-year global warming potential (GWP), 
which is a measure of the climate impact of emissions of 1 ton of a GHG 
over 100 years relative to the impact of the emissions of 1 ton of 
CO<INF>2</INF> over the same time frame), methane has about 30 times as 
much climate impact as CO<INF>2</INF>. Because methane has a shorter 
lifetime than CO<INF>2</INF>, it has a larger relative impact over 
shorter time frames, and a smaller one over longer time frames: the 
IPCC AR6 assessment found that ``Over time scales of 10 to 20 years, 
the global temperature response to a year's worth of current emissions 
of SLCFs [short lived climate forcers] is at least as large as that due 
to a year's worth of CO<INF>2</INF> emissions.'' \9\ The IPCC estimated 
that, depending on the reference scenario, collective reductions in 
these SLCFs (methane, ozone precursors, and hydrofluorocarbons (HFCs)) 
could reduce warming by 0.2 degrees Celsius ([deg]C) (more than one-
third of a degree Fahrenheit ([deg]F) in 2040 and 0.8 [deg]C (almost 
1.5 [deg]F) by the end of the century. As methane is the most important 
SLCF, this makes methane mitigation one of the best opportunities for 
reducing near-term warming. Emissions from human activities have 
already more than doubled atmospheric methane concentrations since 
1750, and that concentration has been growing larger at record rates in 
recent years.\10\ In the absence of additional reduction policies, 
methane emissions are projected to continue rising through at least 
2040.
---------------------------------------------------------------------------

    \9\ However, the IPCC AR6 assessment cautioned that ``[t]he 
effects of the SLCFs decay rapidly over the first few decades after 
pulse emission. Consequently, on time scales longer than about 30 
years, the net long-term temperature effects of sectors and regions 
are dominated by CO<INF>2</INF>.''
    \10\ Naik, V., S. Szopa, B. Adhikary, P. Artaxo, T. Berntsen, 
W.D. Collins, S. Fuzzi, L. Gallardo, A. Kiendler 41 Scharr, Z. 
Klimont, H. Liao, N. Unger, P. Zanis, 2021, Short-Lived Climate 
Forcers. In: Climate Change 42 2021: The Physical Science Basis. 
Contribution of Working Group I to the Sixth Assessment Report of 
the 43 Intergovernmental Panel on Climate Change [Masson-Delmotte, 
V., P. Zhai, A. Pirani, S.L. Connors, C. 44 P[eacute]an, S. Berger, 
N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. 
Lonnoy, J.B.R. 45 Matthews, T.K. Maycock, T. Waterfield, O. 
Yelek[ccedil]i, R. Yu and B. Zhou (eds.)]. Cambridge University 46 
Press. In Press.
---------------------------------------------------------------------------

    Methane's radiative efficiency means that immediate reductions in 
methane emissions, including from sources in the Crude Oil and Natural 
Gas source category, can help reduce near-term warming. As natural gas 
is composed primarily of methane, every natural gas leak or intentional 
release of natural gas through venting or other processes constitutes a 
release of methane. Reducing human-caused methane emissions, such as 
controlling natural gas leaks and releases through the measures in this 
final action, is critical to addressing climate change and its effects. 
See section III of this preamble for further discussion on the air 
emissions from the Crude Oil and Natural Gas source category climate 
change, including discussion of the impacts of GHGs, VOCs, and 
SO<INF>2</INF> emissions on public health and welfare.
    Methane and VOC emissions from the Crude Oil and Natural Gas source 
category result from a variety of industry operations across the supply 
chain. As natural gas moves through the necessarily interconnected 
system of exploration, production, storage, processing, and 
transmission that brings it from wellhead to commerce, emissions 
primarily result from intentional venting, unintentional gas carry-
through (e.g., vortexing from separator drain, improper liquid level 
settings, liquid level control valve on an upstream separator or 
scrubber does not seal properly at the end of an automated liquid 
dumping event, inefficient separation of gas and liquid phases 
occurring upstream of tanks allowing some gas carry-through), routine 
maintenance, unintentional fugitive emissions, flaring, malfunctions, 
abnormal process conditions, and system upsets. These emissions are 
associated with a range of specific equipment and practices, including 
leaking valves, connectors, and other components at well sites and 
compressor stations; leaks and vented emissions from storage vessels; 
releases from natural gas-driven pumps and natural gas-driven process 
controllers; liquids unloading at well sites; and venting or under-
performing flaring of associated gas from oil wells. But technical 
innovations have produced a range of technologies and best practices to 
monitor, eliminate, or minimize these emissions, which in many cases 
have the benefit of reducing multiple pollutants at once and recovering 
saleable product. These technologies and best practices have been 
deployed by individual oil and natural gas companies, required by state 
regulations, or reflected in regulations issued by the EPA and other 
Federal agencies.
    In developing this final rulemaking, the EPA applied the latest 
available information to finalize the analyses presented in the 
December 2022 Supplemental Proposal. This latest information provided 
additional insights into lessons learned from states' regulatory 
efforts, the emission reduction efforts of leading companies, the 
continued development of new and developing technologies, and 
information and data from peer-reviewed literature and emission 
measurement efforts across the U.S.
    In both the November 2021 Proposal and the December 2022 
Supplemental Proposal, the EPA solicited comment on various aspects of 
the proposed rules. This final rulemaking responds to the nearly one 
million total public comments the Agency received. A wide range of 
stakeholders, including state and local governments, Tribal nations, 
representatives of the oil and natural gas industry, communities 
affected by oil and gas pollution, environmental and public health 
organizations, submitted public comments on both the November 2021 
Proposal and the December 2022 Supplemental Proposal. Following the 
November 2021 Proposal, over 470,000 public comments were submitted. 
After the December 2022 Supplemental

[[Page 16825]]

Proposal, over 515,000 additional public comments were submitted. Many 
commenters representing diverse perspectives expressed general support 
for the proposals and requested that the EPA further strengthen the 
proposed rules and make them more comprehensive. Other commenters 
highlighted implementation or cost concerns related to elements of both 
proposals or provided specific data and information that the EPA was 
able to use to refine or revise several of the proposed standards 
included in the December 2022 Supplemental Proposal.
    This final action also builds on extensive engagement with states, 
Tribes, and a broad range of stakeholders. The EPA conducted 
stakeholder trainings after both the November 2021 Proposal and the 
December 2022 Supplemental Proposal for communities with environmental 
justice (EJ) concerns, Tribes, and small businesses. The EPA held 3-day 
virtual public hearings for both the November 2021 Proposal and the 
December 2022 Supplemental Proposal with over 600 speakers and hundreds 
of viewers on livestream. Tribal consultations were completed after the 
November 2021 Proposal at the request of the Northern Arapahoe Tribe, 
Mandan, Hidatsa and Arikara Nation (MHA Nation), and Eastern Shoshone 
Tribe.\11\ Additional Tribal consultation was completed at the request 
of MHA Nation and an informational meeting was held with the Ute Tribe 
after the December 2022 Supplemental Proposal.\12\ Through this 
stakeholder engagement, the EPA heard from diverse voices and 
perspectives, all of which provided ideas and information that helped 
shape and inform this final rulemaking.
---------------------------------------------------------------------------

    \11\ See Memorandum in EPA-HQ-OAR-2021-0317.
    \12\ See Memorandum in EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    In this final rulemaking, the EPA is finalizing updates to various 
aspects of the proposed rules because of the information received 
through the public comment process. For example, after review of the 
comments, the EPA is finalizing updates to allow owners and operators 
the option to use advanced methane monitoring technologies for 
detecting fugitive emissions. All stakeholders supported allowing for 
the use of alternative technologies and provided the EPA with 
constructive feedback and information to help finalize this aspect of 
the rulemaking, along with improvements that provide greater 
flexibility for owners and operators while ensuring these technologies 
are used in an effective way to detect methane emissions. Among other 
things, the EPA is finalizing changes from the December 2022 
Supplemental Proposal that will allow owners and operators to use 
multiple advanced technologies in combination, and facilitate the use 
of the best advanced technologies that we know of by streamlining 
certain of the proposed monitoring requirements associated with their 
use. The EPA is also finalizing an efficient pathway for demonstrating 
that new technologies meet the performance requirements established 
under this rulemaking, and approving their use under this program. The 
final rulemaking allows for either a periodic screening approach or a 
continuous monitoring approach. The EPA believes this program will 
allow owners and operators to leverage advanced technologies that are 
already available to detect methane emissions rapidly with accuracy, as 
well as to incorporate promising new technologies that are emerging in 
this rapidly evolving field.
    As a result of information provided through the public comment 
process, the EPA is also finalizing revisions to the proposed 
requirements for new sources to limit routine flaring of associated 
gas. During the comment period, the EPA received extensive information 
regarding alternatives to routine flaring, state-level requirements to 
limit or prohibit routine flaring, and commitments that owners and 
operators have already made voluntarily to phase out routine flaring in 
the near future. Based on this information and the EPA's updated BSER 
analysis, the EPA is finalizing requirements that will phase out and 
eventually prohibit routine flaring of associated gas from newly 
constructed wells that are developed after the effective date of this 
rule. These requirements include reasonable exemptions for certain 
temporary and emergency uses of flaring, and a transition period to 
allow owners and operators adequate time to incorporate this 
requirement into their development plans and to deploy any necessary 
equipment and controls. For a subcategory of existing wells (with 
documented methane of 40 tons per year (tpy) or less), the EPA is 
finalizing modifications to its December 2022 Supplemental Proposal to 
allow routine flaring. This approach reflects information the EPA 
received during this rulemaking, and the EPA's updated BSER analysis, 
that indicates that alternatives to routine flaring at such wells are 
generally costly and could be technically challenging to implement, 
while achieving relatively small emission reductions. For higher-
emitting existing (above 40 tpy methane), modified, and reconstructed 
wells, the EPA is finalizing the provisions proposed in the December 
2022 Supplemental Proposal limiting routine flaring to situations in 
which a sales line to collect the associated gas is not available, and 
the owner and operator has submitted a demonstration that other 
alternatives to routine flaring are not available due to technical 
infeasibility. With the updates made in this final rulemaking in 
response to comments, the EPA believes that the final rules and 
emission guidelines provide an approach to limiting routine flaring 
from associated gas that achieves significant reductions in emissions, 
while also providing owners and operators with flexibility to utilize 
routine flaring where needed and sufficient lead time to implement 
alternatives to routine flaring at newly developed wells.
    Further, the EPA is finalizing, with certain revisions, 
requirements proposed in the December 2022 Supplemental Proposal to 
monitor flares to ensure proper operation and assure continual 
compliance. Improperly operating flares are a well-documented large 
source of emissions, and requiring operators to monitor and fix these 
problems will yield significant methane reductions.
    In addition, the EPA is finalizing a Super Emitter Program as part 
of this rulemaking that requires owners and operators to take 
appropriate action to investigate very large emissions events upon 
receiving from the EPA a notification from a certified entity, and if 
necessary, take steps to ensure compliance with the applicable 
regulation(s). The EPA has made important modifications to this program 
based on comments received on the December 2022 Supplemental Proposal. 
Public comments informed the EPA that there is widespread recognition 
of the need to address super-emitters, that it is critical for the EPA 
to have a central role in the program, and that timely information-
sharing and response is key to being able to achieve emission 
reductions. As a result, the final Super Emitter Program provides a 
central role for the EPA in receiving notifications from certified 
third parties and verifying that these notifications are complete and 
have properly documented the existence of a super-emitting event before 
sending them to the appropriate owner or operator. In addition, as 
proposed, the EPA will have a central role in approving monitoring 
technologies, certifying and de-certifying notifiers, requiring that 
third parties submit

[[Page 16826]]

notifications within a limited timeframe, and obligating operators to 
subsequently respond in a timely manner. These targeted changes for the 
Super Emitter Program are intended to ensure that the program operates 
with a high degree of accuracy, integrity, and transparency, while 
providing owners and operators with prompt and reliable notifications 
of super-emitting events that may require follow-up investigation and 
remediation. See sections X and XI of this preamble for a full summary 
and rationale of the changes since proposal.
    After careful consideration of the public comments, the EPA is 
finalizing other aspects of the rulemaking as proposed. For example, 
the EPA is finalizing the NSPS and EG for process controllers (formerly 
referred to as pneumatic controllers) as proposed. For both the NSPS 
and EG, process controllers are required to meet a methane and VOC 
emission rate of zero.\13\ Another area of the rulemaking that the EPA 
is finalizing as proposed is liquids unloading. These sources are 
required to comply with best management practices for every well that 
undergoes liquids unloading that results in vented emissions. The EPA 
is also finalizing standards for well completions and sweetening units 
as proposed. See sections X and XI of this preamble for a full summary 
and rationale of the areas of the rulemaking that are being finalized 
as proposed.
---------------------------------------------------------------------------

    \13\ See tables 3 and 4 of this preamble for a summary of 
process controller standards in Alaska.
---------------------------------------------------------------------------

    The EPA conducted an analysis of EJ in the development of this 
final rulemaking and sought to ensure equitable treatment and 
meaningful involvement of all people regardless of race, color, 
national origin, or income in the process. The EPA engaged and 
consulted representatives of frontline communities that are directly 
affected by and particularly vulnerable to the climate and health 
impacts of pollution from this source category through interactions 
such as webinars, listening sessions, and meetings. These opportunities 
allowed the EPA to hear directly from the public, especially 
overburdened and underserved communities, on the development of the 
rulemaking and to factor these concerns into the rulemaking. The 
extensive pollution reduction measures in this final rulemaking will 
collectively reduce the emissions of a suite of harmful pollutants and 
their associated health impacts in communities adjacent to these 
emission sources. A full discussion and summary of engagement with 
pertinent stakeholders can be found in section VII of the preamble. A 
full discussion of the analysis of EJ is found in section XVI.F of the 
preamble.
    In this final rulemaking, the EPA has conducted a comprehensive 
analysis of the available data from emission sources in the Crude Oil 
and Natural Gas source category, the latest available information on 
control measures and techniques, and information submitted by 
stakeholders through the public comment process to identify achievable, 
cost-effective measures to significantly reduce emissions, consistent 
with the requirements of section 111 of the CAA. This final rulemaking 
will lead to significant and cost-effective reductions in climate and 
health-harming pollution and encourage development and deployment of 
innovative technologies to further reduce this pollution in the Crude 
Oil and Natural Gas source category.
    As described in more detail below, the EPA recognizes that several 
states and other Federal agencies currently regulate the oil and 
natural gas industry. The EPA also recognizes that these state and 
other Federal agency regulatory programs have matured since the EPA 
began implementing the current NSPS requirements in 2012 and 2016. The 
EPA further acknowledges the technical innovations that the oil and 
natural gas industry has made during the past decade; this industry 
operates at a fast pace and changes constantly as technology evolves. 
The EPA commends these efforts and recognizes states for their 
innovative standards, alternative compliance options, and 
implementation strategies, and these final actions build upon progress 
made by certain states and Federal agencies in reducing GHG and VOC 
emissions. See preamble section VI for further discussion of Related 
State Actions and Other Federal Actions Regulating Oil and Natural Gas 
Sources and Industry and Voluntary Actions to Address Climate Change.
    As the Federal agency with primary responsibility to protect human 
health and the environment, the EPA has the unique responsibility and 
authority to regulate harmful air pollutants emitted by the Crude Oil 
and Natural Gas source category. The EPA recognizes that states and 
other Federal agencies regulate in accordance with their respective 
legal authorities and within their respective jurisdictions but 
collectively do not fully and consistently address the range of sources 
and emission reduction measures contained in this final rulemaking. 
Direct Federal regulation of methane from new, reconstructed, and 
modified sources in this category, combined with approved state plans 
that are consistent with the EPA's EG presumptive standards for 
designated facilities (existing sources), will help reduce both 
climate- and other health-harming pollution from a large number of 
sources that are either unregulated or from which additional, cost-
effective reductions are available, level the regulatory playing field, 
and help promote technological innovation.
    Included in this final rulemaking are the final new subparts NSPS 
OOOOb and EG OOOOc and amendatory regulatory text for NSPS OOOO, NSPS 
OOOOa, and 40 CFR part 60, subpart KKK (NSPS KKK). The public docket 
for this rulemaking also includes the full text redline versions of 
NSPS OOOO, NSPS OOOOa, and NSPS KKK amendments.\14\ In addition, the 
EPA is providing a Response to Comments (RTC) document and updated 
documents including the technical support document (TSD), supporting 
information collection request (ICR) burden statements, and regulatory 
impact analysis (RIA) that seeks to account for the full impacts of 
these proposed actions.
---------------------------------------------------------------------------

    \14\ Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

B. Summary of the Major Provisions of This Regulatory Action

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

[[Page 16827]]

    Second, pursuant to CAA section 111(d), the EPA is finalizing the 
first nationwide EG for states to limit methane pollution from 
designated facilities in the Crude Oil and Natural Gas source category. 
The EG being finalized in this rulemaking will be in a new subpart, 40 
CFR part 60, subpart OOOOc (EG OOOOc). The EG finalizes presumptive 
standards for GHG emissions (in the form of methane limitations) from 
designated facilities that commenced construction, reconstruction, or 
modification on or before December 6, 2022, and implementation 
requirements designed to inform states in the development, submittal, 
and implementation of state plans that are required to establish 
standards of performance for emissions of GHGs from their designated 
facilities in the Crude Oil and Natural Gas source category. The EPA is 
also finalizing regulatory language in NSPS OOOO, NSPS OOOOa, and NSPS 
KKK to provide clarity on when sources transition from being subject to 
these NSPS and become subject to a state or Federal plan implementing 
EG OOOOc.
    Third, the EPA is taking several related actions stemming from the 
joint resolution of Congress, adopted on June 30, 2021, under the CRA, 
disapproving the EPA's final rule titled, ``Oil and Natural Gas Sector: 
Emission Standards for New, Reconstructed, and Modified Sources 
Review,'' 85 FR 57018 (September 14, 2020) (``2020 Policy Rule''). As 
explained in section XII of this document, the EPA is finalizing 
amendments to the 2016 NSPS OOOOa to address (1) certain 
inconsistencies between the VOC and methane standards resulting from 
the disapproval of the 2020 Policy Rule and (2) certain determinations 
made in the final rule titled, ``Oil and Natural Gas Sector: Emission 
Standards for New, Reconstructed, and Modified Sources 
Reconsideration,'' 85 FR 57398 (September 15, 2020) (``2020 Technical 
Rule''), specifically with respect to fugitive emissions monitoring at 
low production well sites and gathering and boosting stations. With 
respect to the latter, as described below, the EPA is finalizing the 
rescission of provisions of the 2020 Technical Rule that were not 
supported by the record for that rule or by our subsequent information 
and analysis.
    In addition, in this final rulemaking the EPA updates the NSPS OOOO 
and NSPS OOOOa provisions in the CFR to reflect the CRA resolution's 
disapproval of the final 2020 Policy Rule, specifically, the 
reinstatement of the NSPS OOOO and NSPS OOOOa requirements that the 
2020 Policy Rule repealed but that came back into effect immediately 
upon enactment of the CRA resolution. It should be noted that these 
requirements have come back into effect already, even prior to these 
updates to CFR text to reflect them.\15\ The EPA waited to make these 
updates to the CFR text until the final rule simply because it was more 
efficient and clearer to amend the CFR once at the end of this 
rulemaking process to account for all changes to the 2012 NSPS OOOO (77 
FR 49490, August 16, 2012) and 2016 NSPS OOOOa at the same time.
---------------------------------------------------------------------------

    \15\ See Congressional Review Act Resolution to Disapprove EPA's 
2020 Oil and Gas Policy Rule Questions and Answers (June 30, 2021) 
available at https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.
---------------------------------------------------------------------------

    Fourth, the EPA is finalizing a protocol for the use of OGI in leak 
detection being finalized as appendix K to 40 CFR part 60 (referred to 
hereafter as appendix K). While this protocol is being finalized in 
this action, the applicability of the protocol is broader. The protocol 
is applicable to facilities when specified in a referencing subpart to 
help determine the presence and location of leaks; it is not currently 
applicable for use in direct emission rate measurements from sources. 
The protocol does not on its own apply to any sources. For NSPS OOOOb 
and EG OOOOc, we are finalizing the use of the protocol for application 
at natural gas processing plants. The protocol may be applied to other 
sources only when incorporated through rulemaking to a specific 
subpart.
    Each group of actions just described is severable from the other. 
In addition, within each group of actions, the requirements governing 
each emission source are separate from and so severable from the 
requirements for each other emission source. Specifically, for each 
emission source, the EPA separately analyzed and determined the 
appropriate BSER. And for each emission source, the EPA conducted a 
separate analysis for new sources governed by the NSPS and for existing 
sources covered by the EG. Each of the requirements in this final rule 
is functionally independent--i.e., may operate in practice 
independently of the other standards of performance.
    As CAA section 111(a)(1) requires, the standards of performance 
being finalized in this rulemaking reflect ``the degree of emission 
limitation achievable through the application of the best system of 
emission reduction [BSER] which (taking into account the cost of 
achieving such reduction and any nonair quality health and 
environmental impact and energy requirement) the Administrator 
determines has been adequately demonstrated.'' \16\ This rulemaking 
further finalizes EG for designated facilities, under which states must 
submit plans which establish standards of performance that reflect the 
degree of emission limitation achievable through application of the 
BSER, as identified in the final EG. In this final rulemaking, we 
evaluated new data made available to the EPA and information provided 
from public comments on the December 2022 Supplemental Proposal to 
update the analyses and evaluate whether revisions to the proposed BSER 
should be considered. For any potential control measure evaluated in 
this rulemaking, as in the December 2022 Supplemental Proposal, the EPA 
evaluated the emission reductions achievable through these measures and 
employed multiple approaches to evaluate the reasonableness of control 
costs associated with the options under consideration. For example, in 
evaluating controls for reducing VOC and methane emissions from new 
sources, we considered a control measure's cost effectiveness under 
both a ``single-pollutant cost effectiveness'' approach and a 
``multipollutant cost effectiveness'' approach to appropriately 
consider that the systems of emission reduction considered in this 
rulemaking \17\ typically achieve reductions in multiple pollutants at 
once and secure a multiplicity of climate and public health benefits. 
For both NSPS OOOOb and EG OOOOc, we also compared: (1) the capital 
costs that would be incurred through compliance with the final 
standards against the industry's current level of capital expenditures 
and (2) the annualized costs against the industry's estimated annual 
revenues. For a detailed discussion of the EPA's consideration of this 
and other BSER statutory elements, see sections IV and VIII of this

[[Page 16828]]

preamble. Table 2 summarizes the applicability dates for the four 
subparts that the EPA is finalizing.
---------------------------------------------------------------------------

    \16\ 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.
    \17\ For EG OOOOc, where the pollutant is GHGs in the form of 
limitations on methane, the EPA considered a control measure's cost 
effectiveness under a ``single-pollutant cost effectiveness'' 
approach.

Table 2--Applicable Dates for Subparts Addressed in This Rulemaking \18\
------------------------------------------------------------------------
             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
                                                       December 6, 2022.
40 CFR part 60, subpart OOOOb...  New, modified, or   After December 6,
                                   reconstructed       2022.
                                   sources.
40 CFR part 60, subpart OOOOc...  Existing sources..  On or before
                                                       December 6, 2022.
------------------------------------------------------------------------

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

    \18\ See preamble section IX, ``Interaction of the Rules and 
Response to Significant Comments Thereon'' for discussion on the 
applicable dates.
---------------------------------------------------------------------------

    As described in section X of this preamble, the EPA is finalizing 
several changes to the BSER and the NSPS for certain affected 
facilities based on a review of new data made available to the EPA and 
information provided in public comments. For the other NSPS that 
generally remain unchanged, the EPA is finalizing them as proposed in 
the November 2021 Proposal and/or December 2022 Supplemental Proposal. 
The EPA is also finalizing further justifications, flexibilities, or 
clarifications, as needed, based on the public comments and other 
additional information received, as described in section X of this 
preamble. The NSPS applies to affected sources across the Crude Oil and 
Natural Gas source category, including the production, processing, 
transmission, and storage segments, for which construction, 
reconstruction, or modification commenced after December 6, 2022, which 
is the date of publication of the supplemental proposal for NSPS OOOOb.
    In particular, this action finalizes changes to strengthen the 
proposed VOC and methane standards addressing: fugitive emissions from 
well sites; monitoring of control devices; super-emitters; storage 
vessels; associated gas; pumps; equipment leaks at gas plants; appendix 
K; centrifugal compressors; and reciprocating compressors. It generally 
leaves unchanged the SO<INF>2</INF> performance standard for sweetening 
units and the VOC and methane performance standards for well 
completions, gas well liquids unloading operations, process 
controllers, and fugitive emissions from compressor stations. A summary 
of the final BSER determination and final NSPS for affected sources for 
which construction, reconstruction, or modification commenced after 
December 6, 2022 (NSPS OOOOb), is presented in table 2. See sections X 
and XI of this preamble for a complete discussion of the changes to the 
BSER determination and NSPS requirements.
    The final NSPS OOOOb also includes provisions for the use of 
advanced methane detection technologies that allow for periodic 
screening or continuous monitoring for fugitive emissions and emissions 
from covers and closed vent systems (CVS) used to route emissions to 
control devices. These advanced methane detection technologies could 
also be used to identify super-emitter emissions events sooner and 
outside the normal periodic OGI monitoring for fugitive emissions, 
control devices, covers on storage vessels, and CVS. Therefore, the EPA 
is finalizing a Super Emitter Program where an owner or operator must 
investigate, and if necessary, take steps to ensure compliance with the 
applicable regulation(s) upon receiving certified notifications of 
detected emissions that are 100 kilograms per hour (kg/hr) of methane 
or greater. See section X.C of this preamble for a complete discussion 
of these final provisions.
2. EG for Sources Constructed Prior to December 6, 2022 (EG OOOOc)
    As described in sections X and XI of this preamble, the EPA is 
finalizing several changes to the BSER determinations and presumptive 
standards that were proposed under the authority of CAA section 111(d) 
in the November 2021 Proposal and/or the December 2022 Supplemental 
Proposal. These changes are based on a review of new data made 
available to the EPA and information provided in public comments. In 
the November 2021 Proposal, the EPA proposed the first nationwide EG 
for GHG (in the form of methane limitations) for the Crude Oil and 
Natural Gas source category, including the production, processing, and 
transmission and storage segments (EG OOOOc). In the December 2022 
Supplemental Proposal, the EPA proposed key implementation information 
unique to the EG for stakeholders.
    This action finalizes revisions to strengthen the proposed 
presumptive standards for methane addressing: fugitive emissions from 
well sites; monitoring of control devices; super-emitters; storage 
vessels; associated gas; pumps; equipment leaks at gas plants; appendix 
K; centrifugal compressors; and reciprocating compressors. It generally 
leaves unchanged the presumptive standards for gas well liquids 
unloading operations, process controllers, and fugitive emissions from 
compressor stations. A summary of the final BSER determination and 
final presumptive standards for EG OOOOc is presented in table 3. See 
section X of this preamble for a complete discussion of the changes to 
the BSER determination and final presumptive standards.
    The final EG OOOOc also includes the same provisions described for 
NSPS OOOOb that allow for the use of alternative test methods using 
advanced methane detection technologies for periodic screening or 
continuous monitoring for fugitive emissions and emissions from covers 
and CVS used to route emissions to control devices. Finally, the EPA is 
also finalizing in the final EG OOOOc presumptive requirements for 
state plans to include a Super Emitter Program, where an owner or 
operator must investigate, and if necessary, take steps to ensure 
compliance with the applicable regulation(s) upon receiving certified 
notifications of detected emissions that are 100 kilograms per hour 
(kg/hr) of methane or greater. See section X of this preamble for a 
complete discussion of these final provisions.

[[Page 16829]]

    As stated in the November 2021 Proposal \19\ and the December 2022 
Supplemental Proposal,\20\ when the EPA establishes NSPS for a source 
category, the EPA is required to issue EG to reduce emissions of 
certain pollutants from existing sources in that same source category. 
In such circumstances, under CAA section 111(d), the EPA must issue 
regulations to establish procedures under which states submit plans to 
establish, implement, and enforce standards of performance for existing 
sources for certain air pollutants to which a Federal NSPS would apply 
if such existing source were a new source. Thus, the issuance of CAA 
section 111(d) final EG does not impose binding requirements directly 
on existing sources but instead provides requirements for states in 
developing their plans. There is a fundamental requirement under CAA 
section 111(d) that a state's standards of performance in its state 
plan submittal are no less stringent than the presumptive standard 
determined by the EPA, which derives from the definition of ``standard 
of performance'' in CAA section 111(a)(1). Further, as provided in CAA 
section 111(d), a state may choose to take into account remaining 
useful life and other factors (RULOF) in applying a standard of 
performance to a particular source, consistent with the CAA, the EPA's 
implementing regulations, and the final EG.
---------------------------------------------------------------------------

    \19\ See 86 FR 63117 (November 15, 2021).
    \20\ See 87 FR 74702 (December 6, 2022).
---------------------------------------------------------------------------

    The EPA is finalizing changes to the BSER determinations and the 
degree of limitation achievable through application of the BSER for 
certain existing equipment, processes, and activities across the Crude 
Oil and Natural Gas source category. Those changes are discussed in 
section X of this preamble. Section XIII of this preamble discusses the 
components of EG, including the steps, requirements, and considerations 
associated with the development, submittal, and implementation of 
state, Tribal, and Federal plans, as appropriate. For the EG, the EPA 
is translating the degree of emission limitation achievable through 
application of the BSER (i.e., level of stringency) into presumptive 
standards that states may use in the development of state plans for 
specific designated facilities. In doing so, the EPA has formatted the 
final EG OOOOc such that if a state chooses to adopt these presumptive 
standards as the standards of performance in a state plan, the EPA 
could approve such a plan as meeting the requirements of CAA section 
111(d) and the finalized EG, if the plan meets all other applicable 
requirements. In this way, the presumptive standards included in the 
final EG OOOOc serve a function similar to that of a model rule,\21\ 
because they are intended to assist states in developing their plan 
submissions by providing states with a starting point for standards 
that are based on general industry parameters and assumptions. The EPA 
anticipates that providing these presumptive standards will create a 
streamlined approach for states in developing state plans and for the 
EPA in evaluating state plans. However, the EPA's action on each state 
plan submission is carried out via rulemaking, which includes public 
notice and comment. Inclusion of presumptive standards in the final EG 
does not predetermine the outcomes of any future rulemaking on state 
plan submittals.
---------------------------------------------------------------------------

    \21\ 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 XIII.F of this document 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 
designated facilities located within that Tribe's area of Indian 
country. A summary of the final EG for existing sources (EG OOOOc) for 
the oil and natural gas sector is presented in table 4. See section X 
of this preamble for a complete discussion of the final EG 
requirements.
3. Final Amendments to 2016 NSPS OOOOa, and CRA-Related CFR Updates
    The EPA is finalizing modifications to the 2016 NSPS OOOOa to 
address certain amendments to the VOC standards for sources in the 
production and processing segments finalized in the 2020 Technical 
Rule. Because the methane standards for the production and processing 
segments and all standards for the transmission and storage segment 
were removed from the 2016 NSPS OOOOa via the 2020 Policy Rule prior to 
the finalization of the 2020 Technical Rule, the latter amendments 
apply only to the 2016 NSPS OOOOa VOC standards for the production and 
processing segments. In this final rulemaking, the EPA also is applying 
some of the 2020 Technical Rule amendments to the methane standards for 
all industry segments and to VOC standards for the transmission and 
storage segment in the 2016 NSPS OOOOa. These amendments are associated 
with the requirements for well completions, pumps, closed vent systems, 
fugitive emissions, alternative means of emission limitation (AMELs), 
and onshore natural gas processing plants, as well as other technical 
clarifications and corrections. The EPA is also finalizing a repeal of 
the amendments in the 2020 Technical Rule that (1) exempted low 
production well sites from monitoring fugitive emissions and (2) 
changed monitoring of VOC emissions at gathering and boosting 
compressor stations from quarterly to semiannual, which currently 
applies only to VOC standards (not methane standards) from the 
production and processing segments. A summary of the final amendments 
to the 2016 OOOOa NSPS is presented in section XII of this preamble.
    Lastly, in this rulemaking, the EPA updates the NSPS OOOO and OOOOa 
provisions in the CFR to reflect the CRA resolution's disapproval of 
the final 2020 Policy Rule, specifically, the reinstatement of the NSPS 
OOOO and OOOOa requirements that the 2020 Policy Rule repealed but that 
came back into effect immediately upon enactment of the CRA resolution. 
The EPA waited to make the updates to the CFR text until the final 
rulemaking because it would be more efficient and clearer to amend the 
CFR once at the end of this rulemaking process to account for all 
changes to the 2012 NSPS OOOO and 2016 NSPS OOOOa at the same time, 
rather than make piecemeal amendments to the CFR.

[[Page 16830]]



     Table 3--Summary of Final BSER and Final New Source Performance
              Standards for GHGs and VOCs (NSPS OOOOb) \22\
------------------------------------------------------------------------
                                                       Final new source
                                                          performance
         Affected source              Final BSER      standards for GHGs
                                                           and VOCs
------------------------------------------------------------------------
Fugitive Emissions: Single        Quarterly AVO       Quarterly AVO
 Wellhead Only Well Sites and      monitoring          surveys. First
 Small Well Sites.                 surveys.            attempt at repair
                                                       within 15 days
                                                       after detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 15
                                                       days after 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: Multi-        Quarterly AVO       Quarterly AVO
 wellhead Only Well Sites (2 or    monitoring          surveys. First
 more wellheads).                  surveys.            attempt at repair
                                  AND...............   within 15 days
                                  Monitoring and       after detecting
                                   repair based on     fugitive
                                   semiannual          emissions. Final
                                   monitoring using    repair within 15
                                   OGI \2\.            days after first
                                                       attempt.
                                                      Semiannual OGI
                                                       monitoring
                                                       (Optional
                                                       semiannual EPA
                                                       Method 21
                                                       monitoring with
                                                       500 ppm defined
                                                       as a leak).
                                                      First attempt at
                                                       repair within 30
                                                       days after
                                                       detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after 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    Bimonthly AVO       Bimonthly AVO
 with Major Production and         monitoring          surveys. First
 Processing Equipment and          surveys (i.e.,      attempt at repair
 Centralized Production            every other         within 15 days
 Facilities.                       month).             after detecting
                                  AND...............   fugitive
                                  Monitoring and       emissions. Final
                                   repair based on     repair within 15
                                   quarterly           days after first
                                   monitoring using    attempt.
                                   OGI.               AND
                                                      Well sites with
                                                       specified major
                                                       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 after
                                                       detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after 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         Monthly AVO
 Stations.                         monitoring          surveys. First
                                   surveys.            attempt at repair
                                  AND...............   within 15 days
                                  Monitoring and       after detecting
                                   repair based on     fugitive
                                   quarterly           emissions. Final
                                   monitoring using    repair within 15
                                   OGI.                days after first
                                                       attempt.
                                                      AND
                                                      Quarterly OGI
                                                       monitoring.
                                                       (Optional
                                                       quarterly EPA
                                                       Method 21
                                                       monitoring with
                                                       500 ppm defined
                                                       as a leak).
                                                      First attempt at
                                                       repair within 30
                                                       days after
                                                       detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after first
                                                       attempt.
Fugitive Emissions: Well Sites    Monitoring and      Annual OGI
 and Compressor Stations on        repair based on     monitoring.
 Alaska North Slope.               annual monitoring   (Optional annual
                                   using OGI.          EPA Method 21
                                                       monitoring with
                                                       500 ppm defined
                                                       as a leak).
                                                      First attempt at
                                                       repair within 30
                                                       days after
                                                       detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after first
                                                       attempt.
Storage Vessels: A Single         Capture and route   95 percent
 Storage Vessel or Tank Battery    to a control        reduction of VOC
 with PTE \4\ of 6 tpy or more     device.             and methane.
 of VOC or PTE of 20 tpy or more
 of methane.
Process Controllers: Natural Gas- Use of zero-        VOC and GHG
 driven.                           emissions           (methane)
                                   controllers.        emission rate of
                                                       zero.
Process Controllers: Alaska (at   Use of low-bleed    Natural gas bleed
 sites where onsite power is not   process             rate no greater
 available--continuous bleed       controllers.        than 6 scfh.\5\
 natural gas-driven).
Process Controllers: Alaska (at   Monitor and repair  OGI monitoring and
 sites where onsite power is not   through fugitive    repair of
 available--intermittent natural   emissions program.  emissions from
 gas-driven).                                          controller
                                                       malfunctions.

[[Page 16831]]

 
Well Liquids Unloading..........  Best management     Perform best
                                   practices to        management
                                   minimize or         practices to
                                   eliminate methane   minimize or
                                   and VOC emissions   eliminate methane
                                   to the maximum      and VOC emissions
                                   extent possible.    to the maximum
                                                       extent possible
                                                       from liquids
                                                       unloading events
                                                       that vent
                                                       emissions to the
                                                       atmosphere.
Wet Seal Centrifugal Compressors  Capture and route   95 percent
 (except for those located at      emissions from      reduction of
 well sites).                      the wet seal        methane and VOC
                                   fluid degassing     emissions.
                                   system to a
                                   control device.
Wet Seal Centrifugal Compressors  (Optional)          Monitoring and
 (except for those located at      Monitoring and      repair to
 well sites): Self-contained       repair to           maintain
 centrifugal compressors and wet   maintain            volumetric flow
 seal compressors equipped with    volumetric flow     rate at or below
 a mechanical seal.                rate at or below    3 scfm per
                                   3 scfm.             compressor seal.
Wet Seal Centrifugal Compressors  (Optional)          Monitoring and
 (except for those located at      Monitoring and      repair to
 well sites): Alaska North Slope   repair to           maintain
 centrifugal compressors           maintain            volumetric flow
 equipped with a seal oil          volumetric flow     rate at or below
 recovery system.                  rate at or below    9 scfm per
                                   9 scfm per seal.    compressor seal.
Dry Seal Centrifugal Compressors  Monitoring and      Monitoring and
 (except for those located at      repair to           repair of seal to
 well sites).                      maintain            maintain
                                   volumetric flow     volumetric flow
                                   rate at or below    rate at or below
                                   10 scfm \7\ per     10 scfm per
                                   seal.               compressor seal.
Reciprocating Compressors         Monitoring and      Monitoring and
 (except for those located at      repair or replace   repair or
 well sites).                      the reciprocating   replacement of
                                   compressor rod      rod packing to
                                   packing in order    maintain
                                   to maintain         volumetric flow
                                   volumetric flow     rate at or below
                                   rate at or below    2 scfm per
                                   2 scfm per          cylinder.
                                   cylinder.
Pumps: Natural gas-driven.......  Use of zero-        GHG (methane) and
                                   emissions pumps.    VOC emission rate
                                                       of zero.
Pumps: Natural gas-driven (at     Use of an existing  Route pump
 sites where onsite power is not   VRU or control      emissions to a
 available and there are fewer     device.             process if VRU is
 than 3 diaphragm pumps).                              onsite, or to
                                                       control device if
                                                       onsite.
Well Completions: Subcategory 1   Combination of REC  Applies to each
 (non-wildcat and non-             \8\ and the use     well completion
 delineation wells).               of 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, reinject
                                                       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
                                                       reinjected into
                                                       the well or
                                                       another well.
                                                      The operator is
                                                       required to have
                                                       (and use) a
                                                       separator onsite
                                                       during the entire
                                                       flowback period.

[[Page 16832]]

 
Well Completions: Subcategory 2   Use of a            Applies to each
 (exploratory, wildcat, and        completion          well completion
 delineation wells and non-        combustion device.  operation with
 wildcat and non-delineation low-                      hydraulic
 pressure 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 Gas    LDAR \9\ with       LDAR with OGI
 Processing Plants.                bimonthly OGI.      following
                                                       procedures in
                                                       appendix K.
New Wells with Associated Gas     Route associated    Route associated
 that commenced construction       gas to a sales      gas to a sales
 after May 7, 2026.                line.               line; or, the gas
                                                       can be used for
                                                       another useful
                                                       purpose that a
                                                       purchased fuel,
                                                       chemical
                                                       feedstock, or raw
                                                       material would
                                                       serve, or
                                                       recovered from
                                                       the separator and
                                                       reinjected into
                                                       the well or
                                                       injected into
                                                       another well.
New wells with Associated Gas     Route associated    Route associated
 that commenced construction       gas to a sales      gas to a sales
 between May 7, 2024, and May 7,   line.               line; or, the gas
 2026.                                                 can be used for
                                                       another useful
                                                       purpose that a
                                                       purchased fuel,
                                                       chemical
                                                       feedstock, or raw
                                                       material would
                                                       serve, or
                                                       recovered from
                                                       the separator and
                                                       reinjected into
                                                       the well or
                                                       injected into
                                                       another well. If
                                                       demonstrated, and
                                                       documented
                                                       annually, that
                                                       routing to a
                                                       sales line and
                                                       the alternatives
                                                       are not
                                                       technically
                                                       feasible, the
                                                       associated gas
                                                       can be routed to
                                                       a flare or other
                                                       control device
                                                       that achieves at
                                                       least 95 percent
                                                       reduction in GHG
                                                       (methane) and VOC
                                                       emissions. A
                                                       second
                                                       infeasibility
                                                       determination may
                                                       not extend beyond
                                                       24 months from
                                                       effective date.
New Wells with Associated Gas     Route associated    Route associated
 that Commenced Construction       gas to a sales      gas to a sales
 after December 6, 2022, and       line.               line; or, the gas
 before May 7, 2024.                                   can be used for
                                                       another useful
                                                       purpose that a
                                                       purchased fuel,
                                                       chemical
                                                       feedstock, or raw
                                                       material would
                                                       serve, or
                                                       recovered from
                                                       the separator and
                                                       reinjected into
                                                       the well or
                                                       injected into
                                                       another well. If
                                                       demonstrated, and
                                                       documented
                                                       annually, that
                                                       routing to a
                                                       sales line and
                                                       the alternatives
                                                       are not
                                                       technically
                                                       feasible, the
                                                       associated gas
                                                       can be routed to
                                                       a flare or other
                                                       control device
                                                       that achieves at
                                                       least 95 percent
                                                       reduction in GHG
                                                       (methane) and VOC
                                                       emissions.

[[Page 16833]]

 
Wells with Associated Gas         Route associated    Route associated
 Reconstructed or Modified after   gas to a sales      gas to a sales
 December 6, 2022.                 line.               line; or, the gas
                                                       can be used for
                                                       another useful
                                                       purpose that a
                                                       purchased fuel,
                                                       chemical
                                                       feedstock, or raw
                                                       material would
                                                       serve, or
                                                       recovered from
                                                       the separator and
                                                       reinjected into
                                                       the well or
                                                       injected into
                                                       another well. If
                                                       demonstrated, and
                                                       documented
                                                       annually, that
                                                       routing to a
                                                       sales line and
                                                       the alternatives
                                                       are not
                                                       technically
                                                       feasible, the
                                                       associated gas
                                                       can be routed to
                                                       a flare or other
                                                       control device
                                                       that achieves at
                                                       least 95 percent
                                                       reduction in GHG
                                                       (methane) and VOC
                                                       emissions.
Sweetening Units................  Achieve SO2         Achieve required
                                   emission            minimum SO2
                                   reduction           emission
                                   efficiency.         reduction
                                                       efficiency.
------------------------------------------------------------------------
\1\ tpy (tons per year).
\2\ OGI (optical gas imaging).
\3\ ppm (parts per million).
\4\ PTE (potential to emit).
\5\ scfh (standard cubic feet per hour).
\6\ BMP (best management practices).
\7\ scfm (standard cubic feet per minute).
\8\ REC (reduced emissions completion).
\9\ LDAR (leak detection and repair).

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

    \22\ For fugitive emissions at well sites,centralized production 
facilities, and compressor stations, the EPA is finalizing an 
advanced measurement technology compliance option to use alternative 
periodic screening and alternative continuous monitoring instead of 
OGI and AVO monitoring.

 Table 4--Summary of Final BSER and Final Presumptive Standards for GHGs
               From Designated Facilities (EG OOOOc) \23\
------------------------------------------------------------------------
                                                       Final presumptive
       Designated facility            Final BSER      standards for GHGs
------------------------------------------------------------------------
Fugitive Emissions: Single        Quarterly AVO       Quarterly AVO
 Wellhead Only Well Sites and      monitoring          surveys. First
 Small Well Sites.                 surveys.            attempt at repair
                                                       within 15 days
                                                       after detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 15
                                                       days after 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: Multi-        Quarterly AVO       Quarterly AVO
 wellhead Only Well Sites (2 or    monitoring          surveys. First
 more wellheads).                  surveys.            attempt at repair
                                                       within 15 days
                                                       after detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 15
                                                       days after first
                                                       attempt.
                                  AND                 Semiannual OGI
                                                       monitoring
                                                       (Optional semi-
                                  Monitoring and       annual EPA Method
                                   repair based on     21 monitoring
                                   semiannual          with 500 ppm
                                   monitoring using    defined as a
                                   OGI\2\.             leak).
                                                      First attempt at
                                                       repair within 30
                                                       days after
                                                       detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after 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    Bimonthly AVO       Bimonthly AVO
 and Centralized Production        monitoring          surveys. First
 Facilities.                       surveys (i.e.,      attempt at repair
                                   every other         within 15 days
                                   month).             after detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 15
                                                       days after first
                                                       attempt.
                                  AND                 AND
                                  Monitoring and      Well sites with
                                   repair based on     specified major
                                   quarterly           production and
                                   monitoring using    processing
                                   OGI.                equipment:
                                                       Quarterly OGI
                                                       monitoring.
                                                       (Optional
                                                       quarterly EPA
                                                       Method 21
                                                       monitoring with
                                                       500 ppm defined
                                                       as a leak).

[[Page 16834]]

 
                                                      First attempt at
                                                       repair within 30
                                                       days after
                                                       finding fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after 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         Monthly AVO
 Stations.                         monitoring          surveys. First
                                   surveys.            attempt at repair
                                                       within 15 days
                                                       after detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 15
                                                       days after first
                                                       attempt.
                                  AND                 AND
                                  Monitoring and      Quarterly OGI
                                   repair based on     monitoring.
                                   quarterly           (Optional
                                   monitoring using    quarterly EPA
                                   OGI.                Method 21
                                                       monitoring with
                                                       500 ppm defined
                                                       as a leak).
                                                      First attempt at
                                                       repair within 30
                                                       days after
                                                       detecting
                                                       fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after first
                                                       attempt.
Fugitive Emissions: Well Sites    Monitoring and      Annual OGI
 and Compressor Stations on        repair based on     monitoring.
 Alaska North Slope.               annual monitoring   (Optional annual
                                   using OGI.          EPA Method 21
                                                       monitoring with
                                                       500 ppm defined
                                                       as a leak).
                                                      First attempt at
                                                       repair within 30
                                                       days after
                                                       finding fugitive
                                                       emissions. Final
                                                       repair within 30
                                                       days after first
                                                       attempt.
Storage Vessels: Tank Battery     Capture and route   95 percent
 with PTE of 20 tpy or More of     to a control        reduction of
 Methane.                          device.             methane.
Process Controllers: Natural gas- Use of zero-        GHG (methane)
 driven.                           emissions           emission rate of
                                   controllers.        zero.
Process Controllers: Alaska (at   Use of low-bleed    Natural gas bleed
 sites where onsite power is not   process             rate no greater
 available--continuous bleed       controllers.        than 6 scfh.
 natural gas-driven).
Process Controllers: Alaska (at   Monitor and repair  OGI monitoring and
 sites where onsite power is not   through fugitive    repair of
 available--intermittent natural   emissions program.  emissions from
 gas-driven).                                          controller
                                                       malfunctions.
Gas Well Liquids Unloading......  Best management     Perform best
                                   practices to        management
                                   minimize or         practices to
                                   eliminate methane   minimize or
                                   and VOC emissions   eliminate methane
                                   to the maximum      and VOC emissions
                                   extent possible.    to the maximum
                                                       extent possible
                                                       from liquids
                                                       unloading events
                                                       that vent
                                                       emissions to the
                                                       atmosphere.
Wet Seal Centrifugal Compressors  Monitoring and      Monitoring and
 (except for those located at      repair to           repair to
 well sites).                      maintain            maintain
                                   volumetric flow     volumetric flow
                                   rate at or below    rate at or below
                                   3 scfm\7\.          3 scfm per seal.
Wet Seal Centrifugal Compressors  Monitoring and      Monitoring and
 (except for those located at      repair to           repair to
 well sites): Self-contained       maintain            maintain
 centrifugal compressors and wet   volumetric flow     volumetric flow
 seal compressors equipped with    rate at or below    rate at or below
 a mechanical seal.                3 scfm.             3 scfm per seal.
Wet Seal Centrifugal Compressors  Monitoring and      Monitoring and
 (except for those located at      repair to           repair to
 well sites): Alaska North Slope   maintain            maintain
 centrifugal compressors           volumetric flow     volumetric flow
 equipped with a seal oil          rate at or below    rate at or below
 recovery system.                  9 scfm.             9 scfm per seal.
Dry Seal Centrifugal Compressors  Monitoring and      Monitoring and
 (except for those located at      repair to           repair to
 well sites).                      maintain            maintain
                                   volumetric flow     volumetric flow
                                   rate at or below    rate at or below
                                   10 scfm\7\.         10 scfm per seal.
Reciprocating Compressors         Monitoring and      Monitoring and
 (except for those located at      repair or replace   repair to
 well sites).                      the reciprocating   maintain
                                   compressor rod      volumetric flow
                                   packing in order    rate at or below
                                   to maintain         2 scfm per
                                   volumetric flow     cylinder.
                                   rate at or below
                                   2 scfm.
Pumps: Natural gas-driven.......  Use of zero-        GHG (methane)
                                   emissions pumps.    emission rate of
                                                       zero.
Pumps: Natural gas-driven (at     Use of an existing  Route pump
 sites where onsite power is not   VRU or control      emissions to a
 available and there are fewer     device.             process if VRU is
 than 3 diaphragm pumps).                              onsite, or to
                                                       control device if
                                                       onsite.
Equipment Leaks at Natural Gas    LDAR with           LDAR with OGI
 Processing Plants.                bimonthly OGI.      following
                                                       procedures in
                                                       appendix K.

[[Page 16835]]

 
Wells with Associated Gas         Route associated    Route associated
 greater than 40 tpy methane.      gas to a sales      gas to a sales
                                   line.               line.
                                                       Alternatively,
                                                       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, or be
                                                       injected into the
                                                       well or another
                                                       well. If
                                                       demonstrated, and
                                                       annually
                                                       documented, that
                                                       a sales line and
                                                       alternatives 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.
Wells with Associated Gas 40 tpy  Route associated    Route associated
 methane or less.                  gas to a flare or   gas to a sales
                                   other control       line.
                                   device that         Alternatively,
                                   achieves at least   the gas can be
                                   95 percent          used as an onsite
                                   reduction in        fuel source or
                                   methane emissions.  used for another
                                                       useful purpose
                                                       that a purchased
                                                       fuel or raw
                                                       material would
                                                       serve, or be
                                                       injected into the
                                                       well or another
                                                       well.
                                                       Alternatively,
                                                       the gas can be
                                                       routed to a flare
                                                       or other control
                                                       device that
                                                       achieves at least
                                                       95 percent
                                                       reduction in
                                                       methane
                                                       emissions.
------------------------------------------------------------------------

C. Costs and Benefits 
---------------------------------------------------------------------------

    \23\ For fugitive emissions at well sites, centralized 
production facilities, and compressor stations, the EPA is 
finalizing an advanced measurement technology compliance option to 
use alternative periodic screening and alternative continuous 
monitoring instead of OGI and AVO monitoring.
---------------------------------------------------------------------------

    In accordance with the requirements of E.O. 12866, the EPA 
projected the emissions reductions, costs, and benefits that may result 
from this final rulemaking. These results are presented in detail in 
the RIA accompanying this final rulemaking developed in response to 
E.O. 12866. The RIA focuses on the elements of the final rules that are 
likely to result in quantifiable cost or emissions changes compared to 
a baseline without the rule. We estimated the cost, emissions, and 
benefit impacts for the 2024 to 2038 period. We present the present 
value (PV) and equivalent annual value (EAV) of costs, benefits, and 
net benefits of this rulemaking in 2019 dollars.
    The initial analysis year in the RIA is 2024 as we assume the NSPS 
rules will take effect early in 2024. The EG will take longer to go 
into effect as states will need to develop implementation plans in 
response to the EG and have them approved by the EPA. We assume in the 
RIA that this process will take 4 years, and so EG impacts will begin 
in 2028. The final analysis year is 2038, which allows us to provide up 
to 15 years of projected impacts after the NSPS is assumed to take 
effect and 11 years of projected impacts after the EG is assumed to 
take effect.
    The cost analysis presented in the RIA reflects a nationwide 
engineering analysis of compliance cost and emissions reductions, of 
which there are two main components. The first component is a set of 
representative or model plants for each regulated facility, segment, 
and control option. The characteristics of the model plant include 
typical equipment, operating characteristics, and representative 
factors including baseline emissions and the costs, emissions 
reductions, and product recovery resulting from each control option. 
The second component is a set of projections of activity data for 
affected facilities, distinguished by vintage, year, and other 
necessary attributes (e.g., oil versus natural gas wells). Impacts are 
calculated by setting parameters on how and when affected facilities 
are assumed to respond to a particular regulatory regime, multiplying 
activity data by model plant cost and emissions estimates, differencing 
from the baseline scenario, and then summing to the desired level of 
aggregation. In addition to emissions reductions, some control options 
result in natural gas recovery, which can then be combusted in 
production or sold. Where applicable, we present projected compliance 
costs with and without the projected revenues from product recovery.
    The EPA expects climate and health benefits due to the emissions 
reductions projected under this final rulemaking. The EPA estimated the 
monetized climate benefits of methane emission reductions expected from 
these final rules using estimates of the social cost of methane (SC-
CH<INF>4</INF>) that reflect recent advances in the scientific 
literature on climate change and its economic impacts and incorporate 
recommendations made by the National Academies of Science, Engineering, 
and Medicine (National Academies 2017). The EPA presented these 
estimates in a sensitivity analysis in the December 2022 RIA, solicited 
public comment on the methodology and use of these estimates, and has 
conducted an external peer review of these estimates, as discussed in 
section XVI.E of this preamble.
    In addition to climate benefits from methane emissions reductions, 
the EPA expects that VOC emission reductions under the final rulemaking 
will improve air quality and improve health and welfare due to reduced 
exposure to ozone, particulate matter with a diameter of 2.5 
micrometers or less (PM<INF>2.5</INF>), and hazardous air pollutants 
(HAP). In a national-level analysis of public health impacts, the EPA 
used the environmental Benefits Mapping and Analysis Program--Community 
Edition (BenMAP-CE) software program to quantify counts of premature 
deaths and illnesses attributable to photochemical modeled changes in 
summer season average ozone concentrations resulting from projected VOC 
emissions reductions under the rulemaking. The methods for quantifying 
the number and value of air pollution-attributable premature deaths and 
illnesses are described in the RIA for this action and the TSD titled 
Estimating PM<INF>2.5</INF>- and Ozone-Attributable Health 
Benefits.\24\ These reductions in health-harming pollution would result 
in significant public health benefits including avoided

[[Page 16836]]

premature deaths, reductions in new asthma cases and incidences of 
asthma symptoms, reductions in hospital admissions and emergency 
department visits, and reductions in lost school days.
---------------------------------------------------------------------------

    \24\ https://www.epa.gov/system/files/documents/2023-01/Estimating%20PM2.5-%20and%20Ozone-Attributable%20Health%20Benefits%20TSD_0.pdf.
---------------------------------------------------------------------------

    The EPA notes that the benefits analysis is distinct from the 
statutory BSER determinations finalized herein, which are based on the 
statutory factors the EPA is required to consider under section 111(a) 
of the CAA (including cost, energy requirements and nonair quality 
health, and environmental impacts). The assessment of benefits 
described above and in the RIA is presented solely for the purposes of 
complying with E.O. 12866 and providing the public with a complete 
depiction of the impacts of the rulemaking.
    The projected national-level emissions reductions over the 2024 to 
2038 period anticipated under the finalized requirements are presented 
in table 5. Table 6 presents the PV and EAV of the projected benefits, 
costs, and net benefits over the 2024 to 2038 period under the final 
rule using discount rates of 2, 3, and 7 percent.

Table 5--Projected Emissions Reductions Under the Final Rules, 2024-2038
                                  Total
------------------------------------------------------------------------
                                                    Emissions reductions
                     Pollutant                        (2024-2038 total)
------------------------------------------------------------------------
Methane (million short tons) \a\..................                    58
VOC (million short tons)..........................                    16
Hazardous Air Pollutant (million short tons)......                  0.59
Methane (million metric tons CO2 Eq.) \b\.........                 1,500
------------------------------------------------------------------------
\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 28.


                            Table 6--Benefits, Costs, Net Benefits, and Emissions Reductions Under the Final Rules, 2024-2038
                                                   [Dollar Estimates in Millions of 2019 Dollars] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     2 Percent near-term Ramsey discount rate
                                                         -----------------------------------------------------------------------------------------------
                                                                PV              EAV             PV              EAV             PV              EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Climate Benefits \b\....................................        $110,000          $8,500        $110,000          $8,500        $110,000          $8,500
--------------------------------------------------------------------------------------------------------------------------------------------------------


 
                                                              2 Percent discount rate        3 Percent  discount rate        7 Percent  discount rate
                                                         -----------------------------------------------------------------------------------------------
                                                                PV              EAV             PV              EAV             PV              EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Ozone Health Benefits \c\...............................          $7,000            $540          $6,100            $510          $3,500            $380
Net Compliance Costs....................................          19,000           1,500          18,000           1,500          14,000           1,600
Compliance Costs........................................          31,000           2,400          29,000           2,400          22,000           2,400
Value of Product Recovery...............................          13,000             980          11,000             950           7,400             820
Net Benefits \d\........................................          97,000           7,600          97,000           7,500          98,000           7,300
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits..................................  Climate and ozone-related health benefits from reducing 58 million short tons of methane from
                                                          2024 to 2038.
                                                          Benefits to provision of ecosystem services associated with reduced ozone concentrations from
                                                          reducing 16 million short tons of VOC from 2024 to 2038.
                                                          PM2.5-related health benefits from reducing 16 million short tons of VOC from 2024 to 2038.
                                                          HAP benefits from reducing 590 thousand short tons of HAP from 2024 to 2038.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\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 three different estimates of the SC-CH4 (under 1.5 percent,
  2.0 percent, and 2.5 percent near-term Ramsey discount rates). For the presentational purposes of this table, we show the climate benefits associated
  with the SC-CH4 at the 2 percent near-term Ramsey discount rate. Please see tables 3.4 and 3.5 in the RIA for the full range of monetized climate
  benefit estimates. All net benefits are calculated using climate benefits discounted at the 2 percent near-term rate.
\c\ Monetized benefits include those related to public health associated with reductions in ozone concentrations. The health benefits are associated
  with several point estimates.
\d\ Several categories of climate, human health, and welfare benefits from methane, VOC, and HAP emissions reductions remain unmonetized and are thus
  not directly reflected in the quantified benefit estimates in the table.

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

A. Impacts of GHGs, VOCs, and SO<INF>2</INF> Emissions on Public Health 
and Welfare

    As noted previously, the oil and natural gas industry emits a wide 
range of pollutants, including GHGs (such as methane and 
CO<INF>2</INF>), VOCs, SO<INF>2</INF>, NO<INF>X</INF>, H<INF>2</INF>S, 
CS<INF>2</INF>, and COS. See 49 FR 2636, 2637 (January 20, 1984). As 
noted below, to this point the EPA has focused its regulatory efforts 
under CAA section 111 on GHGs, VOC, and SO<INF>2</INF>.\25\
---------------------------------------------------------------------------

    \25\ We note that the EPA's focus on GHGs (in particular 
methane), VOC, and SO<INF>2</INF> in these analyses does not in any 
way limit the EPA's authority to promulgate standards that would 
apply to other pollutants emitted from the Crude Oil and Natural Gas 
source category, if the EPA determines in the future that such 
action is appropriate.
---------------------------------------------------------------------------

1. Climate Change Impacts From GHGs Emissions
    Elevated concentrations of GHGs are and have been warming the 
planet, leading to changes in the Earth's climate including changes in 
the frequency and intensity of heat waves, precipitation, and extreme 
weather events; rising seas; and retreating snow and ice. The changes 
taking place in the atmosphere as a result of the well-documented

[[Page 16837]]

buildup of GHGs due to human activities are changing the climate at a 
pace and in a way that threatens human health, society, and the natural 
environment. Human-produced GHGs, largely derived from our reliance on 
fossil fuels, are causing serious and life-threatening environmental 
and health impacts. While the EPA is not making any new scientific or 
factual findings with regard to the well-documented impact of GHG 
emissions on public health and welfare in support of this rulemaking, 
the EPA is providing some scientific background on climate change to 
offer additional context for this rulemaking and to increase the 
public's understanding of the environmental impacts of GHGs.
    Extensive additional information on climate change is available in 
the scientific assessments and the EPA documents that are briefly 
described in this section of this preamble, as well as in the technical 
and scientific information supporting them. One of those documents is 
the EPA's 2009 Endangerment and Cause or Contribute Findings for GHGs 
Under Section 202(a) of the CAA (74 FR 66496, December 15, 2009).\26\ 
In the 2009 Endangerment Findings, the Administrator found under 
section 202(a) of the CAA that elevated atmospheric concentrations of 
six key well-mixed GHGs--CO<INF>2,</INF> methane, N<INF>2</INF>O, HFCs, 
perfluorocarbons (PFCs), and sulfur hexafluoride (SF<INF>6</INF>)--
``may reasonably be anticipated to endanger the public health and 
welfare of current and future generations'' (74 FR 66523, December 15, 
2009), and the science and observed changes since that time have 
confirmed and strengthened the understanding and concerns regarding the 
climate risks considered in the Findings. The 2009 Endangerment 
Findings, together with the extensive scientific and technical evidence 
in the supporting record, documented that climate change caused by 
human emissions of GHGs threatens the public health of the U.S. 
population. It explained that by raising average temperatures, climate 
change increases the likelihood of heat waves, which are associated 
with increased deaths and illnesses (74 FR 66497, December 15, 2009). 
While climate change also increases the likelihood of reductions in 
cold-related mortality, evidence indicates that the increases in heat 
mortality will be larger than the decreases in cold mortality in the 
U.S. (74 FR 66525, December 15, 2009). The 2009 Endangerment Findings 
further explained that compared to a future without climate change, 
climate change is expected to increase tropospheric ozone pollution 
over broad areas of the U.S., including in the largest metropolitan 
areas with the worst tropospheric ozone problems, and thereby increase 
the risk of adverse effects on public health (74 FR 66525, December 15, 
2009). Climate change is also expected to cause more intense 
hurricanes, and more frequent and intense storms of other types, and 
heavy precipitation, with impacts on other areas of public health such 
as the potential for increased deaths, injuries, infectious and 
waterborne diseases, and stress-related disorders (74 FR 66525, 
December 15, 2009). Children, the elderly, and the poor are among the 
most vulnerable to these climate-related health effects (74 FR 66498, 
December 15, 2009).
---------------------------------------------------------------------------

    \26\ In describing these 2009 Findings in this proposal, the EPA 
is neither reopening nor revisiting them.
---------------------------------------------------------------------------

    The 2009 Endangerment Findings also documented, together with the 
extensive scientific and technical evidence in the supporting record, 
that climate change touches nearly every aspect of public welfare \27\ 
in the U.S. with resulting economic costs, including: changes in water 
supply and quality due to increased frequency of drought and extreme 
rainfall events; increased risk of storm surge and flooding in coastal 
areas and land loss due to inundation; increases in peak electricity 
demand and risks to electricity infrastructure; and the potential for 
significant agricultural disruptions and crop failures (though offset 
to some extent by carbon fertilization). These impacts are also global 
and may exacerbate problems outside the U.S. that raise humanitarian, 
trade, and national security issues for the U.S. (74 FR 66530, December 
15, 2009).
---------------------------------------------------------------------------

    \27\ The CAA states in section 302(h) that ``[a]ll language 
referring to effects on welfare includes, but is not limited to, 
effects on soils, water, crops, vegetation, manmade materials, 
animals, wildlife, weather, visibility, and climate, damage to and 
deterioration of property, and hazards to transportation, as well as 
effects on economic values and on personal comfort and well-being, 
whether caused by transformation, conversion, or combination with 
other air pollutants.'' 42 U.S.C. 7602(h).
---------------------------------------------------------------------------

    In 2016, the Administrator similarly issued Endangerment and Cause 
or Contribute Findings for GHG emissions from aircraft under section 
231(a)(2)(A) of the CAA (81 FR 54422, August 15, 2016).\28\ In the 2016 
Endangerment Findings, the Administrator found that the body of 
scientific evidence amassed in the record for the 2009 Endangerment 
Findings compellingly supported a similar endangerment finding under 
CAA section 231(a)(2)(A) and also found that the science assessments 
released between the 2009 and the 2016 Findings ``strengthen and 
further support the judgment that GHGs in the atmosphere may reasonably 
be anticipated to endanger the public health and welfare of current and 
future generations.'' (81 FR 54424, August 15, 2016).
---------------------------------------------------------------------------

    \28\ In describing these 2016 Findings in this proposal, the EPA 
is neither reopening nor revisiting them.
---------------------------------------------------------------------------

    Since the 2016 Endangerment Findings, the climate has continued to 
change, with new records being set for several climate indicators such 
as global average surface temperatures, GHG concentrations, and sea 
level rise. Moreover, heavy precipitation events have increased in the 
eastern U.S. while agricultural and ecological drought has increased in 
the western U.S. along with more intense and larger wildfires.\29\ 
These and other trends are examples of the risks discussed the 2009 and 
2016 Endangerment Findings that have already been experienced. 
Additionally, major scientific assessments continue to demonstrate 
advances in our understanding of the climate system and the impacts 
that GHGs have on public health and welfare both for current and future 
generations. These updated observations and projections document the 
rapid rate of current and future climate change both globally and in 
the U.S. These assessments include:
---------------------------------------------------------------------------

    \29\ See later in this section of the document for specific 
examples. An additional resource for indicators can be found at 
https://www.epa.gov/climate-indicators.

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

[[Page 16838]]

    <bullet> U.S. Global Change Research Program's (USGCRP) 2016 
Climate and Health Assessment \30\ and 2017-2018 Fourth National 
Climate Assessment (NCA4) <SUP>31 32</SUP>
---------------------------------------------------------------------------

    \30\ 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.
    \31\ USGCRP, 2017: Climate Science Special Report: Fourth 
National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey, 
K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. 
U.S. Global Change Research Program, Washington, DC, USA, 470 pp, 
doi: 10.7930/J0J964J6.
    \32\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
---------------------------------------------------------------------------

    <bullet> IPCC's 2018 Global Warming of 1.5 [deg]C,\33\ 2019 Climate 
Change and Land,\34\ and the 2019 Ocean and Cryosphere in a Changing 
Climate \35\ assessments, as well as the 2023 IPCC Sixth Assessment 
Report (AR6).\36\
---------------------------------------------------------------------------

    \33\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special 
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission 
pathways, in the context of strengthening the global response to the 
threat of climate change, sustainable development, and efforts to 
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner, 
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. 
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. 
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. 
Waterfield (eds.)].
    \34\ IPCC, 2019: Climate Change and Land: an IPCC special report 
on climate change, desertification, land degradation, sustainable 
land management, food security, and greenhouse gas fluxes in 
terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. 
Masson-Delmotte, H.-O. P[ouml]rtner, D. C. Roberts, P. Zhai, R. 
Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. 
Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. 
Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)].
    \35\ IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere 
in a Changing Climate [H.-O. P[ouml]rtner, DC Roberts, V. Masson-
Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A. 
Alegr[iacute]a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer 
(eds.)].
    \36\ IPCC, 2023: Summary for Policymakers. In: Climate Change 
2023: Synthesis Report. Contribution of Working Groups I, II and III 
to the Sixth Assessment Report of the Intergovernmental Panel on 
Climate Change [Core Writing Team, H. Lee and J. Romero (eds.)]. 
IPCC, Geneva, Switzerland, pp. 1-34, doi:10.59327/IPCC/AR6-
9789291691647.001.
---------------------------------------------------------------------------

    <bullet> The NAS 2016 Attribution of Extreme Weather Events in the 
Context of Climate Change,\37\ 2017 Valuing Climate Damages: Updating 
Estimation of the Social Cost of Carbon Dioxide,\38\ and 2019 Climate 
Change and Ecosystems \39\ assessments.
---------------------------------------------------------------------------

    \37\ National Academies of Sciences, Engineering, and Medicine. 
2016. Attribution of Extreme Weather Events in the Context of 
Climate Change. Washington, DC: The National Academies Press. 
https://dio.org/10.17226/21852.
    \38\ National Academies of Sciences, Engineering, and Medicine. 
2017. Valuing Climate Damages: Updating Estimation of the Social 
Cost of Carbon Dioxide. Washington, DC: The National Academies 
Press. https://doi.org/10.17226/24651.
    \39\ National Academies of Sciences, Engineering, and Medicine. 
2019. Climate Change and Ecosystems. Washington, DC: The National 
Academies Press. https://doi.org/10.17226/25504.
---------------------------------------------------------------------------

    <bullet> National Oceanic and Atmospheric Administration's (NOAA) 
annual State of the Climate reports published by the Bulletin of the 
American Meteorological Society,\40\ most recently in 2022.
---------------------------------------------------------------------------

    \40\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the 
Climate in 2021''. Bull. Amer. Meteor. Soc., 103 (8), Si-S465, 
https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
---------------------------------------------------------------------------

    <bullet> EPA Climate Change and Social Vulnerability in the United 
States: A Focus on Six Impacts (2021).\41\
---------------------------------------------------------------------------

    \41\ EPA. 2021. Climate Change and Social Vulnerability in the 
United States: A Focus on Six Impacts. U.S. Environmental Protection 
Agency, EPA 430-R-21-003.
---------------------------------------------------------------------------

    The most recent information demonstrates that the climate is 
continuing to change in response to the human-induced buildup of GHGs 
in the atmosphere. These recent assessments show that atmospheric 
concentrations of GHGs have risen to a level that has no precedent in 
human history and that they continue to climb, primarily because of 
both historical and current anthropogenic emissions, and that these 
elevated concentrations endanger our health by affecting our food and 
water sources, the air we breathe, the weather we experience, and our 
interactions with the natural and built environments. For example, 
atmospheric concentrations of one of these GHGs, CO<INF>2</INF>, 
measured at Mauna Loa in Hawaii and at other sites around the world 
reached 419 parts per million (ppm) in 2022 (nearly 50 percent higher 
than preindustrial levels) \42\ and have continued to rise at a rapid 
rate. Global average temperature has increased by about 1.1 [deg]C (2.0 
[deg]F) in the 2011-2020 decade relative to 1850-1900.\43\ The years 
2015-2021 were the warmest 7 years in the 1880-2021 record, 
contributing to the warmest decade on record with a decadal temperature 
of 0.82 [deg]C (1.48 [deg]F) above the 20th century.<SUP>44 45</SUP> 
The IPCC determined (with medium confidence) that this past decade was 
warmer than any multi-century period in at least the past 100,000 
years.\46\ Global average sea level has risen by about 8 inches (about 
21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 
(0.15 inches/year or 3.7 millimeters (mm)/year) almost twice the rate 
over the 1971 to 2006 period, and three times the rate of the 1901 to 
2018 period.\47\ The rate of sea level rise over the 20th century was 
higher than in any other century in at least the last 2,800 years.\48\ 
Higher CO<INF>2</INF> concentrations have led to acidification of the 
surface ocean in recent decades to an extent unusual in the past 2 
million years, with negative impacts on marine organisms that use 
calcium carbonate to build shells or skeletons.\49\ Arctic sea ice 
extent continues to decline in all months of the year; the most rapid 
reductions occur in September (very likely almost a 13 percent decrease 
per decade between 1979 and 2018) and are unprecedented in at least 
1,000 years.\50\ Human-induced climate change has led to heatwaves and 
heavy precipitation becoming more frequent and more intense, along with 
increases in agricultural and ecological droughts \51\ in many 
regions.\52\
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    \42\ https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt.
    \43\ IPCC, 2021: Summary for Policymakers. In: Climate Change 
2021: The Physical Science Basis. Contribution of Working Group I to 
the Sixth Assessment Report of the Intergovernmental Panel on 
Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. 
Connors, C. P[eacute]an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, 
M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. 
Maycock, T. Waterfield, O. Yelek[ccedil]i, R. Yu, and B. Zhou 
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and 
New York, NY, USA, pp. 3-32, doi:10.1017/9781009157896.001.
    \44\ NOAA National Centers for Environmental Information, State 
of the Climate 2021 retrieved on August 3, 2023, from https://www.ncei.noaa.gov/bams-state-of-climate.
    \45\ Blunden, et al. 2022.
    \46\ IPCC, 2021.
    \47\ IPCC, 2021.
    \48\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
    \49\ IPCC, 2021.
    \27\ IPCC, 2021.
    \51\ These are drought measures based on soil moisture.
    \52\ IPCC, 2021.
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    The assessment literature demonstrates that modest additional 
amounts of warming may lead to a climate different from anything humans 
have ever experienced. The 2022 CO<INF>2</INF> concentration of 419 ppm 
is already higher than at any time in the last 2 million years.\53\ If 
concentrations exceed 450 ppm, they would likely be higher than any 
time in the past 23 million years: \54\ at the current rate of increase 
of more than 2 ppm a year, this would

[[Page 16839]]

occur in about 15 years. While GHGs are not the only factor that 
controls climate, it is illustrative that 3 million years ago (the last 
time CO<INF>2</INF> concentrations were above 400 ppm) Greenland was 
not yet completely covered by ice and still supported forests, while 23 
million years ago (the last time concentrations were above 450 ppm) the 
West Antarctic ice sheet was not yet developed, indicating the 
possibility that high GHG concentrations could lead to a world that 
looks very different from today and from the conditions in which human 
civilization has developed. If the Greenland and Antarctic ice sheets 
were to melt substantially, sea levels would rise dramatically--the 
IPCC estimated that over the next 2,000 years, sea level will rise by 7 
to 10 feet even if warming is limited to 1.5 [deg]C (2.7 [deg]F), from 
7 to 20 feet if limited to 2 [deg]C (3.6 [deg]F), and by 60 to 70 feet 
if warming is allowed to reach 5 [deg]C (9 [deg]F) above preindustrial 
levels.\55\ For context, almost all of the city of Miami is less than 
25 feet above sea level, and the NCA4 stated that 13 million Americans 
would be at risk of migration due to 6 feet of sea level rise. 
Moreover, the CO<INF>2</INF> being absorbed by the ocean has resulted 
in changes in ocean chemistry due to acidification of a magnitude not 
seen in 65 million years,\56\ putting many marine species--particularly 
calcifying species--at risk.
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    \53\ Annual Mauna Loa CO<INF>2</INF> concentration data from 
https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt, 
accessed September 9, 2023.
    \54\ IPCC, 2013.
    \55\ IPCC, 2021.
    \56\ IPCC, 2018.
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    The NCA4 found that it is very likely (greater than 90 percent 
likelihood) that by mid-century, the Arctic Ocean will be almost 
entirely free of sea ice by late summer for the first time in about 2 
million years.\57\ Coral reefs will be at risk for almost complete (99 
percent) losses with 1 [deg]C (1.8 [deg]F) of additional warming from 
today (2 [deg]C or 3.6 [deg]F since preindustrial). At this 
temperature, between 8 and 18 percent of animal, plant, and insect 
species could lose over half of the geographic area with suitable 
climate for their survival, and 7 to 10 percent of rangeland livestock 
would be projected to be lost.\58\ The IPCC similarly found that 
climate change has caused substantial damages and increasingly 
irreversible losses in terrestrial, freshwater, and coastal and open 
ocean marine ecosystems.
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    \57\ USGCRP, 2018.
    \58\ IPCC, 2018.
---------------------------------------------------------------------------

    Scientific assessments also demonstrate that even modest additional 
amounts of warming may lead to a climate different from anything humans 
have ever experienced. Every additional increment of temperature comes 
with consequences. For example, the half degree of warming from 1.5 to 
2 [deg]C (0.9 [deg]F of warming from 2.7 [deg]F to 3.6 [deg]F) above 
preindustrial temperatures is projected on a global scale to expose 420 
million more people to frequent extreme heatwaves, and 62 million more 
people to frequent exceptional heatwaves (where heatwaves are defined 
based on a heat wave magnitude index which takes into account duration 
and intensity--using this index, the 2003 French heat wave that led to 
almost 15,000 deaths would be classified as an ``extreme heatwave'' and 
the 2010 Russian heatwave which led to thousands of deaths and 
extensive wildfires would be classified as ``exceptional''). It would 
increase the frequency of sea-ice-free Arctic summers from once in 100 
years to once in a decade. It could lead to 4 inches of additional sea 
level rise by the end of the century, exposing an additional 10 million 
people to risks of inundation as well as increasing the probability of 
triggering instabilities in either the Greenland or Antarctic ice 
sheets. Between half a million and a million additional square miles of 
permafrost would thaw over several centuries. Risks to food security 
would increase from medium-to-high for several lower-income regions in 
the Sahel, southern Africa, the Mediterranean, central Europe, and the 
Amazon. In addition to food security issues, this temperature increase 
would have implications for human health in terms of increasing ozone 
concentrations, heatwaves, and vector-borne diseases (for example, 
expanding the range of the mosquitoes which carry dengue fever, 
chikungunya, yellow fever, and the Zika virus, or the ticks which carry 
Lyme, babesiosis, or Rocky Mountain Spotted Fever).\59\ Moreover, every 
additional increment in warming leads to larger changes in extremes, 
including the potential for events unprecedented in the observational 
record. Every additional degree will intensify extreme precipitation 
events by about 7 percent. The peak winds of the most intense tropical 
cyclones (hurricanes) are projected to increase with warming. In 
addition to a higher intensity, the IPCC found that precipitation and 
frequency of rapid intensification of these storms has already 
increased, the movement speed has decreased, and elevated sea levels 
have increased coastal flooding, all of which make these tropical 
cyclones more damaging.\60\
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    \59\ IPCC, 2018.
    \60\ IPCC, 2021.
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    The NCA4 also evaluated a number of impacts specific to the U.S. 
Severe drought and outbreaks of insects like the mountain pine beetle 
have killed hundreds of millions of trees in the western U.S. Wildfires 
have burned more than 3.7 million acres in 14 of the 17 years between 
2000 and 2016, and Federal wildfire suppression costs were about a 
billion dollars annually.\61\ The National Interagency Fire Center has 
documented U.S. wildfires since 1983, and the 10 years with the largest 
acreage burned have all occurred since 2004.\62\ Wildfire smoke 
degrades air quality, increasing health risks, and more frequent and 
severe wildfires due to climate change would further diminish air 
quality, increase incidences of respiratory illness, impair visibility, 
and disrupt outdoor activities, sometimes thousands of miles from the 
location of the fire. Meanwhile, sea level rise has amplified coastal 
flooding and erosion impacts, requiring the installation of costly pump 
stations, flooding streets, and increasing storm surge damages. Tens of 
billions of dollars of U.S. real estate could be below sea level by 
2050 under some scenarios. Increased frequency and duration of drought 
will reduce agricultural productivity in some regions, accelerate 
depletion of water supplies for irrigation, and expand the distribution 
and incidence of pests and diseases for crops and livestock. The NCA4 
also recognized that climate change can increase risks to national 
security, both through direct impacts on military infrastructure and by 
affecting factors such as food and water availability that can 
exacerbate conflict outside U.S. borders. Droughts, floods, storm 
surges, wildfires, and other extreme events stress nations and people 
through loss of life, displacement of populations, and impacts on 
livelihoods.\63\
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    \61\ USGCRP, 2018.
    \62\ NIFC (National Interagency Fire Center). 2021. Total 
wildland fires and acres (1983-2020). Accessed August 2021. 
www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html.
    \63\ USGCRP, 2018.

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[[Page 16840]]

    Ongoing EPA modeling efforts can shed further light on the 
distribution of climate change damages expected to occur within the 
U.S. Based on methods from over 30 peer-reviewed climate change impact 
studies, the EPA's Framework for Evaluating Damages and Impacts (FrEDI) 
model has developed estimates of the relationship between future 
temperature changes and physical and economic climate-driven damages 
occurring in specific U.S. regions for 20 specific impact 
categories.\64\ Recent applications of FrEDI have advanced the 
collective understanding about how future climate change impacts in 
these 20 categories are expected to be substantial and distributed 
unevenly across U.S. regions.\65\ Using this framework, the EPA 
estimates that under a global emission scenario with no additional 
mitigation, relative to a world with no additional warming since the 
baseline period (1986-2005), damages accruing to these impact 
categories in the contiguous U.S. occur mainly through increased deaths 
due to increasing temperatures as well as climate-driven changes in air 
quality, transportation impacts due to coastal flooding resulting from 
sea level rise, increased mortality from wildfire emission exposure and 
response costs for fire suppression, and reduced labor hours worked in 
outdoor settings and buildings without air conditioning. The relative 
damages from long-term climate driven changes in these sectors are also 
projected to vary from region to region. For example, of the impact 
categories examined in FrEDI, the largest source of modeled damages 
differ from region to region, with wildfire impacts in the Northwest, 
air quality impacts on the East Coast and the Southwest, labor 
productivity impacts in the Midwest, transportation impacts from high 
tide flooding in the Southern Plains, and damages to rail 
infrastructure in the Northern Plains. While the FrEDI framework 
currently quantifies damages for 20 impact categories within the 
contiguous U.S., it is important to note that it is still a preliminary 
and partial assessment of climate impacts relevant to U.S. interests in 
a number of ways. For example, the FrEDI framework reflects some 
important health damages from U.S. wildfires (i.e., mortality and 
morbidity impacts from wildfire smoke) and suppression costs, but do 
not yet account for other market and non-market welfare effects of 
wildfires (e.g., property damage, impacts to ecosystem services, 
climate feedback effects from wildfire CO<INF>2</INF> emissions). 
Similarly, FrEDI models several types of damages from SLR (e.g., 
traffic delays due to flooded coastal roadways) but do not reflect 
others, such as the effect of groundwater intrusion, business 
interruptions, debris removal costs, or critical infrastructure loss. 
In addition, FrEDI does not reflect increased damages that occur due to 
climate-mediated effects to ecosystem services, or national security, 
interactions between different sectors impacted by climate change or 
all the ways in which physical impacts of climate change occurring 
abroad have spillover effects in different regions of the U.S. See the 
FrEDI Technical Documentation \66\ for more details.
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    \64\ EPA (2021). Technical Documentation on the Framework for 
Evaluating Damages and Impacts (FrEDI). U.S. Environmental 
Protection Agency, EPA 430-R-21-004, available at https://www.epa.gov/cira/fredi. Documentation has been subject to both a 
public review comment period and an independent expert peer review, 
following EPA peer-review guidelines.
    \65\ (1) Sarofim, M.C., Martinich, J., Neumann, J.E., et al. 
(2021). A temperature binning approach for multi-sector climate 
impact analysis. Climatic Change 165. https://doi.org/10.1007/s10584-021-03048-6, (2) Supplementary Material for the Regulatory 
Impact Analysis for the Supplemental Proposed Rulemaking, 
``Standards of Performance for New, Reconstructed, and Modified 
Sources and Emissions Guidelines for Existing Sources: Oil and 
Natural Gas Sector Climate Review,'' Docket ID No. EPA-HQ-OAR-2021-
0317, September 2022, (3) The Long-Term Strategy of the United 
States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050. 
Published by the U.S. Department of State and the U.S. Executive 
Office of the President, Washington DC. November 2021, (4) Climate 
Risk Exposure: An Assessment of the Federal Government's Financial 
Risks to Climate Change, White Paper, Office of Management and 
Budget, April 2022.
    \66\ EPA (2021). Technical Documentation on the Framework for 
Evaluating Damages and Impacts (FrEDI). U.S. Environmental 
Protection Agency, EPA 430-R-21-004, available at https://www.epa.gov/cira/fredi.
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    Some GHGs also have impacts beyond those mediated through climate 
change. For example, elevated concentrations of CO<INF>2</INF> 
stimulate plant growth (which can be positive in the case of beneficial 
species, but negative in terms of weeds and invasive species, and can 
also lead to a reduction in plant micronutrients \67\) and cause ocean 
acidification. Nitrous oxide depletes the levels of protective 
stratospheric ozone.\68\
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    \67\ Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F. 
Garofalo, A.S. Khan, I. Loladze, A.A. P[eacute]rez de Le[oacute]n, 
A. Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety, 
Nutrition, and Distribution. The Impacts of Climate Change on Human 
Health in the United States: A Scientific Assessment. U.S. Global 
Change Research Program, Washington, DC, 189-216. https://health2016.globalchange.gov/low/ClimateHealth2016_07_Food_small.pdf.
    \68\ WMO (World Meteorological Organization), Scientific 
Assessment of Ozone Depletion: 2018, Global Ozone Research and 
Monitoring Project--Report No. 58, 588 pp., Geneva, Switzerland, 
2018.
---------------------------------------------------------------------------

    As methane is the primary GHG addressed in this rulemaking, it is 
relevant to highlight some trends and impacts specific to methane. 
Concentrations of methane reached 1,912 parts per billion (ppb) in 
2022, more than two and a half times the preindustrial concentration of 
722 ppb.\69\ Moreover, the 2022 concentration was an increase of almost 
17 ppb over 2021--the largest annual increase in methane concentrations 
in the dataset (starting in 1984), continuing a trend of rapid rise 
since a temporary pause ended in 2007.\70\ Methane has a high radiative 
efficiency--almost 30 times that of CO<INF>2</INF> per ppb (and, 
therefore, 80 times as much per unit mass).\71\ In addition, methane 
contributes to climate change through chemical reactions in the 
atmosphere that produce tropospheric ozone and stratospheric water 
vapor. Human emissions of methane are responsible for about one-third 
of the warming due to well-mixed GHGs, the second most important human 
warming agent after CO<INF>2</INF>.\72\ Because of the substantial 
emissions of methane, and its radiative efficiency, methane mitigation 
is one of the best opportunities for reducing near-term warming.
---------------------------------------------------------------------------

    \69\ Blunden, et al., 2022.
    \70\ NOAA, https://gml.noaa.gov/webdata/ccgg/trends/ch4/ch4_annmean_gl.txt, accessed August 3, 2023.
    \71\ IPCC, 2021.
    \72\ IPCC, 2021.
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    The tropospheric ozone produced by the reaction of methane in the 
atmosphere has harmful effects for human health and plant growth in 
addition to its climate effects.\73\ In remote areas, methane is an 
important precursor to tropospheric ozone formation.\74\ Approximately 
50 percent of the global annual mean ozone increase since preindustrial 
times is believed to be due to anthropogenic methane.\75\ Projections 
of future

[[Page 16841]]

emissions also indicate that methane is likely to be a key contributor 
to ozone concentrations in the future.\76\ Unlike NO<INF>X</INF> and 
VOC, which affect ozone concentrations regionally and at hourly time 
scales, methane emissions affect ozone concentrations globally and on 
decadal time scales given methane's long atmospheric lifetime when 
compared to these other ozone precursors.\77\ Reducing methane 
emissions, therefore, will contribute to efforts to reduce global 
background ozone concentrations that contribute to the incidence of 
ozone-related health effects.\78\ The benefits of such reductions are 
global and occur in both urban and rural areas.
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    \73\ Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik, 
R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air 
Quality. In Impacts, Risks, and Adaptation in the United States: 
Fourth National Climate Assessment, Volume II [Reidmiller, D.R., 
C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, pp. 512-538. doi:10.7930/NCA4. 2018. 
CH13.
    \74\ U.S. EPA. 2013. ``Integrated Science Assessment for Ozone 
and Related Photochemical Oxidants (Final Report).'' EPA/600-R-10-
076F. National Center for Environmental Assessment--RTP Division. 
Available at https://www.epa.gov/ncea/isa/.
    \75\ Myhre, G., D. Shindell, F.-M. Br[eacute]on, W. Collins, J. 
Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. Mendoza, 
T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. Zhang, 2013: 
Anthropogenic and Natural Radiative Forcing. In: Climate Change 
2013: The Physical Science Basis. Contribution of Working Group I to 
the Fifth Assessment Report of the Intergovernmental Panel on 
Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, 
S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley 
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and 
New York, NY, USA. Pg. 680.
    \76\ Ibid.
    \77\ Ibid.
    \78\ USGCRP, 2018.
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    These scientific assessments, the EPA analyses, and documented 
observed changes in the climate of the planet and of the U.S. present 
clear support regarding the current and future dangers of climate 
change and the importance of GHG emissions mitigation.
2. VOCs
    Many VOCs can be classified as HAP (e.g., benzene \79\) and can 
lead to a variety of health concerns such as cancer and noncancer 
illnesses (e.g., respiratory, neurological). Further, VOCs are one of 
the key precursors in the formation of ozone. Tropospheric, or ground-
level, ozone is formed through reactions of VOCs and NO<INF>X</INF> in 
the presence of sunlight. Ozone formation can be controlled to some 
extent through reductions in emissions of the ozone precursors VOC and 
NO<INF>X.</INF> Recent observational and modeling studies have found 
that VOC emissions from oil and natural gas operations can impact ozone 
levels.<SUP>80 81 82 83</SUP> A significantly expanded body of 
scientific evidence shows that ozone can cause a number of harmful 
effects on health and the environment. Exposure to ozone can cause 
respiratory system effects such as difficulty breathing and airway 
inflammation. For people with lung diseases such as asthma and chronic 
obstructive pulmonary disease (COPD), these effects can lead to 
emergency room visits and hospital admissions. Studies have also found 
that ozone exposure is likely to cause premature death from lung or 
heart diseases. In addition, evidence indicates that long-term exposure 
to ozone is likely to result in harmful respiratory effects, including 
respiratory symptoms and the development of asthma. People most at risk 
from breathing air containing ozone include: children; people with 
asthma and other respiratory diseases; older adults; and people who are 
active outdoors, especially outdoor workers. An estimated 25.9 million 
people have asthma in the U.S., including almost 7.1 million children. 
Asthma disproportionately affects children, families with lower 
incomes, and minorities, including Puerto Ricans, Native Americans/
Alaska Natives, and African Americans.\84\
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    \79\ Benzene Integrated Risk Information System (IRIS) 
Assessment: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.
    \80\ Benedict, K. B., Zhou, Y., Sive, B. C., Prenni, A. J., 
Gebhart, K. A., Fischer, E. V., . . . & Collett Jr, J. L. 2019. 
Volatile organic compounds and ozone in Rocky Mountain National Park 
during FRAPPE. Atmospheric Chemistry and Physics, 19(1), 499-521.
    \81\ Lindaas, J., Farmer, D. K., Pollack, I. B., Abeleira, A., 
Flocke, F., & Fischer, E. V. 2019. Acyl peroxy nitrates link oil and 
natural gas emissions to high ozone abundances in the Colorado Front 
Range during summer 2015. Journal of Geophysical Research: 
Atmospheres, 124(4), 2336-2350.
    \82\ McDuffie, E. E., Edwards, P. M., Gilman, J. B., Lerner, B. 
M., Dub[eacute], W. P., Trainer, M., . . . & Brown, S. S. 2016. 
Influence of oil and gas emissions on summertime ozone in the 
Colorado Northern Front Range. Journal of Geophysical Research: 
Atmospheres, 121(14), 8712-8729.
    \83\ Tzompa[hyphen]Sosa, Z. A., & Fischer, E. V. 2021. Impacts 
of emissions of C2[hyphen]C5 alkanes from the US oil and gas sector 
on ozone and other secondary species. Journal of Geophysical 
Research: Atmospheres, 126(1), e2019JD031935.
    \84\ National Health Interview Survey (NHIS) Data, 2011. https://www.cdc.gov/asthma/nhis/2011/data.htm.
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    In the EPA's 2020 Integrated Science Assessment (ISA) for Ozone and 
Related Photochemical Oxidants,\85\ the EPA estimated the incidence of 
air pollution effects for those health endpoints above where the ISA 
classified as either causal or likely-to-be-causal. In brief, the ISA 
for ozone found short-term (less than one month) exposures to ozone to 
be causally related to respiratory effects, a ``likely to be causal'' 
relationship with metabolic effects and a ``suggestive of, but not 
sufficient to infer, a causal relationship'' for central nervous system 
effects, cardiovascular effects, and total mortality. The ISA reported 
that long-term exposures (one month or longer) to ozone are ``likely to 
be causal'' for respiratory effects including respiratory mortality, 
and a ``suggestive of, but not sufficient to infer, a causal 
relationship'' for cardiovascular effects, reproductive effects, 
central nervous system effects, metabolic effects, and total mortality. 
An example of quantified incidence of ozone health effects can be found 
in the Regulatory Impact Analysis for the Final Revised Cross-State Air 
Pollution Rule (CSAPR) Update.\86\
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    \85\ Integrated Science Assessment (ISA) for Ozone and Related 
Photochemical Oxidants (Final Report). U.S. Environmental Protection 
Agency, Washington, DC, EPA/600/R-20/012, 2020.
    \86\ U.S. EPA. Technical Support Document (TSD) for the Final 
Revised Cross-State Air Pollution Rule Update for the 2008 Ozone 
Season NAAQS Estimating PM 2.5-and Ozone-Attributable Health 
Benefits. 2021. Research Triangle Park, NC.
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    Scientific evidence also shows that repeated exposure to ozone can 
reduce growth and have other harmful effects on sensitive plants and 
trees. These types of effects have the potential to impact ecosystems 
and the benefits they provide.
3. SO<INF>2</INF>
    Current scientific evidence links short-term exposures to 
SO<INF>2</INF>, ranging from 5 minutes to 24 hours, with an array of 
adverse respiratory effects including bronchoconstriction and increased 
asthma symptoms. These effects are particularly important for 
asthmatics at elevated ventilation rates (e.g., while exercising or 
playing).
    Studies also show an association between short-term exposure and 
increased visits to emergency departments and hospital admissions for 
respiratory illnesses, particularly in at-risk populations including 
children, the elderly, and asthmatics.
    SO<INF>2</INF> in the air can also damage the leaves of plants, 
decrease their ability to produce food (photosynthesis), and decrease 
their growth. In addition to directly affecting plants, SO<INF>2</INF>, 
when deposited on land and in estuaries, lakes, and streams, can 
acidify sensitive ecosystems resulting in a range of harmful indirect 
effects on plants, soils, water quality, and fish and wildlife (e.g., 
changes in biodiversity and loss of habitat, reduced tree growth, loss 
of fish species). Sulfur deposition to waterways also plays a causal 
role in the methylation of mercury.\87\
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    \87\ U.S. EPA. Integrated Science Assessment (ISA) for Oxides of 
Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S. 
Environmental Protection Agency, Washington, DC, EPA/600/R-08/082F, 
2008.
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B. Profile of the Oil and Natural Gas Industry and Its Emissions

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

[[Page 16842]]

1. Structure of the Oil and Natural Gas Industry
    The EPA characterizes the oil and natural gas industry's operations 
as being generally composed of four segments: (1) Extraction and 
production of crude oil and natural gas (``oil and natural gas 
production''), (2) natural gas processing, (3) natural gas transmission 
and storage, and (4) natural gas distribution.<SUP>88 89</SUP> The EPA 
regulates oil refineries as a separate source category; accordingly, as 
with the previous oil and gas NSPS rulemakings, for purposes of this 
rulemaking, the EPA's focus for crude oil is on operations from the 
well to the point of custody transfer at a petroleum refinery while the 
focus for natural gas is on all operations from the well to the local 
distribution company custody transfer station, commonly referred to as 
the ``city-gate.'' \90\
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    \88\ The EPA previously described an overview of the sector in 
section 2.0 of the 2011 Background TSD to 40 CFR part 60, subpart 
OOOO, located at Document ID No. EPA-HQ-OAR-2010-0505-0045, and 
section 2.0 of the 2016 Background TSD to 40 CFR part 60, subpart 
OOOOa, located at Document ID No. EPA-HQ-OAR-2010-0505-7631.
    \89\ While generally oil and natural gas production includes 
both onshore and offshore operations, 40 CFR part 60, subpart OOOOa, 
addresses onshore operations.
    \90\ For regulatory purposes, the EPA defines the Crude Oil and 
Natural Gas source category to mean (1) crude oil production, which 
includes the well and extends to the point of custody transfer to 
the crude oil transmission pipeline or any other forms of 
transportation; and (2) natural gas production, processing, 
transmission, and storage, which include the well and extend to, but 
do not include, the local distribution company custody transfer 
station. The distribution segment is not part of the defined source 
category.
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a. Production Segment
    The oil and natural gas production segment includes the wells and 
all related processes used in the extraction, production, recovery, 
lifting, stabilization, and separation or treatment of oil and/or 
natural gas (including condensate). Although many wells produce a 
combination of oil and natural gas, wells can generally be grouped into 
two categories: oil wells and natural gas wells. Oil wells comprise two 
types, oil wells that produce crude oil only and oil wells that produce 
both crude oil and natural gas (commonly referred to as ``associated'' 
gas). Production equipment and components located on the well pad may 
include, but are not limited to: wells and related casing heads; tubing 
heads; ``Christmas tree'' piping, pumps, and compressors; heater 
treaters; separators; storage vessels; process controllers; pumps; and 
dehydrators. Production operations include well drilling, completion, 
and recompletion processes, including all the portable non-self-
propelled apparatuses associated with those operations.
    Other sites that are part of the production segment include 
``centralized tank batteries,'' stand-alone sites where oil, 
condensate, produced water, and natural gas from several wells may be 
separated, stored, or treated. The production segment also includes 
gathering pipelines, gathering and boosting compressor stations, and 
related components that collect and transport the oil, natural gas, and 
other materials and wastes from the wells to the refineries or natural 
gas processing plants.
    Crude oil and natural gas undergo successive, separate processing. 
Crude oil is separated from water and other impurities and transported 
to a refinery via truck, railcar, or pipeline. As noted above, the EPA 
treats oil refineries as a separate source category; accordingly, for 
present purposes, the oil component of the production segment ends at 
the point of custody transfer at the refinery.\91\
---------------------------------------------------------------------------

    \91\ See 40 CFR part 60, subparts J and Ja, and 40 CFR part 63, 
subparts CC and UUU.
---------------------------------------------------------------------------

    The separated, unprocessed natural gas is commonly referred to as 
field gas and is composed of methane, natural gas liquids (NGL), and 
other impurities such as water vapor, H<INF>2</INF>S, CO<INF>2</INF>, 
helium, and nitrogen. Ethane, propane, butane, isobutane, and pentane 
are all considered NGL and often are sold separately for a variety of 
different uses. Natural gas with high methane content is referred to as 
``dry gas,'' while natural gas with significant amounts of ethane, 
propane, or butane is referred to as ``wet gas.'' Natural gas is 
typically sent to gas processing plants in order to separate NGLs for 
use as feedstock for petrochemical plants, fuel for space heating and 
cooking, or a component for blending into vehicle fuel.
b. Processing Segment
    The natural gas processing segment consists of separating certain 
hydrocarbons (HC) and fluids from the natural gas to produce ``pipeline 
quality'' dry natural gas. The degree and location of processing is 
dependent on factors such as the type of natural gas (e.g., wet or dry 
gas), market conditions, and company contract specifications. 
Typically, processing of natural gas begins in the field and continues 
as the gas is moved from the field through gathering and boosting 
compressor stations to natural gas processing plants, where the 
complete processing of natural gas takes place. Natural gas processing 
operations separate and recover NGL or other non-methane gases and 
liquids from field gas through one or more of the following processes: 
oil and condensate separation, water removal, separation of NGL, sulfur 
and CO<INF>2</INF> removal, fractionation of NGL, and other processes, 
such as the capture of CO<INF>2</INF> separated from natural gas 
streams for delivery outside the facility.
c. Transmission and Storage Segment
    Once natural gas processing is complete, the resulting natural gas 
exits the natural gas process plant and enters the transmission and 
storage segment where it is transmitted to storage and/or distribution 
to the end user.
    Pipelines in the natural gas transmission and storage segment can 
be interstate pipelines, which carry natural gas across state 
boundaries, or intrastate pipelines, which transport the gas within a 
single state. Basic components of the two types of pipelines are the 
same, though interstate pipelines may be of a larger diameter and 
operated at a higher pressure. To ensure that the natural gas continues 
to flow through the pipeline, the natural gas must periodically be 
compressed, thereby increasing its pressure. Compressor stations 
perform this function and are usually placed at 40- to 100-mile 
intervals along the pipeline. At a compressor station, the natural gas 
enters the station, where it is compressed by reciprocating or 
centrifugal compressors.
    Another part of the transmission and storage segment are 
aboveground and underground natural gas storage facilities. Storage 
facilities hold natural gas for use during peak seasons. The main 
difference between underground and aboveground storage sites is that 
storage takes place in storage vessels constructed of non-earthen 
materials in aboveground storage. Underground storage of natural gas 
typically occurs in depleted natural gas or oil reservoirs and salt 
dome caverns. One purpose of this storage is for load balancing 
(equalizing the receipt and delivery of natural gas). At an underground 
storage site, typically other processes occur, including compression, 
dehydration, and flow measurement.
d. Distribution Segment
    The distribution segment provides the final step in delivering 
natural gas to customers.\92\ The natural gas enters the distribution 
segment from delivery points located along interstate and

[[Page 16843]]

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

    \92\ The distribution segment is not included in the definition 
of the Crude Oil and Natural Gas source category in NSPS OOOO, NSPS 
OOOOa, NSPS OOOOb, or EG OOOOc.
---------------------------------------------------------------------------

2. Emissions From the Oil and Natural Gas Source Category
    The oil and natural gas industry sector is the largest source of 
industrial methane emissions in the U.S.\93\ Natural gas is composed 
primarily of methane; every natural gas leak or intentional release 
through venting or other industrial processes constitutes a release of 
methane. Methane is a potent GHG; over a 100-year timeframe, it is 
nearly 30 times more powerful at trapping climate warming heat than 
CO<INF>2</INF>, and over a 20-year timeframe, it is 83 times more 
powerful.\94\ Because methane is a powerful GHG and is emitted in large 
quantities, reductions in methane emissions provide a significant 
benefit in reducing near-term warming. Indeed, one-third of the warming 
due to GHGs that we are experiencing today is due to human-caused 
emissions of methane. Additionally, the Crude Oil and Natural Gas 
sector emits, in varying concentrations and amounts, a wide range of 
other health-harming pollutants, including VOCs, SO<INF>2</INF>, 
NO<INF>X</INF>, H<INF>2</INF>S, CS<INF>2</INF>, and COS. The year 2016 
modeling platform produced by the EPA estimated about 3 million tons of 
VOC are emitted by oil and gas-related sources.\95\
---------------------------------------------------------------------------

    \93\ H.R. Rep. No. 117-64, 4 (2021) (Report by the House 
Committee on Energy and Commerce concerning H.J. Res. 34, to 
disapprove the 2020 Policy Rule) (House Report).
    \94\ IPCC, 2021.
    \95\ https://www.epa.gov/sites/default/files/2020-11/documents/2016v1_emismod_tsd_508.pdf.
---------------------------------------------------------------------------

    Emissions of methane and these co-pollutants occur in every segment 
of the Crude Oil and Natural Gas source category, which comprises the 
oil and natural gas production, natural gas processing, and natural gas 
transmission and storage segments of the larger industry. Many of the 
processes and equipment types that contribute to these emissions are 
found in every segment of the source category and are highly similar 
across segments. Emissions from the crude oil portion of the regulated 
source category result primarily from field production operations, such 
as venting of associated gas from oil wells, oil storage vessels, and 
production-related equipment such as gas dehydrators, pig traps, 
process controllers, and pumps. Emissions from the natural gas portion 
of the industry can occur in all segments. As natural gas moves through 
the system, emissions primarily result from intentional venting through 
normal operations, routine maintenance, unintentional fugitive 
emissions, flaring, malfunctions, and system upsets. Venting can occur 
through equipment design or operational practices, such as the 
continuous bleed and intermittent venting of gas from process 
controllers (devices that control gas flows, levels, temperatures, and 
pressures in the equipment). In addition to vented emissions, emissions 
can occur from leaking equipment (also referred to as fugitive 
emissions) in all parts of the infrastructure, including major 
production and processing equipment (e.g., separators or storage 
vessels) and individual components (e.g., valves or connectors). Flares 
are commonly used throughout each segment in the oil and natural gas 
industry as a control device--to provide pressure relief to prevent 
risk of explosions; to destroy methane, which has a high global warming 
potential, and convert it to CO<INF>2</INF> which has a lower global 
warming potential; and to control other air pollutants such as VOC.
    ``Super-emitting'' events, sites, or equipment, which refer to a 
small proportion of particularly highly emitting sources that account 
for a large proportion of overall emissions, can occur throughout the 
oil and natural gas industry and have been observed in the equipment 
types and activities covered by this final rulemaking. There are a 
number of definitions for the term ``super-emitter.'' A 2018 National 
Academies of Sciences, Engineering, and Medicine report \96\ on methane 
discussed three categories of ``high-emitting'' sources:
---------------------------------------------------------------------------

    \96\ https://www.nap.edu/download/24987#.
---------------------------------------------------------------------------

    <bullet> Routine or ``chronic'' high-emitting sources, which 
regularly emit at higher rates relative to ``peers'' in a sample. 
Examples include large facilities and large emissions at smaller 
facilities caused by poor design or operational practices.
    <bullet> Episodic high-emitting sources, which are typically large 
in nature and are generally intentional releases from known maintenance 
events at a facility. Examples include gas well liquids unloading, well 
workovers and maintenance activities, and compressor station or 
pipeline blowdowns.
    <bullet> Malfunctioning high-emitting sources, which can be either 
intermittent or prolonged in nature and result from malfunctions and 
poor work practices. Examples include malfunctioning intermittent 
process controllers and stuck open dump valves. Another example is well 
blowout events. For example, a 2018 well blowout in Ohio was estimated 
to have emitted over 60,000 tons of methane.\97\
---------------------------------------------------------------------------

    \97\ Pandey, et al. (2019). Satellite observations reveal 
extreme methane leakage from a natural gas well blowout. PNAS 
December 26, 2019. 116 (52) 26376-81.
---------------------------------------------------------------------------

    Super-emitters have been observed at many different scales, from 
site-level to component-level, across many research studies.\98\ 
Studies will often develop a study-specific definition such as a top 
percentile of emissions in a study population (e.g., top 10 percent), 
emissions exceeding a certain threshold (e.g., 26 kg/day), emissions 
over a certain detection threshold (e.g., 1-3 g/s) or as facilities 
with the highest proportional emission rate.\99\ For certain equipment 
types and activities, the EPA's GHG emission estimates include the full 
range of conditions, including ``super-emitters.'' For other 
situations, where data are available, emissions estimates for abnormal 
events are

[[Page 16844]]

calculated separately and included in the Inventory of U.S. Greenhouse 
Gas Emissions and Sinks (GHGI) (e.g., Aliso Canyon leak event).\100\ 
Given the variability of practices and technologies across oil and gas 
systems and the occurrence of episodic events, it is possible that the 
EPA's estimates do not include all methane emissions from abnormal 
events. The EPA continues to engage with the research community and 
expert stakeholders to review new data from the EPA's Greenhouse Gas 
Reporting Program (GHGRP) petroleum and natural gas systems source 
category (40 CFR part 98, subpart W, also referred to as ``GHGRP 
subpart W''), as well as the peer-reviewed scientific literature and 
research studies to assess how emissions estimates can be improved. 
Because lost gas, whether through fugitive emissions, unintentional gas 
carry-through, or intentional releases, represents lost earning 
potential, the industry benefits from capturing and selling emissions 
of natural gas (and methane). Limiting super-emitters through actions 
included in this rulemaking such as reducing fugitive emissions, using 
lower emitting equipment where feasible, and employing best management 
practices will not only reduce emissions but reduce the loss of revenue 
from this valuable commodity.
---------------------------------------------------------------------------

    \98\ See, for example, Brandt, A., Heath, G., Cooley, D. (2016) 
Methane Leaks from Natural Gas Systems Follow Extreme Distributions. 
Environ. Sci. Technol., doi:10.1021/acs.est.6b04303; Zavala-Araiza, 
D., Alvarez, R.A., Lyon, D.R., Allen, D.T., Marchese, A.J., 
Zimmerle, D.J., & Hamburg, S.P. (2017). Super-emitters in natural 
gas infrastructure are caused by abnormal process conditions. Nature 
communications, 8, 14012; Mitchell, A., et al. (2015), Measurements 
of Methane Emissions from Natural Gas Gathering Facilities and 
Processing Plants: Measurement Results. Environmental Science & 
Technology, 49(5), 3219-3227; Allen, D., et al. (2014), Methane 
Emissions from Process Equipment at Natural Gas Production Sites in 
the United States: Pneumatic Controllers. Environmental Science & 
Technology.
    \99\ Caulton, et al. (2019). Importance of Super-emitter Natural 
Gas Well Pads in the Marcellus Shale. Environ. Sci. Technol. 2019, 
53, 4747-4754; Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. 
(2016). Super-emitters in natural gas infrastructure are caused by 
abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012; Lyon, et al. (2016). Aerial 
Surveys of Elevated Hydrocarbon Emissions from Oil and Gas 
Production Sites. Environ. Sci. Technol. 2016, 50, 4877-4886. 
https://pubs.acs.org/doi/10.1021/acs.est.6b00705; and Zavala-Araiza 
D, et al. (2015). Toward a functional definition of methane 
superemitters: Application to natural gas production sites. Environ. 
Sci. Technol. 49, 8167-8174. https://pubs.acs.org/doi/10.1021/acs.est.5b00133.
    \100\ The EPA's emission estimates in the GHGI are developed 
with the best data available at the time of their development, 
including data from the GHGRP in 40 CFR part 98, subpart W, and from 
recent research studies. GHGRP subpart W emissions data used in the 
GHGI are quantified by reporters using direct measurements, 
engineering calculations, or emission factors, as specified by the 
regulation. The EPA has a multi-step data verification process for 
GHGRP subpart W data, including automatic checks during data entry, 
statistical analyses on completed reports, and staff review of the 
reported data. Based on the results of the verification process, the 
EPA follows up with facilities to resolve mistakes that may have 
occurred.
---------------------------------------------------------------------------

    Below we provide estimated emissions of methane, VOC, and 
SO<INF>2</INF> from oil and natural gas industry operation sources.
a. Methane Emissions in the U.S. and From the Oil and Natural Gas 
Industry
    Official U.S. estimates of national-level GHG emissions and sinks 
are developed by the EPA for the GHGI in fulfillment of commitments 
under the United Nations Framework Convention on Climate Change. The 
GHGI, which includes recent trends, is organized by industrial sector. 
The oil and natural gas production, natural gas processing, and natural 
gas transmission and storage sectors emit 28 percent of U.S. 
anthropogenic methane. Table 7 presents total U.S. anthropogenic 
methane emissions for the years 1990, 2010, and 2021.
    In accordance with the practice of the EPA GHGI, the EPA GHGRP, and 
international reporting standards under the U.N. Framework Convention 
on Climate Change, the 2007 IPCC Fourth Assessment Report value of the 
methane 100-year GWP is used for weighting emissions in the following 
tables. The 100-year GWP value of 28 for methane indicates that 1 ton 
of methane has approximately as much climate impact over a 100-year 
period as 28 tons of CO<INF>2</INF>. The most recent IPCC AR6 
assessment has calculated updated 100-year GWPs for methane of either 
27.2 or 29.8 depending on whether the value includes the CO<INF>2</INF> 
produced by the oxidation of methane in the atmosphere. As mentioned 
earlier, because methane has a shorter lifetime than CO<INF>2</INF>, 
the emissions of a ton of methane will have more impact earlier in the 
100-year timespan and less impact later in the 100-year timespan 
relative to the emissions of a 100-year GWP-equivalent quantity of 
CO<INF>2</INF>: when using the AR6 20-year GWP of 81, which only looks 
at impacts over the next 20 years, the total U.S. emissions of methane 
in 2021 would be equivalent to about 2,140 MMT CO<INF>2</INF>.
---------------------------------------------------------------------------

    \101\ Other sources include rice cultivation, stationary 
combustion, abandoned coal mines, mobile combustion, composting, and 
several sources emitting less than 1 MMT CO<INF>2</INF> Eq. in 2021.

                                    Table 7--U.S. Methane Emissions by Sector
                          [Million metric tons carbon dioxide equivalent (MMT CO2 Eq.)]
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2010            2021
----------------------------------------------------------------------------------------------------------------
Oil and Natural Gas Production, and Natural Gas Processing and               206             224             202
 Transmission and Storage.......................................
Landfills.......................................................             198             139             123
Enteric Fermentation............................................             183             191             195
Coal Mining.....................................................             108              92              45
Manure Management...............................................              39              59              66
Other Oil and Gas Sources.......................................              68              37              38
Wastewater Treatment............................................              23              22              21
Other Methane Sources\101\......................................              44              44              38
                                                                 -----------------------------------------------
    Total Methane Emissions.....................................             869             808             727
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2021 (published April 13,
  2023), calculated using GWP of 28. Note: Totals may not sum due to rounding.

    Table 8 presents total methane emissions from natural gas 
production through transmission and storage and petroleum production, 
for years 1990, 2010, and 2021, in MMT CO<INF>2</INF> Eq. (or million 
metric tons CO<INF>2</INF> Eq.) of methane.

                     Table 8--U.S. Methane Emissions From Natural Gas and Petroleum Systems
                                                  [MMT CO2 Eq.]
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2010            2021
----------------------------------------------------------------------------------------------------------------
Natural Gas Production..........................................              68             121              94
Natural Gas Processing..........................................              24              11              14
Natural Gas Transmission and Storage............................              64              39              45

[[Page 16845]]

 
Petroleum Production............................................              50              54              49
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2021 (published April 13,
  2023), calculated using GWP of 28. Note: Totals may not sum due to rounding.

b. Global GHG Emissions
    For additional background information and context, we used 2018 
World Resources Institute Climate Watch data to make comparisons 
between U.S. oil and natural gas production and natural gas processing 
and transmission and storage emissions and the emissions inventories of 
entire countries and regions.\102\ The U.S. methane emissions from oil 
and natural gas production and natural gas processing and transmission 
and storage constitute 0.4 percent of total global emissions of all 
GHGs (48,600 MMT CO<INF>2</INF> Eq.) from all sources.\103\ Ranking 
U.S. emissions of methane from oil and natural gas production and 
natural gas processing and transmission and storage against total GHG 
emissions for entire countries (using 2021 Climate Watch data) shows 
that these emissions are comparatively large as they exceed the 
national-level emissions totals for all GHGs and all anthropogenic 
sources for Colombia, the Czech Republic, Chile, Belgium, and over 164 
other countries. This means that the U.S. emits more of a single GHG--
methane--from a single sector--the oil and natural gas sector--than the 
total combined GHGs emitted by 168 countries. Furthermore, U.S. 
emissions of methane from oil and natural gas production and natural 
gas processing and transmission and storage are greater than the sum of 
total emissions of 63 of the lowest-emitting countries and territories 
using the 2021 Climate Watch data set.
---------------------------------------------------------------------------

    \102\ The Climate Watch figures presented here come from the PIK 
dataset included on Climate Watch. The PIK dataset combines the 
United Nations Framework Convention on Climate Change (UNFCCC) 
reported data where available and fills gaps with other sources. It 
does not include land use change and forestry but covers all other 
sectors. https://www.climatewatchdata.org/ghg-emissions?end_year=2018&source=PIK&start_year=1990. The PIK data set 
uses AR4 GWPs. For the comparisons presented here, the AR4 GWPs were 
applied to the U.S. oil and gas methane values.
---------------------------------------------------------------------------

    As illustrated by the domestic and global GHGs comparison data 
summarized above, the collective GHG emissions from the Crude Oil and 
Natural Gas source category are significant, whether the comparison is 
domestic (where this sector is the largest source of methane emissions, 
accounting for 28 percent of U.S. methane and 3 percent of total U.S. 
emissions of all GHGs), global (where this sector, accounting for 0.4 
percent of all global GHG emissions, emits more than the total national 
emissions of over 160 countries, and combined emissions of over 60 
countries), or when both the domestic and global GHG emissions 
comparisons are viewed in combination. Consideration of the global 
context is important. GHG emissions from U.S. oil and natural gas 
production and natural gas processing and transmission and storage will 
become globally well-mixed in the atmosphere and thus will have an 
effect on both the U.S. regional and global climate for years and 
indeed many decades to come. No single GHG source category dominates on 
the global scale. While the Crude Oil and Natural Gas source category, 
like many (if not all) individual GHG source categories, could appear 
small in comparison to total emissions, in fact, it is a very important 
contributor both in terms of absolute emissions and in comparison to 
other source categories globally or within the U.S.
    The IPCC AR6 assessment determined that ``[f]rom a physical science 
perspective, limiting human-induced global warming to a specific level 
requires limiting cumulative CO<INF>2</INF> emissions, reaching at 
least net zero CO<INF>2</INF> emissions, along with strong reductions 
in other GHG emissions.'' The report also singled out the importance of 
``strong and sustained methane emission reductions'' in part due to the 
short lifetime of methane leading to the near-term cooling from 
reductions in methane emissions, which can offset the warming that will 
result due to reductions in emissions of cooling aerosols such as 
SO<INF>2</INF>. Therefore, reducing methane emissions globally is an 
important facet in any strategy to limit warming. In the oil and gas 
sector, methane reductions are highly achievable and cost-effective 
using existing and well-known solutions and technologies that actually 
result in recovery of saleable product.
c. VOC and SO<INF>2</INF> Emissions in the U.S. and From the Oil and 
Natural Gas Industry
    Official U.S. estimates of national-level VOC and SO<INF>2</INF> 
emissions are developed by the EPA for the National Emissions Inventory 
(NEI), for which states are required to submit information under 40 CFR 
part 51, subpart A. Data in the NEI may be organized by various data 
categories, including sector, NAICS code, and Source Classification 
Code. Tables 9 and 10 below present total U.S. VOC and SO<INF>2</INF> 
emissions by sector, respectively, for the year 2020, in kilotons (kt) 
(or thousand metric tons). The oil and natural gas sector represents 
the top anthropogenic U.S. sector for VOC emissions after removing the 
biogenics and wildfire sectors in table 9 (about 23 percent of the 
total VOC emitting by anthropogenic sources). About 10 percent of the 
total U.S. anthropogenic SO<INF>2</INF> comes from the oil and natural 
gas sector.

                  Table 9--U.S. VOC Emissions by Sector
                                  [kt]
------------------------------------------------------------------------
                        Sector                              2020 NEI
------------------------------------------------------------------------
Biogenics--Vegetation and Soil.......................             29,519
Fires--Wildfires.....................................              4,623
Oil and Natural Gas Production, and Natural Gas                    2,761
 Processing and Transmission.........................
Solvent--Consumer and Commercial Solvent Use.........              1,936
Fires--Prescribed Fires..............................              1,936

[[Page 16846]]

 
Mobile--Non-Road Equipment--Gasoline.................                935
Mobile--On-Road non-Diesel Light Duty Vehicles.......                835
Other VOC Sources....................................              3,642
                                                      ------------------
Total VOC Emissions..................................             46,188
------------------------------------------------------------------------
Emissions from the 2020 NEI (released March 2023). Note: Totals may not
  sum due to rounding.


                 Table 10--U.S. SO2 Emissions by Sector
                                  [kt]
------------------------------------------------------------------------
                        Sector                              2020 NEI
------------------------------------------------------------------------
Fuel Combustion--Electric Generation--Coal...........                771
Industrial Processes--Not Elsewhere Classified.......                230
Oil and Natural Gas Production and Natural Gas                       165
 Processing and Transmission.........................
Fires--Wildfires.....................................                141
Fuel Combustion--Industrial Boilers, Internal                        115
 Combustion Engines--Coal............................
Industrial Processes--Chemical Manufacturing.........                 91
Other SO2 Sources....................................                313
                                                      ------------------
    Total SO2 Emissions..............................              1,827
------------------------------------------------------------------------
Emissions from the 2020 NEI (released March 2023). Note: Totals may not
  sum due to rounding.

    Table 11 presents total VOC and SO<INF>2</INF> emissions from oil 
and natural gas production through transmission and storage, for the 
year 2020, in kt. The contribution to the total anthropogenic VOC 
emissions budget from the oil and gas sector has been increasing in 
recent NEI cycles. In the 2020 NEI, the oil and gas sector makes up 
about 23 percent of the total VOC emissions from anthropogenic sources. 
The SO<INF>2</INF> emissions have been declining in almost every 
anthropogenic sector, but the oil and gas sector is an exception where 
SO<INF>2</INF> emissions have been increasing in recent years.

   Table 11--U.S. VOC and SO2 Emissions from Natural Gas and Petroleum
                                 Systems
                                  [kt]
------------------------------------------------------------------------
                        Sector                            VOC      SO2
------------------------------------------------------------------------
Oil and Natural Gas Production........................    2,729      160
Natural Gas Processing................................        8        3
Natural Gas Transmission and Storage..................       24        2
------------------------------------------------------------------------
Emissions from the 2020 NEI, (published March 2023), in kt (or thousand
  metric tons). Note: Totals may not sum due to rounding.

IV. Statutory Background and Regulatory History

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

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

[[Page 16847]]

    In determining whether a given system of emission reduction 
qualifies as ``the best system of emission reduction . . . adequately 
demonstrated,'' or ``BSER,'' CAA section 111(a)(1) requires that the 
EPA take into account, among other factors, ``the cost of achieving 
such reduction.'' As described in the proposal \104\ for the 2016 Rule 
and in the November 2021 Proposal for this rulemaking,\105\ the U.S. 
Court of Appeals for the District of Columbia Circuit (the D.C. 
Circuit) has stated that in light of this provision, the EPA may not 
adopt a standard the cost of which would be ``exorbitant,'' \106\ 
``greater than the industry could bear and survive,'' \107\ 
``excessive,'' \108\ or ``unreasonable.'' \109\ These formulations 
appear to be synonymous, and for convenience, in this rulemaking, as in 
previous rulemakings, we will refer to this standard as reasonableness, 
so that a control technology may be considered the ``best system of 
emission reduction . . . adequately demonstrated'' if its costs are 
reasonable, but cannot be considered the BSER if its costs are 
unreasonable. See 80 FR 64662, 64720-21 (October 23, 2015).
---------------------------------------------------------------------------

    \104\ 80 FR 56593, 56616 (September 18, 2015).
    \105\ 86 FR 63154 (December 6, 2022).
    \106\ Lignite Energy Council, 198 F.3d at 933.
    \107\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \108\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \109\ Id.
---------------------------------------------------------------------------

    CAA section 111(a) does not provide specific direction regarding 
what metric or metrics to use in considering costs, affording the EPA 
considerable discretion in choosing a means of cost consideration.\110\ 
In this rulemaking, we evaluated whether a control cost is reasonable 
under a number of approaches that we find appropriate for assessing the 
types of controls at issue. For example, we evaluated costs at a sector 
level by assessing the projected new capital expenditures required 
under the final rulemaking (compared to overall new capital 
expenditures by the sector) and the projected compliance costs 
(compared to overall annual revenue for the sector) if the rule were to 
require such controls. In evaluating controls for reducing VOC and 
methane emissions from new sources, we also considered a control's cost 
effectiveness under both a ``single-pollutant cost effectiveness'' 
approach and a ``multipollutant cost effectiveness'' approach, in order 
to appropriately take into account that the systems of emission 
reduction considered in this rule typically achieve reductions in 
multiple pollutants at once and secure a multiplicity of climate and 
public health benefits.\111\ For a detailed discussion of these cost 
approaches, please see section VIII.B of the preamble as well as the 
November 2021 Proposal and the December 2022 Supplemental Proposal.
---------------------------------------------------------------------------

    \110\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. 
Cir. 2001) (where CAA section 213 does not mandate a specific method 
of cost analysis, the EPA may make a reasoned choice as to how to 
analyze costs).
    \111\ We believe that both the single and multipollutant 
approaches are appropriate for assessing the reasonableness of the 
multipollutant controls considered in this action. The EPA has 
considered similar approaches in the past when considering multiple 
pollutants that are controlled by a given control option. See, e.g., 
80 FR 56616-17; 73 FR 64079-83; and EPA Document ID Nos. EPA-HQ-OAR-
2004-0022-0622, -0447, -0448.
---------------------------------------------------------------------------

    Under CAA section 111(a)(1), an essential, although not sufficient, 
condition for a ``system of emission reduction'' to serve as the basis 
for an ``achievable'' emission limitation is that the Administrator 
must determine that the system is ``adequately demonstrated.'' This 
means, according to the D.C. Circuit, that the system is ``one which 
has been shown to be reasonably reliable, reasonably efficient, and 
which can reasonably be expected to serve the interests of pollution 
control without becoming exorbitantly costly in an economic or 
environmental way.'' \112\ It does not mean that the system ``must be 
in actual routine use somewhere,'' \113\ though the technologies relied 
upon in this final rulemaking are. Similarly, the EPA may ``hold the 
industry to a standard of improved design and operational advances, so 
long as there is substantial evidence that such improvements are 
feasible.'' \114\ Ultimately, the analysis ``is partially dependent on 
`lead time,''' that is, ``the time in which the technology will have to 
be available.'' \115\ The caselaw is clear that the EPA may treat a set 
of control measures as ``adequately demonstrated'' regardless of 
whether the measures are in widespread commercial use. For example, the 
D.C. Circuit upheld the EPA's determination that selective catalytic 
reduction (SCR) was adequately demonstrated to reduce NO<INF>X</INF> 
emissions from coal-fired industrial boilers, even though it was a 
``new technology.'' The court explained that ``section 111 `looks 
toward what may fairly be projected for the regulated future, rather 
than the state of the art at present.' '' \116\ The court added that 
the EPA may determine that control measures are ``adequately 
demonstrated'' through a ``reasonable extrapolation of [the control 
measures'] performance in other industries.'' \117\
---------------------------------------------------------------------------

    \112\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \113\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted) (``The Administrator may make a 
projection based on existing technology, though that projection is 
subject to the restraints of reasonableness and cannot be based on 
`crystal ball' inquiry.''); ibid. (discussing the Senate and House 
bills and reports from which the language in CAA section 111 grew).
    \114\ Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981).
    \115\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
    \116\ Lignite Energy Council, 198 F.3d at 934 (citing Portland 
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)).
    \117\ Ibid.
---------------------------------------------------------------------------

    As defined in CAA section 111(a), the ``standard of performance'' 
that the EPA develops, based on the BSER, is expressed as a performance 
level (typically, a rate-based standard). CAA section 111(b)(5) 
precludes the EPA from prescribing a particular technological system 
that must be used to comply with a standard of performance. Rather, 
sources can select any measure or combination of measures that will 
achieve the standard.
    CAA section 111(h)(1) authorizes the Administrator to promulgate 
``a design, equipment, work practice, or operational standard, or 
combination thereof'' if in his or her judgment, ``it is not feasible 
to prescribe or enforce a standard of performance.'' CAA section 
111(h)(2) provides the circumstances under which prescribing or 
enforcing a standard of performance is ``not feasible,'' such as when 
the pollutant cannot be emitted through a conveyance designed to emit 
or capture the pollutant, or when there is no practicable measurement 
methodology for the particular class of sources.\118\ CAA section 
111(b)(1)(B) requires the EPA to ``at least every 8 years review and, 
if appropriate, revise'' performance standards unless the 
``Administrator determines that such review is not appropriate in light 
of readily available information on the efficacy'' of the standard.
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    \118\ 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.
---------------------------------------------------------------------------

    As mentioned above, once the EPA lists a source category under CAA 
section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA 
discretion to determine the pollutants and sources to be regulated. In 
addition, concurrent

[[Page 16848]]

with the 8-year review (and though not a mandatory part of the 8-year 
review), the EPA may examine whether to add standards for pollutants or 
emission sources not currently regulated for that source category.
    Once the EPA establishes NSPS in a particular source category, the 
EPA is required in certain circumstances to issue EG to reduce 
emissions from existing sources in that same source category. 
Specifically, CAA section 111(d) requires that the EPA prescribe 
regulations to establish procedures under which states submit plans to 
establish, implement, and enforce standards of performance for existing 
sources for certain air pollutants to which a Federal NSPS would apply 
if such existing source were a new source. The EPA addresses this CAA 
requirement both through its promulgation of general implementing 
regulations for CAA section 111(d) as well as through specific EG. The 
EPA first published general implementing regulations in 1975, 40 FR 
53340 (November 17, 1975) (codified at 40 CFR part 60, subpart B), and 
has revised its CAA section 111(d) implementing regulations several 
times. on the EPA published updated implementing regulations in 2019, 
84 FR 32520 (codified at 40 CFR part 60, subpart Ba), which apply to EG 
promulgated after July 8, 2019, 40 CFR 60.20a(a), including this EG, 
and which were recently revised.\119\ In accordance with CAA section 
111(d), states are required to submit plans pursuant to these 
regulations to establish standards of performance for existing sources 
for any air pollutant: (1) the emission of which is subject to a 
Federal NSPS; and (2) which is neither a pollutant regulated under CAA 
section 108(a) (i.e., criteria pollutants such as ground-level ozone 
and particulate matter (PM), and their precursors, like VOC) \120\ nor 
a HAP regulated under CAA section 112. See also definition of 
``designated pollutant'' in 40 CFR 60.21a(a). The EPA's general 
implementing regulations use the term ``designated facility'' to 
identify those existing sources that may be subject to regulation under 
the provision of CAA section 111(d). See 40 CFR 60.21a(b).
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    \119\ The D.C. Circuit vacated certain timing provisions within 
subpart Ba. American Lung Ass'n, 985 F.3d 914. However, the court 
did not vacate the applicability provision. Therefore, 40 CFR part 
60, subpart Ba, applies to the final EG. On November 17, 2023, the 
EPA issued final updates to the Agency's ``Implementing 
Regulations'' under section 111(d) of the Clean Air Act (88 FR 
80480). These final amendments address the provisions that were 
vacated in 2021 and make other updates to the implementing 
regulations applicable to this EG.
    \120\ VOC are not listed as CAA section 108(a) pollutants, but 
they are regulated precursors to photochemical oxidants (e.g., 
ozone), which is a listed CAA section 108(a) pollutant. Therefore, 
VOC falls within the CAA 108(a) exclusion. Accordingly, promulgation 
of NSPS for VOC does not trigger the application of CAA section 
111(d).
---------------------------------------------------------------------------

    While states are authorized to establish standards of performance 
for designated facilities, there is a fundamental requirement under CAA 
section 111(d) that a state's standards of performance in its state 
plan submittal are no less stringent than the presumptive standard 
determined by the EPA, which derives from the definition of ``standard 
of performance'' in CAA section 111(a)(1). The EPA identifies the 
degree of emission limitation achievable through application of the 
BSER as part of its EG. See 40 CFR 60.22a(b)(5). While standards of 
performance must generally reflect the degree of emission limitation 
achievable through application of the BSER, CAA section 111(d)(1) also 
requires that the EPA regulations permit the states, in applying a 
standard of performance to a particular source, to take into account 
the source's RULOF. States may apply less stringent standards of 
performance to particular sources based on consideration of such 
sources' remaining useful life and other factors.
    After the EPA issues final EG per the requirements under CAA 
section 111(d) and under 40 CFR part 60, subpart Ba, states are 
required to submit to the EPA plans that establish standards of 
performance for the designated facilities as defined in the EPA's 
guidelines and that contain other measures to implement and enforce 
those standards. The EPA's final EG issued under CAA section 111(d) do 
not impose binding requirements directly on sources but instead provide 
requirements for states in developing their plans and criteria for 
assisting the EPA when judging the adequacy of such plans. Under CAA 
section 111(d), and the EPA's implementing regulations, a state must 
submit its plan to the EPA for approval; the EPA will evaluate the plan 
for completeness in accordance with enumerated criteria and then will 
act on that plan via a rulemaking process to either approve or 
disapprove the plan in whole or in part. If a state does not submit a 
plan, or if the EPA does not approve a state's plan because it is not 
``satisfactory,'' then the EPA must establish a Federal plan for 
designated facilities in that state.\121\ If the EPA approves a state's 
plan, the provisions in the state plan become federally enforceable 
against the designated facility responsible for compliance in the same 
manner as the provisions of an approved State Implementation Plan (SIP) 
under CAA section 110. If no designated facility is located within a 
state, the state must submit to the EPA a letter certifying to that 
effect in lieu of submitting a state plan. See 40 CFR 60.23a(b).
---------------------------------------------------------------------------

    \121\ CAA section 111(d)(2)(A).
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    Designated facilities located in Indian country would not be 
addressed by a state's CAA section 111(d) plan. Instead, an eligible 
Tribe that has one or more designated facilities located in its area of 
Indian country \122\ 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.\123\ 
If a Tribe does not submit a plan, or if the EPA does not approve a 
Tribe's plan, then the EPA has the authority to establish a Federal 
plan for the designated facilities located on its Tribal land.\124\
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    \122\ The EPA is aware of many oil and natural gas operations 
located in Indian country.
    \123\ See 40 CFR part 49, subpart A.
    \124\ CAA section 111(d)(2)(A).
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B. What is the regulatory history and litigation background of NSPS and 
EG for the oil and natural gas industry?

1. 1979 Listing of Source Category
    Subsequent to the enactment of the CAA of 1970, the EPA took action 
to develop standards of performance for new stationary sources as 
directed by Congress in CAA section 111. By 1977, the EPA had 
promulgated NSPS for a total of 27 source categories, while NSPS for an 
additional 25 source categories were then under development.\125\ 
However, in amending the CAA that year, Congress expressed 
dissatisfaction that the EPA's pace was too slow. Accordingly, the 1977 
CAA Amendments included a new subsection (f) in section 111, which 
specified a schedule for the EPA to list additional source categories 
under CAA section 111(b)(1)(A) and prioritize them for regulation under 
CAA section 111(b)(1)(B).
---------------------------------------------------------------------------

    \125\ See 44 FR 49222 (August 21, 1979).
---------------------------------------------------------------------------

    In 1979, as required by CAA section 111(f), the EPA published a 
list of source categories, which included ``Crude Oil and Natural Gas 
Production,'' for which the EPA would promulgate standards of 
performance under CAA section 111(b). See ``Priority List and Additions 
to the List of Categories of Stationary Sources,'' 44 FR 49222 (August 
21, 1979) (``1979 Priority List''). That list included, in the order of 
priority for promulgating standards, source categories that the EPA 
Administrator had determined, pursuant to CAA section 111(b)(1)(A),

[[Page 16849]]

contribute significantly to air pollution that may reasonably be 
anticipated to endanger public health or welfare. See 44 FR 49223 
(August 21, 1979); see also 49 FR 2636-37 (January 20, 1984).
2. 1985 NSPS for VOC and SO<INF>2</INF> Emissions From Natural Gas 
Processing Plants
    On June 24, 1985 (50 FR 26122), the EPA promulgated NSPS for the 
Crude Oil and Natural Gas source category that addressed VOC emissions 
from equipment leaks at onshore natural gas processing plants (40 CFR 
part 60, subpart KKK). On October 1, 1985 (50 FR 40158), the EPA 
promulgated additional NSPS for the source category to regulate 
SO<INF>2</INF> emissions from onshore natural gas processing plants (40 
CFR part 60, subpart LLL).
3. 2012 NSPS OOOO Rule and Related Amendments
    In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to 
review and, if appropriate, revise the 1985 NSPS, the EPA published the 
final rule, ``Standards of Performance for Crude Oil and Natural Gas 
Production, Transmission and Distribution,'' 77 FR 49490 (August 16, 
2012) (40 CFR part 60, subpart OOOO) (``2012 NSPS OOOO''). The 2012 
rule updated the SO<INF>2</INF> standards for sweetening units and the 
VOC standards for equipment leaks at onshore natural gas processing 
plants. In addition, it established VOC standards for several oil and 
natural gas-related operations emission sources not covered by 40 CFR 
part 60, subparts KKK and LLL, including natural gas well completions, 
centrifugal and reciprocating compressors, certain natural gas-driven 
process controllers in the production and processing segments of the 
industry, and storage vessels in the production, processing, and 
transmission and storage segments.
    In 2013, 2014, and 2015 the EPA amended the 2012 NSPS OOOO rule in 
order to address implementation of the standards. ``Oil and Natural Gas 
Sector: Reconsideration of Certain Provisions of New Source Performance 
Standards,'' 78 FR 58416 (September 23, 2013) (``2013 NSPS OOOO'') 
(concerning storage vessel implementation); ``Oil and Natural Gas 
Sector: Reconsideration of Additional Provisions of New Source 
Performance Standards,'' 79 FR 79018 (December 31, 2014) (``2014 NSPS 
OOOO'') (concerning well completion); ``Oil and Natural Gas Sector: 
Definitions of Low Pressure Gas Well and Storage Vessel,'' 80 FR 48262 
(August 12, 2015) (``2015 NSPS OOOO'') (concerning low-pressure gas 
wells and storage vessels).
    The EPA received petitions for both judicial review and 
administrative reconsiderations for the 2012, 2013, and 2014 NSPS OOOO 
rules. The EPA denied reconsideration for some issues, see 
``Reconsideration of the Oil and Natural Gas Sector: New Source 
Performance Standards; Final Action,'' 81 FR 52778 (August 10, 2016), 
and, as noted below, granted reconsideration for other issues. As 
explained below, all litigation related to NSPS OOOO is currently in 
abeyance.
4. 2016 NSPS OOOOa Rule and Related Amendments
a. Regulatory Action
    On June 3, 2016, the EPA published a final rule titled, ``Oil and 
Natural Gas Sector: Emission Standards for New, Reconstructed, and 
Modified Sources; Final Rule,'' at 81 FR 35824 (40 CFR part 60, subpart 
OOOOa) (``2016 Rule'' or ``2016 NSPS OOOOa'').<SUP>126 127</SUP> The 
2016 NSPS OOOOa rule established NSPS for sources of GHGs and VOC 
emissions for certain equipment, processes, and operations across the 
oil and natural gas industry, including in the transmission and storage 
segment (81 FR 35832). The EPA explained that the 1979 listing 
identified the source category broadly enough to include that segment 
and, in the alternative, if the listing had limited the source category 
to the production and processing segments, the EPA affirmatively 
expanded the source category to include the transmission and storage 
segment on grounds that operations in those segments are a sequence of 
functions that are interrelated and necessary for getting the recovered 
gas ready for distribution (81 FR 35832). In addition, because the 2016 
rule represented the first time that the EPA had promulgated NSPS for 
GHG emissions from the Crude Oil and Natural Gas source category, the 
EPA predicated those NSPS on a determination that it had a rational 
basis on which to regulate GHG emissions from the source category (81 
FR 35843). In response to comments, the EPA explained that it was not 
required to make an additional pollutant-specific finding that GHG 
emissions from the source category contribute significantly to 
dangerous air pollution, but in the alternative, the EPA did make such 
a finding, relying on the same information that it relied on when 
determining that it had a rational basis on which to promulgate a GHG 
NSPS (81 FR 35843).
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    \126\ The June 3, 2016, rulemaking also included certain final 
amendments to 40 CFR part 60, subpart OOOO, to address issues on 
which the EPA had granted reconsideration.
    \127\ The EPA review which resulted in the 2016 NSPS OOOOa rule 
was instigated by a series of directives from then-President Obama 
targeted at reducing GHGs, including methane: the President's 
Climate Action Plan (June 2013); the President's Climate Action 
Plan: Strategy to Reduce Methane Emissions (``Methane Strategy'') 
(March 2014); and the President's goal to address, propose and set 
standards for methane and ozone-forming emissions from new and 
modified sources in the sector (January 2015, https://obamawhitehouse.archives.gov/the-press-office/2015/01/14/fact-sheet-Administration-takes-steps-forward-climate-action-plan-anno-1).
---------------------------------------------------------------------------

    Specifically, the 2016 NSPS OOOOa addresses the following emission 
sources:
    <bullet> Sources that were unregulated under the 2012 NSPS OOOO 
(hydraulically fractured oil well completions, pneumatic pumps, and 
fugitive emissions from well sites and compressor stations);
    <bullet> Sources that were regulated under the 2012 NSPS OOOO for 
VOC emissions, but not for GHG emissions (hydraulically fractured gas 
well completions and equipment leaks at natural gas processing plants); 
and
    <bullet> Certain equipment that is used across the source category, 
of which the 2012 NSPS OOOO regulated emissions of VOC from only a 
subset (process controllers, centrifugal compressors, and reciprocating 
compressors, with the exception of those compressors located at well 
sites).
    On March 12, 2018 (83 FR 10628), the EPA finalized amendments to 
certain aspects of the 2016 NSPS OOOOa requirements for the collection 
of fugitive emissions components at well sites and compressor stations, 
specifically (1) the requirement that components on a delay of repair 
must conduct repairs during unscheduled or emergency vent blowdowns, 
and (2) the monitoring survey requirements for well sites located on 
the Alaska North Slope.
b. Petitions for Judicial Review and To Reconsider
    Following promulgation of the 2016 NSPS OOOOa rule, several states 
and industry associations challenged the final rule in the D.C. 
Circuit. The Administrator also received five petitions for 
reconsideration of several provisions of the final rule. Copies of the 
petitions are posted in Docket ID No. EPA-HQ-OAR-2010-0505.\128\ As 
noted below, the EPA granted reconsideration as to several issues 
raised with respect to the 2016 NSPS OOOOa rule and finalized certain 
modifications discussed in the next section of this document. As 
explained in the next section, all litigation challenging the

[[Page 16850]]

2016 NSPS OOOOa rule is currently stayed.
---------------------------------------------------------------------------

    \128\ See Document ID Nos. EPA-HQ-OAR-2010-0505-7682, -7683, -
7684, -7685, -7686.
---------------------------------------------------------------------------

5. 2020 Policy and Technical Rules
a. Regulatory Action
    In September 2020, the EPA published two final rules to amend 2012 
NSPS OOOO and 2016 NSPS OOOOa. The first is titled, ``Oil and Natural 
Gas Sector: Emission Standards for New, Reconstructed, and Modified 
Sources Review.'' 85 FR 57018 (September 14, 2020). Commonly referred 
to as the 2020 Policy Rule, it first rescinded the regulations 
applicable to the transmission and storage segment on the basis that 
the 1979 listing limited the source category to the production and 
processing segments and that the transmission and storage segment is 
not ``sufficiently related'' to the production and processing segments 
and therefore cannot be part of the same source category (85 FR 57027, 
57029). In addition, the 2020 Policy Rule rescinded methane 
requirements for the industry's production and processing segments on 
two separate bases. The first was that such standards are redundant to 
VOC standards for these segments (85 FR 57030). The second was that the 
rule interpreted CAA section 111 to require, or at least authorize the 
Administrator to require, a pollutant-specific ``significant 
contribution finding'' (SCF) as a prerequisite to a NSPS for a 
pollutant, and to require that such finding be supported by some 
identified standard or established set of criteria for determining 
which contributions are ``significant'' (85 FR 57034). The 2020 Policy 
Rule went on to conclude that the alternative significant-contribution 
finding that the EPA made in the 2016 Rule for GHG emissions was flawed 
because it accounted for emissions from the transmission and storage 
segment and because it was not supported by criteria or a threshold (85 
FR 57038).\129\
---------------------------------------------------------------------------

    \129\ Following the promulgation of the 2020 Policy Rule, the 
EPA promulgated a final rule that identified a standard or criteria 
for determining which contributions are ``significant,'' which the 
D.C. Circuit vacated. ``Pollutant-Specific Significant Contribution 
Finding for Greenhouse Gas Emissions From New, Modified, and 
Reconstructed Stationary Sources: Electric Utility Generating Units, 
and Process for Determining Significance of Other New Source 
Performance Standards Source Categories.'' 86 FR 2542 (January 13, 
2021), vacated by California v. EPA, No. 21-1035 (D.C. Cir.) (Order, 
April 5, 2021, Doc. #1893155).
---------------------------------------------------------------------------

    Published on September 15, 2020, the second of the two rules is 
titled, ``Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources Reconsideration.'' Commonly 
referred to as the 2020 Technical Rule, this second rule made further 
amendments to the 2016 NSPS OOOOa following the 2020 Policy Rule to 
eliminate or reduce certain monitoring obligations and to address a 
range of issues in response to administrative petitions for 
reconsideration and other technical and implementation issues brought 
to the EPA's attention since the 2016 NSPS OOOOa rulemaking. 
Specifically, the 2020 Technical Rule exempted low production well 
sites from fugitives monitoring (previously required semiannually), 
required semiannual monitoring at gathering and boosting compressor 
stations (previously quarterly), streamlined recordkeeping and 
reporting requirements, allowed compliance with certain equivalent 
state requirements as an alternative to NSPS fugitive requirements, 
streamlined the application process to request the use of new 
technologies to monitor for fugitive emissions, addressed storage tank 
batteries for applicability determination purposes and finalized 
several technical corrections. Because the 2020 Technical Rule was 
issued the day after the EPA's rescission of methane regulations in the 
2020 Policy Rule, the amendments made in the 2020 Technical Rule 
applied only to the requirements to regulate VOC emissions from this 
source category. The 2020 Policy Rule amended 40 CFR part 60, subparts 
OOOO and OOOOa, as finalized in 2016. The 2020 Technical Rule amended 
the 40 CFR part 60, subpart OOOOa, as amended by the 2020 Policy Rule.
b. Petitions To Reconsider
    The EPA received three petitions for reconsideration of the 2020 
rulemakings. Two of the petitions sought reconsideration of the 2020 
Policy Rule. As discussed below, on June 30, 2021, the President signed 
into law S.J. Res. 14, a joint resolution under the CRA disapproving 
the 2020 Policy Rule, and as a result, the petitions for 
reconsideration on the 2020 Policy Rule are now moot. All three 
petitions sought reconsideration of certain elements of the 2020 
Technical Rule.
c. Litigation
    Several states and non-governmental organizations (NGOs) challenged 
the 2020 Policy Rule as well as the 2020 Technical Rule. All petitions 
for review regarding the 2020 Policy Rule were consolidated into one 
case in the D.C. Circuit. State of California, et al. v. EPA, No. 20-
1357. On August 25, 2021, after the enactment of the joint resolution 
of Congress disapproving the 2020 Policy Rule (explained in section 
VIII of this preamble), the U.S. Court of Appeals for the District of 
Columbia Circuit (i.e., the court) granted petitioners' motion to 
voluntarily dismiss their cases. Id. ECF Docket #1911437. All petitions 
for review regarding the 2020 Technical Rule were consolidated into a 
different case in the D.C. Circuit. Environmental Defense Fund (EDF), 
et al. v. EPA, No. 20-1360 (D.C. Cir.). On February 19, 2021, the court 
issued an order granting a motion by the EPA to hold in abeyance the 
consolidated litigation over the 2020 Technical Rule pending the EPA's 
rulemaking actions in response to E.O. 13990 and pending the conclusion 
of the EPA's potential reconsideration of the 2020 Technical Rule. Id. 
ECF Docket #1886335.
    As mentioned above, the EPA received petitions for judicial review 
regarding the 2012, 2013, and 2014 NSPS OOOO rules as well as the 2016 
NSPS OOOOa rule. The challenges to the 2012 NSPS OOOO rule (as amended 
by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) were consolidated. 
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.). The 
majority of those cases were further consolidated with the consolidated 
challenges to the 2016 NSPS OOOOa rule. West Virginia v. EPA, No. 16-
1264 (D.C. Cir.), see specifically ECF Docket #1654072. As such, West 
Virginia v. EPA includes challenges to the 2012 NSPS OOOO rule (as 
amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) as well as 
challenges to the 2016 NSPS OOOOa rule.\130\ On December 10, 2020, the 
court granted a joint motion of the parties in West Virginia v. EPA to 
hold that case in abeyance until after the mandate has issued in the 
case regarding challenges to the 2020 Technical Rule. West Virginia v. 
EPA, ECF Docket #1875192.
---------------------------------------------------------------------------

    \130\ When the EPA issued the 2016 NSPS OOOOa rule, a challenge 
to the 2012 NSPS OOOO rule for failing to regulate methane was 
severed and assigned to a separate case, NRDC v. EPA, No. 16-1425 
(D.C. Cir.), pending judicial review of the 2016 NSPS OOOOa in 
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.).
---------------------------------------------------------------------------

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

    On June 30, 2021, the President signed into law a joint resolution 
of Congress, S.J. Res. 14, adopted under the CRA,\131\ disapproving the 
2020 Policy Rule.\132\ By the terms of the CRA, the signing into law of 
the CRA joint resolution of disapproval means that the

[[Page 16851]]

2020 Policy Rule is ``treated as though [it] had never taken effect.'' 
5 U.S.C. 801(f). As a result, the VOC and methane standards for the 
transmission and storage segment, as well as the methane standards for 
the production and processing segments--all of which had been rescinded 
in the 2020 Policy Rule--remain in effect. In addition, the EPA's 
authority and obligation to require the states to regulate existing 
sources of methane in the Crude Oil and Natural Gas source category 
under section 111(d) of the CAA also remains in effect.
---------------------------------------------------------------------------

    \131\ The Congressional Review Act was adopted in Subtitle E of 
the Small Business Regulatory Enforcement Fairness Act of 1996.
    \132\ ``Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources Review,'' 85 FR 57018 (September 
14, 2020) (``2020 Policy Rule'').
---------------------------------------------------------------------------

    The CRA resolution did not address the 2020 Technical Rule. 
Therefore, those amendments remain in effect with respect to the VOC 
standards for the production and processing segments in effect at the 
time of its enactment. As part of this rulemaking, in section XII of 
this document the EPA discusses the impact of the CRA resolution and 
identifies and finalizes appropriate changes to reinstate the 
regulatory text that had been rescinded by the 2020 Policy Rule and to 
resolve any discrepancies in the regulatory text between the 2016 NSPS 
OOOOa Rule and 2020 Technical Rule.\133\
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    \133\ The EPA understands that a limited number of affected 
facilities may have obtained, renewed, or revised a title V permit 
to reflect the 2020 Policy Rule, and that such permits no longer 
include certain applicable requirements from the 2012 NSPS OOOO and 
2016 NSPS OOOOa regulations that were reinstated by the CRA. The EPA 
strongly encourages states to reopen Title V permits that currently 
reflect the 2020 Policy Rule, and to follow all appropriate 
requirements of 40 CFR 70.7(f) governing the reopening of Title V 
permits.
---------------------------------------------------------------------------

V. Legal Basis for Final Rule Scope

A. Introduction

    The EPA finalizes this rulemaking to revise certain NSPS, to 
promulgate additional NSPS for both methane and VOC emissions from new 
oil and gas sources in the production, processing, and transmission and 
storage segments of the industry; and to promulgate EG to require 
states to regulate methane emissions from existing sources in those 
segments. The large amount of methane emissions from the oil and 
natural gas industry--by far, the largest methane-emitting industry in 
the nation--coupled with the adverse effects of methane on the global 
climate compel expeditious regulatory action to mitigate those 
emissions. This section explains the EPA's legal authority for 
proceeding with this final action, including regulating methane and 
VOCs from sources in all segments of the source category, and in so 
doing, responds to the principal comments received.
    In the November 2021 Proposal and the December 2022 Supplemental 
Proposal, the EPA discussed the history of our regulatory actions for 
oil and gas sources in the 2016 NSPS OOOOa and the 2020 Policy Rule. 
See 85 FR 63147-53, 86 FR74719-20. These discussions explained the key 
statutory interpretations and determinations, which we sometimes refer 
to as the key positions, taken in the 2016 rule that serve as the basis 
for this action, as well as Congress's endorsement of those positions 
in adopting the 2021 CRA joint resolution to disapprove the 2020 rule 
and thereby reinstate the 2016 rule. These discussions further 
explained that the EPA was not reopening those positions in this 
rulemaking, but added, for the purpose of informing the public, that 
the EPA would continue to take the same positions even if Congress had 
not adopted the joint resolution. The EPA includes those discussions by 
reference here, and the rest of this section assumes familiarity with 
them. For convenience, the EPA summarizes them immediately below. The 
EPA then summarizes the principal comments received and responds to the 
most significant adverse comments. For the purpose of providing more 
information to the public, and without reopening the positions in the 
2016 rule, the EPA explains why we would take the same positions as in 
the 2016 rule even if Congress had not adopted the joint resolution as 
well as the implications of the joint resolution and its legislative 
history in foreclosing commenters' objections.

B. Overview

    This section summarizes why the statutory interpretations the EPA 
took in the 2016 Rule were correct and why the contrary interpretations 
taken in the congressionally-voided 2020 Policy Rule were 
incorrect.\134\ These views are confirmed by Congress's reasoning in 
the legislative history of the CRA resolution and so, for convenience, 
this section refers to that legislative history as well.
---------------------------------------------------------------------------

    \134\ Under F.C.C. v. Fox Television Stations, Inc., 556 U.S. 
502 (2009), an agency may revise its policy, but must demonstrate 
that the new policy is permissible under the statute and is 
supported by good reasons, taking into account the record of the 
previous rule. To the extent that this standard applies in this 
action--where Congress has disapproved the 2020 Policy Rule--the EPA 
believes the explanations provided here satisfy the standard.
---------------------------------------------------------------------------

    The 2016 NSPS OOOOa established the EPA's authority to regulate GHG 
emissions from the Crude Oil and Natural Gas source category, in the 
form of limits on methane emissions. In that rule, the EPA explained 
that the source category, as the EPA listed it in 1979 for regulation 
under CAA section 111(b)(1)(A), included the production and processing 
as well as transmission and storage segments. The EPA also explained 
that it was justified in promulgating standards of performance for GHG 
emissions from new sources in the source category because it had a 
rational basis for doing so. In response to comments, the EPA further 
explained that once it had listed a source category, it was not 
required to make, as a predicate to regulating GHG emissions from the 
source category, an additional pollutant-specific finding that those 
GHG emissions contribute significantly to dangerous air pollution 
(termed, a pollutant-specific significant contribution finding).
    In addition to providing those explanations, the EPA made two 
determinations in the 2016 NSPS OOOOa that established alternative 
legal bases for the GHG NSPS. The first was that the EPA re-listed the 
source category under CAA section 111(b)(1)(A). To do so, the EPA 
determined the following: (i) In case the source category did not 
already include the transmission and storage segment, the EPA revised 
the source category to include that segment, along with the production 
and processing segments. The EPA explained that all the segments are 
interrelated because they comprise parts of a single process of 
extracting natural gas and preparing it for commercial sale, and that 
many of the same types of equipment are used in the various segments. 
(ii) By dint of its emissions of VOC, SO<INF>2</INF>, and GHG, the 
source category thus defined ``causes or contributes significantly to 
air pollution which may reasonably be anticipated to endanger public 
health or welfare,'' under CAA section 111(b)(1)(A). 81 FR 25833-40. 
For convenience, we refer to this as the endangerment finding, and 
treat it as having two components: the significant contribution finding 
and the finding of dangerous air pollution. The second determination 
was that, in the alternative, if it were necessary to make a pollutant-
specific significant contribution finding for GHG emissions as a 
predicate to promulgating NSPS for GHG from the source category, then 
the 2016 rule made such a finding. To do so, the rule relied on 
information concerning the large amounts of methane emissions from the 
source category. 81 FR 35843.
    The 2020 Policy Rule rescinded the above statutory interpretations 
and determinations. 85 FR 57018. The rule asserted that the 
transmission and storage segment was not properly included as part of 
the same source

[[Page 16852]]

category as the production and processing segments, and was therefore 
not subject to regulation under CAA section 111. The rule took the 
position that the transmission and storage segment had not been 
included in the source category when it was originally listed in 1979, 
and the 2016 rule's alternative determination to revise the source 
category was flawed because that segment was not interrelated with the 
production and processing segments. The rule further asserted that the 
EPA did not have authority to promulgate NSPS for methane emissions 
from sources in the production and processing segments because those 
NSPS were redundant to NSPS for VOC emissions from those sources. The 
rule further asserted, in the alternative, that the EPA did not have 
such authority because it was required to make, or was at least 
authorized to require, a pollutant-specific significant contribution 
finding for GHG emissions from production and processing sources as a 
predicate for promulgating NSPS for methane emissions. The rule 
explained that such a finding was necessary because the EPA had not 
considered GHG emissions when it listed the source category in 1979. 
The rule further asserted that the pollutant-specific significant 
contribution finding in the 2016 NSPS OOOOa was flawed because it had 
been based in part on emissions from the transmission and storage 
segment, which, in the rule's view, were not part of the oil and gas 
source category, and because the EPA had not first established a 
standard or criteria for determining when emissions contribute 
significantly, as opposed to simply contribute, to dangerous air 
pollution. 85 FR 57024-40.
    The CRA joint resolution, signed into law by President Biden on 
June 30, 2021, disapproved the 2020 Policy Rule, and thereby reinstated 
the 2016 NSPS OOOOa regulation of sources in the transmission and 
storage segment and regulation of methane emissions from the entire oil 
and gas source category. 86 FR 63135-36. The legislative history of the 
CRA resolution--the House Report and a floor statement from Senate 
sponsors, 167 Cong. Rec. S2282-83 (April 28, 2021) (statement by Sen. 
Heinrich) (Senate Statement)--made clear Congress's intent that the EPA 
must regulate methane from the source category under CAA section 111, 
due to the large amount and impact of those emissions. The legislative 
history went on to make clear that Congress's basis for disapproving 
the 2020 rule was that Congress rejected each of the legal 
interpretations, described above, that underlay the rule. Specifically, 
the legislative history stated that: the rule was incorrect in removing 
the transmission and storage segment from the source category; 
promulgation of NSPS for methane was not redundant with promulgation of 
NSPS for VOCs, in light of the fact that the former, but not the 
latter, triggers the requirement to promulgate emission guidelines for 
existing sources under CAA section 111(d); the EPA is required to 
promulgate NSPS for a pollutant from a source category when the EPA has 
a rational basis for doing so, and the EPA cannot decline to promulgate 
a NSPS on grounds that it is required, or authorized to require, a 
pollutant-specific significant contribution finding; and the EPA's past 
approach of relying on a facts-and-circumstances approach to determine 
significance is acceptable, and an established standard or criteria are 
not necessary.
    In the November 2021 Proposal, the EPA confirmed that it agreed 
with those interpretations. 86 FR 63151. In the December 2022 
Supplemental Proposal, the EPA added that if it were required to make a 
pollutant-specific significant contribution finding, it would not be 
required to specify a standard or criterion for determining 
significance, and that if it were so required, methane emissions from 
the source category are so large that they would be significant under 
any reasonable standard or criterion. 87 FR 74719-20 (explaining that 
the ``massive quantities of methane emissions'' from the source 
category, combined with the ``potency of methane'' are significant in 
light of, among other things, the fact that the oil and gas sector 
accounts for 28 percent of U.S. methane emissions or more than the 
total national emissions of over 160 countries).\135\
---------------------------------------------------------------------------

    \135\ As noted above, to the extent that the standard of Fox 
Television applies in this action--where Congress has disapproved 
the 2020 Policy Rule--the EPA believes the explanations provided 
here satisfy the standard.
---------------------------------------------------------------------------

C. Comments

    Some stakeholders commented adversely. They assert that the 
November 2021 Proposal and the December 2022 Supplemental Proposal 
contain what they see as the same flaws as the 2016 NSPS OOOOa. One of 
these flaws, these commenters assert, is that the EPA is precluded from 
promulgating requirements for sources in the transmission and storage 
segment without first listing that segment as a separate source 
category and making an endangerment finding for GHG emissions from it. 
According to this view, the source category as listed in 1979 did not 
include that segment, and that segment must be treated as a separate 
source category because otherwise, the agency could expand a 
preexisting source category incrementally, and thereby avoid the CAA 
section 111 requirements to undertake an endangerment finding before 
promulgating regulation. A second flaw, according to these commenters, 
is that regulation of methane is redundant to regulation of VOC. In 
addition, the commenters assert that CAA section 111 precludes the EPA 
from promulgating requirements for GHG emissions from the source 
category without first making a pollutant-specific endangerment 
finding, including a pollutant-specific significant contribution 
finding. Moreover, according to the commenters, such a finding must be 
for methane. In addition, it must be based on an established standard 
or criteria for determining significance; otherwise, such a finding 
would be arbitrary and capricious. According to these commenters, CAA 
section 111 does not authorize the EPA to regulate air pollutants from 
a listed source category on the grounds that it has a rational basis 
for such regulation. These commenters further assert that although the 
CRA resolution disapproved the 2020 Policy Rule, it did not change the 
underlying requirements of CAA section 111, so that these flaws in the 
EPA's regulatory approach remained. They argue that only the 
legislative language of the joint resolution, and not the accompanying 
legislative history, is relevant.
    Other commenters supported the November 2021 Proposal and December 
2022 Supplemental Proposal. They state that the 2016 NSPS OOOOa 
established an appropriate basis for promulgating regulations to 
control methane emissions from the oil and gas industry. They state 
that the 1979 source category listing included the transmission and 
storage segment, and that in any event, the 2016 rule correctly 
determined that the transmission and storage segment was interrelated 
with the other segments and thus merited inclusion in the revised 
source category. They also state that regulation of methane from this 
source category is not redundant to regulation of VOCs. They add that 
because the EPA previously determined that the oil and gas source 
category causes or contributes significantly to dangerous air 
pollution, the EPA is authorized to promulgate a NSPS for methane 
because it is rational to do so in light of the large amount of methane 
emissions from the source category. For

[[Page 16853]]

this reason, commenters assert, it would be arbitrary and capricious 
for the EPA to decline to regulate methane emissions from the source 
category. Commenters add that a pollutant-specific significant 
contribution or endangerment finding for methane is neither necessary 
nor authorized by CAA section 111; that any such findings under CAA 
section 111 should be made on the basis of the facts and circumstances, 
and not a predetermined standard or threshold; and that in any event, 
the large amounts of methane emissions from the source category must be 
considered to be significant under any reasonable definition. 
Commenters also note that the 2016 rule made an appropriate significant 
finding contribution for GHG from the source category in the 
alternative. Commenters also assert that Congress's disapproval of the 
2020 Policy Rule through the CRA joint resolution reaffirmed the 2016 
rule's positions.

D. Response to Comments and Discussion

    The adverse arguments by commenters described above concern the 
positions in the 2016 NSPS OOOOa, which also provide the basis for this 
rulemaking, and the significance of the CRA joint resolution and its 
legislative history. The commenters' arguments concerning the positions 
in the 2016 rule were rejected in the 2016 rule itself, adopted in the 
2020 Policy Rule, and then rejected in the legislative history of the 
joint resolution. The EPA stated in the November 2021 Proposal and 
December 2022 Supplemental Proposal that it was not reopening these 
positions, and we maintain that decision here. However, again, solely 
for the purpose of informing the public, we provide responses to the 
commenters' arguments immediately below and in the response to comment 
document. Our decision not to reopen the positions in the 2016 rule 
does not apply to issues concerning the joint resolution, which post-
dated the 2016 rule. Accordingly, the EPA responds in more detail 
further below to the commenters' arguments concerning the joint 
resolution.
1. Commenters' Arguments Concerning the Key Positions in the 2016 NSPS 
OOOOa
    Stakeholders submitted adverse comments on key positions, including 
statutory interpretations and determinations, that the EPA made in the 
2016 NSPS OOOOa and that serve as the foundation for the present 
action. These adverse comments generally mirrored those made in the 
course of the 2016 NSPS OOOOa rulemaking and the rationale for the 2020 
Policy Rule, and did not raise significant new points not addressed in 
the 2016 NSPS OOOOa or the November 2021 Proposal and December 2022 
Supplemental Proposal. The EPA continues to disagree with those 
comments.
a. Scope of the Oil and Gas Source Category as Listed in 1979
i. Scope of the Source Category as Listed in 1979
    The 2016 NSPS OOOOa stated that the Crude Oil and Natural Gas 
Production source category, as the EPA listed it for regulation under 
CAA section 111(b)(1)(A) in 1979, included the transmission and storage 
segment, along with the other two major segments of the industry, the 
production and processing segments. Based on this understanding, the 
EPA continued to promulgate NSPS for sources in that segment, after it 
had begun to do so in the 2012 NSPS OOOO. Adverse commenters on the 
November 2021 Proposal took the contrary view, reiterating adverse 
comments on the 2016 rule. However, the 2016 rule was correct--the 
EPA's 1979 listing of the source category should be considered to have 
included the transmission and storage segment.
    The commenters' argument stems from the fact that the 1979 listing, 
44 FR 49222 (Aug. 21, 1979) (1979 Listing Rule), identified the source 
category as ``Crude Oil and Natural Gas Production,'' and did not 
specifically identify the transmission and storage segment as part of 
the source category. See 44 FR 49222 (citing Priorities for New Source 
Performance Standards Under the Clean Air Act Amendments of 1977, EPA-
450/3-78-019 (April 1978) (``1978 Priority List'')). This argument 
fails to recognize the comprehensive approach that the EPA undertook in 
the 1979 Listing Rule, which strongly indicates that the oil and gas 
source category included the transmission and storage segment. In the 
1979 Listing Rule, the EPA determined that numerous source categories 
met the CAA section 111(b)(1)(B) requirements to be listed for 
regulation. The EPA based that determination on a study it had 
undertaken in 1978, the 1978 Priorities List, that comprehensively 
identified all source categories in the United States--203 in number--
and indicated which ones should and should not be listed. That study 
identified the oil and gas source category as the ``Crude Oil and 
Natural Gas Production Plants,'' a name that referenced only the 
production segment of the oil and gas industry. However, the study, and 
the 1979 Listing Rule, which identified the source category as ``Crude 
Oil and Natural Gas Production,'' clearly intended the source category 
to be broader than just that segment, consistent with the fact that the 
1978 Priorities List was designed to be comprehensive. This is evident 
because in 1985, the EPA promulgated the first set of NSPS for the 
source category, which concerned sources in the processing segment, not 
the production segment. 50 FR 26122 (June 24, 1985) (VOC emissions from 
equipment leaks), 50 FR 40158 (Oct. 1, 1985) (SO<INF>2</INF> 
emissions). It is evident that the source category, as listed in 1979, 
also included the third major segment of the industry, the transmission 
and storage segment. Otherwise, the 1978 Priorities List, which was 
designed to be comprehensive, would have completely overlooked this 
major segment, which is not plausible.
ii. Alternative Determination in 2016 NSPS OOOOa To Include 
Transmission and Storage Segment in Source Category
    In addition, in the 2016 NSPS OOOOa, in the alternative, and on the 
assumption that the source category as listed in 1979 did not include 
the transmission and storage segment, the EPA revised the source 
category to include that segment, and relisted that source category--
which it termed the Crude Oil and Natural Gas source category--under 
CAA section 111(b)(1)(A). 81 FR 35832-40. This alternative 
determination further addresses commenters' objections.
    The EPA has broad discretion in determining the scope of the source 
category, which is reviewable under the arbitrary and capricious 
standard of CAA section 307(d)(9). In the 2016 NSPS OOOOa, the EPA 
determined that the transmission and storage segment was 
``interrelated'' with the production and processing segments and 
therefore should be included in the same source category, the EPA 
provided sound reasons for doing so. 81 FR 35832. This reasoning is 
consistent with the ordinary understanding of the term, ``category.'' 
Merriam-Webster defines ``category'' as ``any of several fundamental 
and distinct classes to which entities or concepts belong,'' \136\ and 
it defines a ``class [ ]'' as ``a group, set, or kind sharing common 
attributes.'' \137\ Treating all those

[[Page 16854]]

segments as part of the source category meets this definition because, 
as the EPA explained in the 2016 NSPS OOOOa, the segments all included 
operations that were a sequence of functions in a multi-step process 
that is necessary to achieve the common goal of preparing recovered gas 
for distribution. Moreover, the segments had common equipment and 
control technology. 81 FR 35832. In the 2016 rule, the EPA went on to 
assess the air pollutants emitted from the source category, including 
VOC, SO<INF>2</INF>, and GHG; as well as the associated air pollution, 
including hazardous air pollution, tropospheric ozone, SO<INF>2</INF>, 
and atmospheric GHG; and determined that the source category causes or 
contributes significantly to air pollution which may reasonably be 
anticipated to endanger public health or welfare. Id. 35840. The EPA 
has not reopened that endangerment finding.
---------------------------------------------------------------------------

    \136\ ``Category.'' Merriam-Webster.com Dictionary, Merriam-
Webster, https://www.merriamwebster.com/dictionary/category. 
Accessed Sept. 25, 2023.
    \137\ ``Class.'' Merriam-Webster.com Dictionary, Merriam-
Webster, https://www.merriamwebster.com/dictionary/class. Accessed 
Sept. 25, 2023.
---------------------------------------------------------------------------

    This re-listing addresses the commenters' objections concerning the 
regulation of sources in the transmission and storage segment. By 
properly including the segment in a source category and listing that 
source category under CAA section 111(b)(1)(A), the EPA established the 
predicate for such regulation.
b. Reliance on Rational Basis Test, and Rejection of Pollutant-Specific 
Significant Contribution Finding, for Regulating GHG From the Source 
Category
    In the 2016 NSPS OOOOa, the EPA interpreted CAA section 111 to 
authorize regulation of methane emissions from the oil and gas source 
category because the large amount of those emissions provided a 
rational basis for such regulation. 81 FR 35842. The EPA went on to 
determine that it had a rational basis to regulate methane emissions 
from the source category on grounds that, among other things, the oil 
and gas industry is the largest industrial emitter of methane in the 
U.S. Id. 35842-43. As stated in section III, human emissions of 
methane, a potent GHG, are responsible for about one third of the 
warming due to well-mixed GHGs, which makes methane the second most 
important human warming agent after carbon dioxide.\138\ The EPA has 
not reopened that determination in the present rulemaking.
---------------------------------------------------------------------------

    \138\ See preamble section III.A. for further discussion on the 
Crude Oil and Natural Gas Emissions and Climate Change, including 
discussion of the GHGs, VOCs and SO<INF>2</INF> Emissions on Public 
Health and Welfare.
---------------------------------------------------------------------------

    However, commenters asserted that under CAA section 111, a rational 
basis determination is insufficient as a predicate for regulation, and, 
instead, the EPA was required to determine that methane emissions from 
the oil and gas source category cause or contribute significantly to 
air pollution that is reasonably anticipated to endanger public health 
or welfare. Commenters took this same position in the 2016 NSPS OOOOa. 
For the reasons discussed immediately below, we disagree with 
commenters and we confirm the position in the 2016 rule. As we discuss 
further below, the 2016 rule also addressed commenters' objections by 
making a finding that the GHG emissions from the oil and gas source 
category contribute significantly to dangerous air pollution.
    CAA section 111 is clear in authorizing the EPA to regulate air 
pollutants from a listed source category if it has a rational basis for 
doing so, and does not require, or authorize the EPA to require, a 
pollutant-specific significant contribution finding or endangerment 
finding as a predicate for such regulation. CAA section 111(b)(1)(A) 
requires the EPA to ``publish . . . a list of categories of stationary 
sources'' for regulation, and to ``include a source category in such 
list if . . . it causes, or contributes significantly to, air pollution 
which may reasonably be anticipated to endanger public health or 
welfare.'' CAA section 111(b)(1)(B) provides that within a specified 
time after listing the source category, the EPA shall promulgate 
``standards of performance for new sources within such category.'' CAA 
section 111(a)(1) defines ``standard of performance'' (in the singular) 
as ``a standard for emissions of air pollutants'' that is determined in 
a particular manner. CAA section 307(d)(1)(C) provides that the EPA's 
promulgation of standards of performance under CAA section 111 are 
subject to the requirements of CAA section 307(d). Those requirements 
include the judicial review provisions of CAA section 307(d)(9)(A), 
which provide that a court may reverse standards of performance ``found 
to be arbitrary, capricious, an abuse of discretion, or otherwise not 
in accordance with law.''
    By their terms, these provisions require the EPA to make an 
endangerment finding, including a significant contribution finding, for 
a source category as a predicate to promulgating standards of 
performance, and they establish detailed requirements that standards of 
performance must meet. However, by their terms, they do not require, or 
authorize the EPA to require, any significant contribution or 
endangerment findings for particular air pollutants as a predicate to 
promulgating such standards. Instead, the EPA's promulgation of such 
standards is subject to the CAA section 307(d)(9)(A) arbitrary and 
capricious standard for judicial review. See American Electric Power 
Co. v. Connecticut, 564 U.S. 410, 424, 427 (2011). In contrast, 
numerous other provisions explicitly require a pollutant-specific 
contribution or endangerment finding. See, e.g., CAA section 
183(f)(1)(A), 202(a)(1), 211(c)(1)(A), 213(a)(1)-(3), 231(a)(2). The 
inclusion of clear requirements for pollutant-specific findings in 
other CAA provisions confirms that the absence of such a requirement in 
CAA section 111 indicates Congress' intention not to include such a 
requirement there. See United States v. Gonzales, 520 U.S. 1, 5 (1997) 
(``Where Congress includes particular language in one section of a 
statute but omits it in another section of the same Act, it is 
generally presumed that Congress acts intentionally and purposely in 
the disparate inclusion or exclusion.'') (internal quotations omitted).
    Importantly, the arbitrary and capricious standard is tantamount to 
a standard of reasonableness or rationality. See Motor Vehicle Mfrs. 
Ass'n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 42-
43 (1983) (Motor Vehicle Mfrs. Ass'n) (``[t]he scope of review under 
the `arbitrary and capricious' standard'' means that a court ``may not 
set aside an agency rule that is [, among other things,] rational''). 
In the 2016 NSPS OOOOa, the EPA termed this standard the rational basis 
test, and applied it to the promulgation of GHG standards of 
performance for the oil and gas source category. This standard of 
review is well established, and courts routinely review rules under it, 
as noted in the House Report at 11.
    On the other hand, requiring a pollutant-specific significant 
contribution finding as a predicate for promulgating NSPS would disrupt 
the scheme Congress set out because it would render the significant 
contribution and endangerment findings for the source category 
superfluous. This is because a finding that any particular air 
pollutant emitted from a source category contributes significantly to 
dangerous air pollution necessarily means that the source category 
itself contributes significantly to dangerous air pollution. See TRW 
Inc. v. Andrews, 534 U.S. 19, 31 (2001) (``It is a cardinal principle 
of statutory construction that a statute ought, upon the whole, to be 
so construed that, if it can be prevented, no clause, sentence, or word 
shall be superfluous. . . .'').

[[Page 16855]]

    The EPA's more than half-century long regulatory history of CAA 
section 111 is consistent with the rational basis test and provides no 
precedent for requiring or authorizing the EPA to require a pollutant-
specific significant contribution finding. The EPA first listed source 
categories and promulgated standards of performance for them in 1971, 
36 FR 5931 (Mar. 31, 1971) (listing initial source categories); 36 FR 
24876 (Dec. 23, 1971) (promulgating initial standards of performance), 
and since then, has listed dozens more source categories and 
promulgated hundreds of standards. 40 CFR part 60. The EPA has always 
listed source categories by determining that they contribute 
significantly to dangerous air pollution, and then has proceeded to 
promulgate NSPS for particular air pollutants from the source 
categories, without making comparable significant contribution or 
endangerment findings for those air pollutants.\139\ The EPA has 
followed this approach when it has promulgated standards of performance 
for particular air pollutants at approximately the same time that it 
listed the source category, see, e.g., 36 FR 5931 (Mar. 31, 1971) 
(listing five source categories); 36 FR 24876 (Dec. 23, 1971) 
(promulgating standards of performance for same five source 
categories), and when it has promulgated standards of performance for 
particular air pollutants for the first time many years after it listed 
the source category, and which it did not address when it listed the 
source category. See 38 FR 15380 (June 11, 1973) (listing the petroleum 
refineries source category), 39 FR 9310 (Mar. 8, 1974) (promulgating 
standards of performance for PM, CO, SO<INF>2</INF>, and opacity from 
the source category), 73 FR 35838 (June 24, 2008) (promulgating 
standards of performance for NO<INF>X</INF> and VOC from the source 
category).
---------------------------------------------------------------------------

    \139\ The only exceptions have been two rules in which the EPA 
made pollutant-specific significant contribution findings in the 
alternative. 80 FR 64510, 64531 (Oct. 23, 2015) (GHG NSPS for 
electric power plants); 2016 NSPS OOOOa, 81 FR 35843.
---------------------------------------------------------------------------

    In other rulemakings, the EPA declined to promulgate NSPS for 
certain air pollutants, on the basis of what amounted to a rational 
basis test, although the EPA did not use that specific terminology. See 
42 FR 22056, 22507 (May 3, 1977) (declining to promulgate NSPS for 
NO<INF>X</INF>, CO, and SO<INF>2</INF> from lime manufacturing plants 
due to limited amounts of emissions of pollutants or limited reductions 
that controls would achieve); National Lime Assoc. v. EPA, 627 F.2d 
416, 426 & n.27 (D.C. Cir. 1980). On the other hand, in rulemakings 
since 2009, the EPA has rejected comments that it was required to make 
a pollutant-specific significant contribution finding. See 74 FR 51950, 
51957 (Oct. 8, 2009) (NSPS for coal preparation and processing plant 
source category); 80 FR 64510, 64530 (Oct. 23, 2015) (NSPS for GHG from 
electric utility generation source category); 2016 NSPS OOOOa, 81 FR 
35843.
    It is clear that interpreting CAA section 111 to require, or 
authorize the EPA to require, a pollutant-specific significant 
contribution finding as a predicate for regulation is novel and departs 
from the EPA's lengthy history of promulgating standards of 
performance.\140\ This ``consistent and longstanding interpretation of 
the agency charged with administering the statute'' further supports 
interpreting CAA section 111 to base the promulgation of standards of 
performance on a rational basis standard, consistent with CAA section 
307(d)(9)(A), and not to require a pollutant-specific significant 
contribution finding. See Entergy Corp. v. Riverkeeper, Inc., 556 U.S. 
208, 235 (2009). Indeed, interpreting CAA section 111 to require, or 
authorize the EPA to require, a pollutant-specific significant 
contribution finding as a predicate for regulation would undermine the 
EPA's implementation of CAA section 111 to date, including, in 
particular, virtually all of the standards of performance the EPA has 
promulgated to date.
---------------------------------------------------------------------------

    \140\ The only actions in which CAA section 111 has been 
interpreted to require or authorize the EPA to require a pollutant-
specific significant contribution finding as a predicate for 
regulation are the 2020 Policy Rule, which was disapproved by the 
CRA joint resolution, and a January 2021 rule that purported to 
establish a significance threshold for GHG emissions from source 
categories, but that was adopted without notice-and-comment, and was 
vacated by the D.C. Circuit in April 2021. See ``Pollutant-Specific 
Significant Contribution Finding for Greenhouse Gas Emissions From 
New, Modified, and Reconstructed Stationary Sources: Electric 
Utility Generating Units, and Process for Determining Significance 
of Other New Source Performance Standards Source Categories--Final 
Rule,'' 86 FR 2542 (Jan. 13, 2021); California v. EPA, No. 21-1035 
(D.C. Cir. April 5, 2021) Doc. #1893155 (order granting motion for 
voluntary vacatur and remand).
---------------------------------------------------------------------------

    In addition, even if commenters are correct that CAA section 111 
requires a pollutant-specific finding, that finding should be simply a 
contribution, not a significant contribution. A contribution finding 
would be consistent with Congress's approach in other CAA provisions. 
See, e.g., CAA section 183(f)(1)(A), 202(a)(1), 211(c)(1), 231(a)(2). A 
significant contribution finding is illogical because it would render 
the source category significant contribution finding under CAA section 
111(b)(1)(A) superfluous, as noted above. By analogy, CAA section 
213(a)(4) explicitly requires the EPA make two findings, but 
differentiates them: (1) emissions from new nonroad engines or vehicles 
contribute significantly to an air pollution problem, and (2) emissions 
from classes or categories of new nonroad engines or vehicles cause or 
contribute to the air pollution problem. Accordingly, if CAA section 
111 were interpreted to require, or at least authorize, the EPA to 
require a pollutant-specific finding as a predicate for regulation, 
that finding should be that the source category's emissions of the 
pollutant cause or contribute to dangerous air pollution.
c. Lack of Redundancy of Regulation of Methane
    Commenters also argued that the GHG NSPS in the oil and gas source 
category are redundant to the VOC NSPS. Adverse commenters had made 
this objection during the 2016 NSPS OOOOa. We rejected it there and 
reject it here as well.
    In the 2016 rule, the EPA structured the requirements of the VOC 
and GHG NSPS to mirror each other, and it is that structure that forms 
the basis for commenters' argument that the GHG NSPS should be 
considered to be redundant. Because the EPA had listed the oil and gas 
source category for regulation, it was required to promulgate NSPS for 
GHG emissions under CAA section 111(b)(1)(B) (as long as doing so was 
rational), and that requirement is not eliminated by the fact that the 
GHG NSPS could be structured to mirror the VOC NSPS. Moreover, the fact 
that the 2016 rule structured the requirements as it did does not mean 
they are redundant, only that the EPA sought to allow sources to comply 
with them as efficiently as possible. Had the EPA not been careful to 
structure the two sets of NSPS to mirror each other, no argument would 
have arisen that the GHG NSPS were redundant, but that would have been 
an inefficient regulatory scheme.
    Most importantly, the GHG NSPS are not redundant because only they, 
and not the VOC NSPS, trigger the requirement that existing sources are 
subject to GHG emission guidelines under CAA section 111(d). The large 
contribution of methane emissions from the source category to dangerous 
air pollution driving the grave and growing threat of climate change 
means that, in the agency's judgment, it would be arbitrary and 
capricious under CAA section 307(d)(9)(A)--as well as highly 
irresponsible--for the EPA to decline to promulgate NSPS for methane 
emissions from the source category. See

[[Page 16856]]

American Electric Power, 564 U.S. at 426-27.
d. Alternative Determination in the 2016 NSPS OOOOa for a Pollutant-
Specific Endangerment Finding
    The 2016 NSPS OOOOa re-listing of the source category, described 
above, included another alternative determination that provided an 
additional basis for the regulation of GHG emissions, which was that 
the EPA explicitly determined that GHG emissions from the Crude Oil and 
Natural Gas source category cause or contribute significantly to 
dangerous air pollution. 81 FR 35833-40. This determination--which, to 
be clear, the EPA is not required to do, but nevertheless did so in the 
alternative--further addressed commenters' objections that the EPA was 
required to make such a pollutant-specific determination as a predicate 
for regulating methane emissions. The EPA has not reopened this 
determination.
    As noted above, this type of determination entails two findings, a 
significant contribution finding and a finding of dangerous air 
pollution. In this case, those findings were for GHG emissions. We 
refer to the former as the pollutant-specific significant contribution 
finding. In the 2016 rule, the EPA based the pollutant-specific 
significant contribution finding on the same facts concerning the large 
amount of methane emissions from the oil and gas source category that 
it relied on in making the rational basis determination, as noted 
above. Id. 35842-43. It made the finding of dangerous air pollution 
based on the endangerment finding for GHG that the EPA made under CAA 
section 202(a) in 2009 \141\ (the 2009 Endangerment Finding) and the 
2010 denial of petitions to reconsider,\142\ updated with more recent 
information. See Coalition for Responsible Regulation v. EPA, 684 F.3d 
102, 117-123 (D.C. Cir. 2012) (upholding the 2009 Endangerment Finding 
and 2010 denial of petitions to reconsider, and noting, among other 
things, the ``substantial . . . body of scientific evidence marshaled 
by EPA in support'').
---------------------------------------------------------------------------

    \141\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR 
66496 (Dec. 15, 2009).
    \142\ See ``EPA's Denial of the Petitions To Reconsider the 
Endangerment and Cause or Contribute Findings for Greenhouse Gases 
Under Section 202(a) of the Clean Air Act,'' 75 FR 49556 (August 13, 
2010).
---------------------------------------------------------------------------

    This pollutant-specific determination for GHG from the oil and gas 
source category addresses the commenters' arguments that the EPA cannot 
regulate GHG from the source category without making such a finding. 
See American Lung Ass'n v. EPA, 985 F.3d 914, 974-77 (D.C. Cir. 2021) 
(American Lung Ass'n) (the pollutant-specific significant-contribution 
finding that the EPA made in the alternative for GHG emissions from 
electric power plants provided a sufficient basis for regulation and 
addressed petitioners' arguments that the NSPS for GHG emissions from 
those sources was invalid due to lack of such a finding), rev'd in part 
sub nom West Virginia v. EPA, 142 S.Ct. 2587 (2022) (West 
Virginia).\143\
---------------------------------------------------------------------------

    \143\ It should be noted that the part of the D.C. Circuit's 
opinion in American Lung Ass'n concerning the pollutant-specific 
significant contribution finding was not affected by the Supreme 
Court's decision in West Virginia.
---------------------------------------------------------------------------

    Commenters also argued that an endangerment finding specifically 
for methane emissions--that is, a determination that methane emissions 
from the oil and gas source category cause or contribute significantly 
to atmospheric levels of methane, and that those levels may reasonably 
be anticipated to endanger public health or welfare--is necessary as a 
predicate for regulation of methane emissions from the source category. 
The EPA responded to the same comment in the 2016 NSPS OOOOa. 81 FR 
35841-42, 35877. The EPA is not reopening this issue, but for the 
purpose of providing information to the public, will explain why, 
assuming that a pollutant-specific determination is necessary as a 
predicate for CAA section 111 regulation, it is appropriate for the EPA 
to make the significant contribution finding on the basis of GHG 
emissions and for the EPA to rely on the finding of dangerous air 
pollution that it made for GHG, and it is not necessary for the EPA to 
make comparable determinations for methane emissions.
    The EPA's approach in the 2016 NSPS OOOOa to make the findings for 
GHG is fully consistent with other rulemakings in which this issue 
arose. The first was the 2009 Endangerment Finding. 74 FR 66496. CAA 
section 202(a)(1) requires the EPA to establish ``standards applicable 
to the emission of any air pollutant from any class or classes of new 
motor vehicles or new motor vehicle engines'' that ``in his judgment 
cause, or contribute to, air pollution which may reasonably be 
anticipated to endanger public health or welfare.'' The EPA explained 
that this provision sets forth a two-part test for regulatory action: 
first, whether the relevant air pollution may reasonably be anticipated 
to endanger public health or welfare, and second, whether emissions of 
any air pollutant from the class or classes of the sources in question 
(there, new motor vehicles) cause or contribute to this air pollution. 
74 FR 66505, 66516, 66536. The EPA explained that ``the air pollution 
can be thought of as the total, cumulative stock in the atmosphere, 
while the air pollutant can be thought of as the flow that changes the 
size of the total stock.'' 74 FR 66536 (emphasis omitted). The EPA went 
on to explain that the ``air pollution'' that it was determining 
endangered public health and welfare is the elevated atmospheric 
concentrations of ``the combined mix of six key directly-emitted, long-
lived and well-mixed greenhouse gases''--carbon dioxide, methane, 
nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur 
hexafluorides. Id. 66516-23. The EPA supported this conclusion by 
explaining, among other things, that these six gases have the common 
attributes regarding their climate effects. Id. 66517. For the same 
reasons, in the 2009 Endangerment Finding, the EPA also defined the air 
pollutant as GHG--a single air pollutant made up of the same six gases 
in an aggregate group for purposes of determining whether the air 
pollutant causes or contributes to the endangering air pollution. Id. 
66537. The EPA explained that ``they are all greenhouse gases that are 
directly emitted . . .; they are sufficiently long-lived in the 
atmosphere such that, once emitted, concentrations of each gas become 
well mixed throughout the entire global atmosphere; and they exert a 
climate warming effect by trapping outgoing, infrared heat that would 
otherwise escape to space. Moreover, the radiative forcing effect of 
these six greenhouse gases is well understood.'' Id. The EPA further 
explained that this definition of the GHG air pollutant was reasonable, 
even if emissions from the source category did not include all six 
gases. Id. In fact, in the 2009 Endangerment Finding, the EPA noted 
that the emissions from the relevant class or classes of new motor 
vehicles or new motor vehicle engines included only four of the gases. 
Id. 66538, 66541. As noted in section III.A.1 above, the oil and gas 
source category emits methane and CO<INF>2,</INF> although the limits 
established in this action focus on regulating GHG through requirements 
that are expressed in the form of limits on methane, as a constituent 
of the GHG air pollutant.
    In subsequent actions that entailed or referenced GHG endangerment 
findings, the EPA has taken the same position that the air pollution 
consists of the elevated atmospheric concentrations of these six 
greenhouse gases and the air pollutant consists of the mix of the same 
six gases. 81 FR 54422 (2016 GHG

[[Page 16857]]

endangerment and cause or contribute finding for certain aircraft under 
CAA section 231(a)(2)(A)). The EPA took this same position in the 2016 
NSPS OOOOa, as mentioned at the beginning of this section. 81 FR 35833, 
35877. For the same reasons that the EPA has consistently articulated 
in the 2009 Endangerment Finding and afterwards, it is appropriate to 
base that determination on the contribution of GHG emitted from the 
source category to atmospheric GHG levels. This is because, as noted 
above, the 2016 rule identifies the air pollutant as GHG, even though 
it expresses the requirements in the form of limits on methane. 40 CFR 
60.5360a. Any significant contribution finding must address the 
pollutant being regulated, in this case, GHG. In addition, for the 
finding of dangerous air pollution, the air pollution of concern is the 
elevated concentration of the six well-mixed greenhouse gases, and not 
only concentrations of methane.
e. Standards or Criteria for Determining Significance
    Commenters argued that when the EPA makes a significant 
contribution determination for the pollutant and the source category as 
a predicate for regulation, the EPA must first establish a standard or 
criteria for when a contribution is significant.\144\ They stated that 
such a standard or criteria is necessary to allow the EPA to 
distinguish between a contribution and a significant contribution, and 
that without it, the significant contribution finding is arbitrary. The 
EPA disagrees with this comment. Rather, it is fully appropriate for 
the EPA to exercise its discretion to employ a facts-and-circumstances 
approach, particularly in light of the wide range of source categories 
and the air pollutants they emit that the EPA must regulate under CAA 
section 111.
---------------------------------------------------------------------------

    \144\ 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)).
---------------------------------------------------------------------------

    With respect to the significant contribution finding for a source 
category, CAA section 111(b)(1)(A) by its terms does not require that 
such a finding be based on established criteria or a standard or 
threshold. In fact, during the 50 years that it has listed dozens of 
source categories,\145\ the EPA has never identified a standard or 
criteria for determining significance, and instead, has always relied 
on the particular facts and circumstances. This approach is appropriate 
because Congress intended that CAA section 111 apply to a wide range of 
source categories and pollutants, from wood heaters to emergency backup 
engines to petroleum refineries. In that context, it is reasonable to 
interpret CAA section 111 to allow the EPA the discretion to determine 
how best to assess significant contribution and endangerment based on 
the individual circumstances of each pollutant and each source 
category. For example, among the six well-mixed gases that comprise 
GHG, CO<INF>2</INF> is emitted in the greatest quantities while methane 
emissions have a greater impact than CO<INF>2</INF> emissions on a per-
ton basis. In addition, source categories that emit the same air 
pollutant may differ from each other in several ways that may be 
relevant for purposes of a significance finding, including whether new 
sources are expected to be constructed.
---------------------------------------------------------------------------

    \145\ List of Categories of Stationary Sources, 36 FR 5931 
(March 31, 1971); see 40 CFR part 60.
---------------------------------------------------------------------------

    With respect to any significant contribution finding for an air 
pollutant--and as noted above, CAA section 111 does not require one as 
a predicate for regulation--established criteria or standards are also 
not required. The D.C. Circuit adopted this position in American Lung 
Ass'n, 985 F.3d at 976-77, when it upheld the EPA's pollutant-specific 
significant-contribution finding for GHG emissions from electric power 
plants even though the EPA did not ``articulate a specific threshold 
measurement for significance.'' The court relied on the same reasoning 
that it used when, in upholding the 2009 Endangerment Finding, it 
rejected an argument that the EPA must establish criteria in order to 
determine that an air pollutant endangers public health and welfare. 
Coal. for Responsible Regulation, Inc. v. EPA, 684 F.3d 102 (D.C. Cir. 
2012). The court stated that ``EPA need not establish a minimum 
threshold of risk or harm before determining whether an air pollutant 
endangers'' because ``the inquiry necessarily entails a case-by-case, 
sliding-scale approach.'' Id. at 122-23. Although there, the court was 
discussing whether an air pollutant endangers public health or welfare, 
the court later, in American Lung Ass'n, made clear that the same 
principle applies to whether an air pollutant contributes significantly 
to dangerous air pollution. On this point, as well, the EPA is in full 
agreement with the statements in the House Report stating that the EPA 
is not required to base a significance finding on an established 
standard or criteria. House Report at 9-10.
    Commenters who interpret CAA section 111 to require a pollutant-
specific significant contribution finding rely on the requirement in 
CAA section 111(b)(1)(A) for a source-category significant endangerment 
finding. By that logic, the facts-and-circumstances method by which the 
EPA has always determined the source category significant-contribution 
finding should also apply to any pollutant-specific significant 
contribution finding. See Alaska Dep't of Envtl. Conservation, 540 U.S. 
461, 487 (2004) (explaining, in a case under the CAA, ``[w]e normally 
accord particular deference to an agency interpretation of longstanding 
duration'' (internal quotation marks omitted) (citing Barnhart v. 
Walton, 535 U.S. 212, 220 (2002)). In fact, in each of the first two 
rules in which the EPA made a pollutant-specific significant 
contribution finding as an alternative basis for regulating GHG from 
the relevant source category, the EPA relied on a facts-and-
circumstances test for determining significance. 80 FR 64531 (NSPS for 
GHG from electric power plants); 2016 NSPS OOOOa, 81 FR 35843.\146\ The 
EPA's long track record for basing CAA section 111 significance 
findings on an examination of facts and circumstances, and not relying 
on established criteria or other standards or thresholds, coupled with 
the importance of allowing the EPA the flexibility to take into account 
the particular circumstances of the pollutant and the source category, 
makes clear that a lack of such criteria or standards does not render 
the significance determinations arbitrary and capricious. The courts 
have long reviewed agency actions under the arbitrary-and-capricious 
standard without requiring quantitative or numerical standards. See 
Motor Vehicle Mfrs. Ass'n, 463 U.S. 42-43 (stating that the court ``may 
not set aside an agency rule that is rational, based on consideration 
of the relevant factors and within the scope of the authority delegated 
to the agency by the statute'').
---------------------------------------------------------------------------

    \146\ As noted above, a January 2021 rule, promulgated without 
notice and comment and vacated by the D.C. Circuit, took the 
position that standards or criteria for a pollutant-specific 
significant contribution finding are necessary. 86 FR 2542; 
California v. EPA, No. 21-1035 (D.C. Cir. April 5, 2021) Doc. 
#1893155 (order granting motion for voluntary vacatur and remand).
---------------------------------------------------------------------------

    Other CAA provisions require the EPA to make a pollutant-specific 
determination, and the EPA's actions under these provisions are 
informative here as well. The EPA has implemented some of these 
provisions through a facts and circumstances test, see 59 FR 31308 
(June 17, 1994) (under CAA section 213, in determining whether 
emissions from nonroad engines and vehicles contribute significantly to 
dangerous air pollution, the EPA made a qualitative assessment, and 
rejected assertions by commenters

[[Page 16858]]

that it was required to determine a specific numerical standard for 
significance); and has implemented some of these provisions through 
both a facts and circumstances test and criteria or standards. See 84 
FR 50268 (Sept. 24, 2019) (proposal for 2020 Policy Rule; discusses EPA 
action under CAA section 189(e), which requires the EPA to regulate 
sources of precursors to PM<INF>10</INF> except where EPA determines 
such sources do not contribute significantly to PM<INF>10</INF> levels 
that exceed the NAAQS; EPA has determined significance through a 
combination of a facts-and-circumstances test and criteria); compare 
id. at 50267-68 (discussing EPA's implementation of CAA section 
110(a)(2)(D)(i), the Good Neighbor Provision, which requires states to 
prohibit emissions ``in amounts which will contribute significantly to 
nonattainment'' of the NAAQS in any other state; in rules concerning 
ozone and PM<INF>2.5,</INF> the EPA has identified a numerical 
criterion for determining significant contribution) with 84 FR 54498, 
54499 (October 10, 2019) (in rules under the Good Neighbor Provision 
concerning the SO<INF>2</INF> NAAQS, EPA has applied a weight of 
evidence (that is, evaluating all available facts and circumstances) 
test for determining whether there is significant contribution). The 
fact that the EPA has sometimes relied on a facts-and-circumstances 
test for determining significance in these CAA provisions supports its 
view that such a test is reasonable under CAA section 111.
    If the EPA were required to develop a standard or criteria to 
determine significance, any reasonable standard or criteria would 
necessarily focus on the amount of emissions from the source category 
and the harmfulness of the pollutant emitted. In the case of the oil 
and gas source category, the ``massive quantities of methane 
emissions'' contributed by the sector to the levels of well-mixed GHG 
in the atmosphere, as described in the November 2021 Proposal, 86 FR 
63148, coupled with the potency of methane (with a global warming 
potential (GWP) of almost 30 or more than 80, depending on the time 
period of the impacts, id. 63130), demonstrate that the source 
category's GHG emissions would be significant under any reasonable 
criteria-based approach. See 86 FR 63131.
    In particular, the fact that the oil and gas source category has 
the largest amount of methane emissions in the United States, in the 
context of a problem such as climate change that is caused by the 
collective contribution of many different sources, confirms that those 
emissions would meet any reasonable standard or criteria for 
significance.\147\ See American Lung Ass'n, 985 F.3d at 977 (``The 
global nature of the air pollution problem means that `[a] country or a 
source may be a large contributor, in comparison to other countries or 
sources, even though its percentage contribution may appear relatively 
small' in the context of total emissions worldwide.'' (quoting 2009 
Endangerment Findings). In fact, as noted above and discussed at 
further length in the December 2022 Supplemental Proposal, 87 FR 74719-
20, the oil and gas source category's position as the largest methane-
emitting source category in the U.S. would itself qualify as a 
criterion that supports treating it as a significant contributor of 
methane, if such a criterion were necessary.
---------------------------------------------------------------------------

    \147\ The EPA acknowledges that the collective nature of the 
climate change problem means that other source categories of methane 
emissions that are not necessarily as large as the oil and gas 
source category may also require regulation, 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 the 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 necessarily 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 of concern and 
when regulation would have produced little environmental benefit for 
other reasons. 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)).
---------------------------------------------------------------------------

2. Commenters' Arguments Concerning the CRA Joint Resolution and its 
Legislative History
    Commenters dismiss the significance of the CRA joint resolution 
that disapproved the 2020 Policy Rule by arguing that although the 
joint resolution had the effect of reinstating the 2016 NSPS OOOOa, it 
did not change the underlying requirements of CAA section 111, so that 
the flaws the commenters perceived in the 2016 rule's positions 
remained. The commenters further argue that the legislative history of 
the joint resolution that supported the 2016 rule's positions is 
irrelevant. We disagree with these commenters. Under the CRA, the 
enactment of the joint resolution not only disapproved the 2020 Policy 
Rule and had the effect of reinstating the 2016 rule, it also 
prohibited the EPA from promulgating another rule that is 
``substantially the same'' as the 2020 Policy Rule. CRA section 
801(b)(2). The joint resolution, confirmed by its legislative history, 
made clear what rules would and would not be prohibited. The 
commenters' arguments, if accepted, would lead to the adoption of a 
rule that would be considered substantially the same as the 2020 rule, 
and for that reason, their arguments must be rejected. In this section, 
we provide background information concerning the CRA and the role of 
legislative history, we summarize the discussion in the joint 
resolution's legislative history, and then we explain why commenters' 
arguments must be rejected.
    a. The CRA Joint Resolution of Disapproval
    Congress enacted the CRA in 1996 to facilitate Congressional 
oversight of agency action by streamlining the process for adopting 
legislation to disapprove agency rules.\148\ The CRA provides the 
specific wording for a joint resolution of disapproval for an agency 
action, which is a sentence that states (including the standard 
prefatory phrase for a joint resolution): ``Resolved by the Senate and 
House of Representatives of the United States of America in Congress 
assembled, That Congress disapproves the rule submitted by the __ 
relating to __, and such rule shall have no force or effect.'' 5 U.S.C. 
802(a). The blank spaces are for the name of the agency and the rule. 
The CRA further provides that after Congress adopts a joint resolution 
of disapproval of an agency rule, the agency is precluded from 
promulgating a new rule that is ``substantially the same'' as the 
disapproved rule, absent a new act of Congress authorizing such a rule. 
CRA section 801(b)(2).
---------------------------------------------------------------------------

    \148\ Congressional Research Service, ``The Congressional Review 
Act (CRA): Frequently Asked Questions (Jan. 14, 2020) at 1-2.
---------------------------------------------------------------------------

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

[[Page 16859]]

simply a one-sentence disapproval of the agency action, as noted above.
b. CRA Joint Resolution of Disapproval of the 2020 Policy Rule
    The joint resolution of disapproval of the 2020 Policy Rule 
provided, consistent with the form mandated under the CRA, ``Resolved 
by the Senate and House of Representatives of the United States of 
America in Congress assembled, That Congress disapproves the rule 
submitted by the Administrator of the Environmental Protection Agency 
relating to ``Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources Review'' (85 FR 57018 (September 
14, 2020)), and such rule shall have no force or effect.'' \149\ In 
adopting it, Congress explained its understanding of CAA section 111 
and, based on that, its reasons why the 2020 Policy Rule was 
inconsistent with CAA section 111 and must be disapproved. 
Specifically, as discussed in the November 2021 Proposal and summarized 
above, the Senate floor debate over the joint resolution and the House 
Report made clear Congress's views concerning the relevant provisions 
of CAA section 111 and the statutory interpretations contained in the 
2016 NSPS OOOOa and the 2020 Policy Rule, and its intention that the 
EPA take further rulemaking action consistent with those views. Thus, 
the legislative history made clear that Congress (i) intended the EPA 
to treat the transmission and storage segment as part of the Crude Oil 
and Natural Gas Production source category and to promulgate NSPS and 
emission guidelines for GHG from the source category, (ii) viewed the 
2016 rule's statutory interpretations of CAA section 111 to be correct 
and to serve as the basis for these regulatory actions, and (iii) 
viewed the contrary statutory interpretations contained in the 2020 
rule to be incorrect. The statutory interpretations that Congress 
viewed to be correct include that the EPA is not authorized to 
promulgate a pollutant-specific significant contribution finding as a 
predicate for regulation, and that a facts and circumstances test for 
determining significant contribution for the source category listing is 
appropriate.
---------------------------------------------------------------------------

    \149\ S.J. Res.14--117th Congress, Public Law 117-23.
---------------------------------------------------------------------------

c. Commenters' Arguments and the EPA's Responses
    Commenters assert that while the CRA joint resolution disapproved 
the 2020 Policy Rule, that action did not extend to the legal rationale 
and policy positions in the 2020 rule, and did not endorse the legal 
rationale and policy positions in the 2016 rule. They also assert that 
only the text of the joint resolution--again, a single sentence, quoted 
above, stating that Congress disapproves the 2020 rule and it shall 
have no force or effect--is relevant, and that the legislative history 
is not relevant. The commenters then assert that the joint resolution 
did not change the requirements of CAA section 111. From there, they 
assert that CAA section 111 requires the interpretations and 
determinations that the 2020 Policy Rule made, including that in order 
for the EPA to promulgate NSPS for sources in the transmission and 
storage segment, the EPA must first list that segment as a separate 
source category, including making significant contribution and 
endangerment findings for it; and in order for the EPA to promulgate 
NSPS for GHG emissions from oil and gas sources, the EPA must first 
make a pollutant-specific significant contribution finding, including 
specifying a standard or criterion for significance.
    The EPA rejects the commenters' arguments. In essence, commenters 
seek to minimize the importance of the joint resolution in order to 
argue that the EPA must rescind most of the 2016 NSPS OOOOa on grounds 
that it is inconsistent with CAA section 111's requirements, as the 
commenters see them. However, such a rescission rule would be 
substantially the same as the 2020 Policy Rule, and is therefore 
precluded by the joint resolution.
    The central features of the disapproved 2020 Policy Rule were its 
position that the transmission and storage segment is separate from the 
production and processing segments; its position that a GHG-specific 
significant contribution finding, supported by standards or criteria 
for determining significance, was a necessary predicate for regulating 
GHG emissions; and the statutory interpretations that underlay those 
positions. In addition, the legislative history of the CRA resolution 
made clear that Congress disapproved the 2020 Policy Rule because it 
rejected those positions and the underlying legal interpretations. 
Thus, a rule that adopted the same positions and interpretations as the 
2020 Policy Rule would be precluded by the joint resolution as 
substantially the same as the 2020 Policy Rule.
    Looked at another way, the commenters' in essence argue that the 
EPA should withdraw the November 2021 Proposal and the December 2022 
Supplemental Proposal and instead propose and promulgate a rule stating 
that the EPA is not authorized to further regulate oil and gas sources, 
including promulgating emission guidelines, unless it lists the 
transmission and storage segment as a separate source category and 
makes a pollutant-specific significant contribution finding for 
GHGs,\150\ based on standards or criteria for determining significance. 
However, such a rule would also be precluded by the joint resolution as 
substantially the same as the key aspects of the 2020 Policy Rule 
because it would be based on the same statutory interpretations as that 
rule. Indeed, it is difficult to see what effect the disapproval would 
have if not to preclude the EPA from re-instating the positions and 
underlying legal interpretations included in the 2020 Policy Rule.
---------------------------------------------------------------------------

    \150\ As noted above, commenters' argument that the EPA must 
make a pollutant-specific significant contribution finding for GHG 
emissions from the source category has been addressed because the 
2016 NSPS OOOOA made such a finding in the alternative.
---------------------------------------------------------------------------

    These commenters also err in asserting that the legislative history 
is irrelevant. Agencies and courts regularly look to legislative 
history to inform their actions and decisions. This makes particular 
sense in the case of a CRA joint resolution given the very limited 
language Congress may use in the joint resolution itself. Commenters 
also argue that the EPA's position that the joint resolution of 
disapproval applies to the legal and policy positions in the 2020 
Policy Rule would call into question the interpretations of CAA section 
111 that the rule included that are noncontroversial and necessary to 
proper implementation of the provision. There is no reason to think 
that Congress would have objected to those interpretations, but in any 
event, this argument by commenters makes clear that the joint 
resolution's legislative history is useful because it clarifies which 
interpretations and positions in the rule that Congress did object to.
    After reviewing the text of the disapproval and, separately, the 
disapproval resolution's legislative history, the EPA is proceeding 
with further rulemaking under CAA section 111 for sources in the Crude 
Oil and Natural Gas source category. With the 2016 Rule reinstated by 
the operation of the CRA resolution, the EPA is revising and adding 
certain NSPS and is promulgating emission guidelines for existing 
sources. These actions apply to sources in the transmission and storage 
segment, and apply to methane emissions. This rule is fully consistent 
with the CRA joint resolution.

[[Page 16860]]

VI. Other Actions and Related Efforts

    This section of this preamble describes related state actions and 
other Federal actions regulating oil and natural gas emissions sources; 
industry and voluntary efforts to reduce methane emissions from this 
sector; and other EPA programs to reduce methane emissions, including 
the Methane Emissions Reduction Program that was signed into law as 
part of the Inflation Reduction of 2022. The final NSPS OOOOb and EG 
OOOOc include specific measures that build on the experience and 
knowledge the Agency and industry have gained through voluntary 
programs and previous regulatory efforts, as well as the leadership of 
the states in developing their own regulatory programs. The final NSPS 
OOOOb and EG OOOOc consists of reasonable, proven, cost-effective 
technologies and practices that reflect the evolutionary nature of the 
oil and natural gas industry and these proactive regulatory and 
voluntary efforts.
    At the same time, the final NSPS OOOOb and EG OOOOc reflect the 
EPA's unique authority and responsibility under the CAA to ensure that 
new and existing sources throughout the nation are subject to 
appropriate standards of performance through NSPS and approved state 
plans. By requiring all owners and operators of the sources regulated 
in this final rulemaking to limit methane emissions, the EPA intends to 
achieve methane emission reductions on a more consistent and 
comprehensive basis than has been achieved through current programs and 
efforts. Direct Federal regulation of methane and VOCs from new 
sources, combined with approved state plans that are consistent with 
the EPA's EG for methane from existing sources, will bring national 
consistency to the regulatory landscape, help promote technological 
innovation, and reduce both climate- and other health-harming pollution 
from a large number of sources that are either currently unregulated or 
where additional cost-effective reductions are available.

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

    The EPA recognizes that several states currently regulate emissions 
from the oil and natural gas industry.\151\ The EPA also recognizes 
that some of these state programs have been expanded and strengthened 
since the EPA began implementing its 2012 NSPS and subsequent 2016 
NSPS. These state-level efforts have been important in spurring the 
deployment of emission control technologies and practices, and 
developing a broad base of experience that has informed the final rule. 
At the same time, the EPA recognizes that state-level regulatory 
efforts cannot, alone, address the increasingly dangerous impacts of 
methane emissions on public health and welfare. State agencies regulate 
in accordance with their own authorities and within their own 
respective jurisdictions; as a result, there is considerable variation 
in the scope and stringency of such programs. Collectively, these 
programs do not fully address the range of sources and emission 
reduction measures contained in this rulemaking. The EPA is committed 
to working within its authority to provide opportunities to align its 
programs with these existing state programs in order to reduce 
regulatory redundancy where appropriate.
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    \151\ The EPA summarized examples of state programs in the 
November 2021 Proposal and November 2021 TSD. See 86 FR 63137 and 
Document ID No. EPA-HQ-OAR-2021-0317-0166.
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    In addition to states, certain Federal agencies also regulate 
aspects of the oil and natural gas industry pursuant to their own 
authorities. The EPA has maintained an ongoing dialogue with its 
Federal partners during the development of this final rulemaking in 
order to avoid potential regulatory conflicts and unnecessary 
regulatory obligations on the part of owners and operators as each 
agency responds to its particular statutory charge.
    The below description summarizes other Federal regulations and 
programs related to air emissions from the oil and natural gas 
industry. The U.S. Department of the Interior (DOI) regulates the 
extraction of oil and gas from Federal and Indian lands. DOI bureaus 
that are responsible for administering natural resources conservation 
and safety related to onshore and offshore energy development include 
the Bureau of Land Management (BLM) (Federal onshore fossil fuel 
related activities), the Bureau of Safety and Environmental Enforcement 
(Federal offshore safety and environmental protection of oil and gas 
development), and the Bureau of Ocean Energy Management (BOEM) (Federal 
offshore oil and gas related activities). The BLM manages the Federal 
Government's onshore subsurface mineral estate--about 700 million acres 
(30 percent of the U.S.)--for the benefit of the American public. The 
BLM maintains the Federal onshore oil and gas leasing program pursuant 
to the Mineral Leasing Act, the Mineral Leasing Act for Acquired Lands, 
the Federal Land Management and Policy Act, and the Federal Oil and Gas 
Royalty Management Act. The BLM's oil and gas operating regulations are 
found in 43 CFR part 3160. An oil and gas operator's general 
environmental and safety obligations for onshore activities are found 
at 43 CFR 3162.5. Pursuant to a delegation of Secretarial authority, 
the BLM also oversees oil and gas operations on many Indian/Tribal 
leases.
    The BLM has the express authority and responsibility to regulate 
both for the prevention of waste and the protection of the environment 
for operations on Federal and Indian lands. This responsibility 
includes promulgating regulations to reduce the waste of natural gas 
from oil and gas leases administered by the BLM. This gas is lost 
during oil and gas exploration and production activities through 
venting, flaring, and leaks. More detailed information can be found at 
the BLM's website: https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production/methane-and-waste-prevention-rule.
    BOEM manages the development of U.S. Outer Continental Shelf 
(offshore) energy and mineral resources. BOEM has air quality 
jurisdiction in the Gulf of Mexico \152\ and the North Slope Borough of 
Alaska.\153\ BOEM also has air jurisdiction in Federal waters on the 
Outer Continental Shelf 3-9 miles offshore (depending on the state) and 
beyond. The Outer Continental Shelf Lands Act (OCSLA), section 5(a)(8) 
states, ``The Secretary of the Interior is authorized to prescribe 
regulations `for compliance with the national ambient air quality 
standards pursuant to the CAA . . . to the extent that activities 
authorized under [the Outer Continental Shelf Lands Act] significantly 
affect the air quality of any state.' '' The EPA and states have the 
air jurisdiction onshore and in state waters, and the EPA has air 
jurisdiction offshore in certain areas. More detailed information can 
be found at BOEM's website: https://www.boem.gov/.
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    \152\ The CAA gave BOEM air jurisdiction west of 87.5 degrees 
longitude in the Gulf of Mexico region.
    \153\ The Consolidated Appropriations Act of 2012 gave BOEM air 
jurisdiction in the North Slope Borough of Alaska.
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    The U.S. Department of Transportation (DOT) manages the U.S. 
transportation system. Within DOT, the Pipeline and Hazardous Materials 
Safety Administration (PHMSA) is responsible for regulating and 
ensuring the safe and secure transport of energy and other hazardous 
materials to industry and consumers by all modes of transportation, 
including pipelines.

[[Page 16861]]

While PHMSA regulatory requirements for gas pipeline facilities have 
focused on human safety, which has attendant environmental co-benefits, 
the ``Protecting our Infrastructure of Pipelines and Enhancing Safety 
Act of 2020'' (Pub. L. 116-260, Division R; ``PIPES Act of 2020''), 
which was signed into law on December 27, 2020, revised PHMSA organic 
statutes to emphasize the centrality of environmental safety and 
protection of the environment in PHMSA decision making. For example, 
the PHMSA's Office of Pipeline Safety ensures safety in the design, 
construction, operation, maintenance, and incident response of the 
U.S.' approximately 3.3 million miles of natural gas and hazardous 
liquid transportation pipelines. When pipelines are maintained, the 
likelihood of environmental releases like leaks are reduced.\154\ In 
addition, the PIPES Act of 2020 contains several provisions that 
specifically address the minimization of releases of natural gas from 
pipeline facilities, such as a mandate that the Secretary of 
Transportation promulgate regulations related to gas pipeline LDAR 
programs. More detailed information can be found at PHMSA's website: 
https://www.phmsa.dot.gov/.
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    \154\ See Final Report on Leak Detection Study to PHMSA. 
December 10, 2012. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf.
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    The U.S. Department of Energy (DOE) develops oil and natural gas 
policies and funds research on advanced fuels and monitoring and 
measurement technologies. Specifically, the Advanced Research Projects 
Agency-Energy (ARPA-E) program advances high-potential, high-impact 
energy technologies that are too early for private-sector investment. 
APRA-E awardees are unique because they are developing entirely new 
technologies. More detailed information can be found at ARPA-E's 
website: https://arpa-e.energy.gov/. Also, the U.S. Energy Information 
Administration (EIA) compiles data on energy consumption, prices, 
including natural gas, and coal. More detailed information can be found 
at the EIA's website: https://www.eia.gov/.
    The U.S. Federal Energy Regulatory Commission (FERC) is an 
independent agency that regulates the interstate transmission of 
electricity, natural gas,\155\ and oil.\156\ FERC also reviews 
proposals to build liquefied natural gas terminals and interstate 
natural gas pipelines, and licenses hydropower projects. FERC's 
responsibilities for the crude oil industry include the following: 
regulation of rates and practices of oil pipeline companies engaged in 
interstate transportation; establishment of equal service conditions to 
provide shippers with equal access to pipeline transportation; and 
establishment of reasonable rates for transporting petroleum and 
petroleum products by pipeline. FERC's responsibilities for the natural 
gas industry include the following: regulation of pipeline, storage, 
and liquefied natural gas facility construction; regulation of natural 
gas transportation in interstate commerce; issuance of certificates of 
public convenience and necessity to prospective companies providing 
energy services or constructing and operating interstate pipelines and 
storage facilities; regulation of facility abandonment, establishment 
of rates for services; regulation of the transportation of natural gas 
as authorized by the Natural Gas Policy Act and OCSLA; and oversight of 
the construction and operation of pipeline facilities at U.S. points of 
entry for the import or export of natural gas. FERC has no jurisdiction 
over construction or maintenance of production wells, oil pipelines, 
refineries, or storage facilities. More detailed information can be 
found at FERC's website: https://www.ferc.gov/.
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    \155\ https://www.ferc.gov/industries-data/natural-gas.
    \156\ https://www.ferc.gov/industries-data/oil.
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B. Industry and Voluntary Actions To Address Climate Change

    Separate from regulatory requirements, some owners or operators of 
facilities in the oil and natural gas industry choose to participate in 
voluntary initiatives to reduce methane emissions from their 
operations. Over 100 oil and natural gas companies have participated in 
the EPA Natural Gas STAR Program and Methane Challenge partnership over 
the past several decades. Owners or operators also participate in a 
growing number of voluntary programs unaffiliated with the EPA 
voluntary programs; the EPA is aware of at least 19 such 
initiatives.\157\ Firms participate in voluntary environmental programs 
for a variety of reasons, including attracting customers, employees, 
and investors who value more environmentally-responsible goods and 
services; finding approaches to improve efficiency and reduce costs; 
and preparing for or helping inform future 
regulations.<SUP>158 159</SUP>
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    \157\ Highwood Emissions Management (2021). ``Voluntary 
Emissions Reduction Initiatives for Responsibly Sourced Oil and 
Gas.'' Available for download at: https://highwoodemissions.com/research/.
    \158\ Borck, J.C. and C. Coglianese (2009). ``Voluntary 
Environmental Programs: Assessing Their Effectiveness.'' Annual 
Review of Environment and Resources 34(1): 305-324.
    \159\ Brouhle, K., C. Griffiths, and A. Wolverton. (2009). 
``Evaluating the role of EPA policy levers: An examination of a 
voluntary program and regulatory threat in the metal-finishing 
industry.'' Journal of Environmental Economics and Management. 
57(2): 166-181.
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    The EPA's Natural Gas STAR Program started in 1993 with the 
objective of achieving methane emission reductions through 
implementation of cost-effective best practices and technologies. 
Through the program, partner companies documented their voluntary 
emission reduction activities and reported their accomplishments to the 
EPA annually. Over the course of the Natural Gas STAR Partnership from 
1993 to 2022, the EPA collaborated with over 100 companies across the 
natural gas value chain. Through the partnership, the EPA tracked more 
than 150 different methane-reducing activities and technologies which 
it then shared among partners and through the program website. Between 
1993 and 2020, partner companies reported cumulative methane emissions 
reductions of nearly 1.7 trillion cubic feet.
    The EPA's Methane Challenge Program was launched in 2016 to expand 
upon the Natural Gas STAR Program by providing partner companies the 
opportunity to make ambitious, quantifiable emissions reduction 
commitments, provide detailed, transparent reporting, and receive 
partner recognition. Annually, Methane Challenge Partners submit 
facility-level reports that characterize methane emission sources at 
their facilities and detail voluntary actions taken to reduce methane 
emissions. The EPA emphasizes the importance of transparency by 
publishing these facility-level data. Since its inception, the Methane 
Challenge Program has included nearly 70 companies and currently has 54 
active partners, primarily from the transmission and distribution 
segments.
    Other voluntary programs for the oil and natural gas industry are 
administered by numerous organizations, including trade associations 
and non-profits. These voluntary efforts have helped reduce methane 
emissions beyond what is required by current regulations, as well as to 
significantly expand the understanding of methane mitigation measures 
within the industry and among Federal and state regulators. Although 
the EPA recognizes and commends the value of these programs, such 
voluntary efforts are not legally

[[Page 16862]]

binding and do not alter the EPA's own statutory responsibility to 
regulate methane emissions from this sector under the CAA. Moreover, as 
the information and analysis reflected in this final rulemaking make 
clear, there is still considerable need and opportunity to further 
reduce methane emissions from the industry.

C. Methane Emissions Reduction Program

    In August 2022, Congress passed, and President Biden signed, the 
Inflation Reduction Act of 2022 into law. Section 60113 of the 
Inflation Reduction Act of 2022 amended the CAA by adding section 136, 
``Methane Emissions and Waste Reduction Incentive Program for Petroleum 
and Natural Gas Systems'' (also referred to as the ``Methane Emissions 
Reduction Program'').
    Subsections (a) and (b) of CAA section 136 provide $1.55 billion 
for the Methane Emissions Reduction Program, including for incentives 
for methane mitigation and monitoring. The EPA is partnering with the 
DOE and National Energy Technology Laboratory to provide financial 
assistance for monitoring and reducing methane emissions from the oil 
and gas sector, as well as technical assistance to help implement 
solutions for monitoring and reducing methane emissions. As designed by 
Congress, these incentives were intended to complement the regulatory 
programs and to help facilitate the transition to a more efficient 
petroleum and natural gas industry.
    On August 1, 2023, the EPA proposed revisions to GHGRP subpart W 
consistent with the authority and directives set forth in CAA section 
136(h), as well as the EPA's authority under CAA section 114 (88 FR 
50282). In that rulemaking, the EPA proposed revisions to require 
reporting of additional emissions or emissions sources to address 
potential gaps in the total methane emissions reported by facilities to 
GHGRP subpart W. For example, these proposed revisions would add a new 
emissions source, referred to as ``other large release events,'' to 
capture large emissions events that are not accurately accounted for 
using existing methods in GHGRP subpart W. The EPA also proposed 
revisions to add or revise existing calculation methodologies to 
improve the accuracy of reported emissions, incorporate additional 
empirical data, and allow owners and operators of applicable facilities 
to submit empirical emissions data that could appropriately demonstrate 
the extent to which a charge is owed in implementation of CAA section 
136, as directed by CAA section 136(h). The EPA also proposed revisions 
to existing reporting requirements to collect data that would improve 
verification of reported data, ensure accurate reporting of emissions, 
and improve the transparency of reported data. Additionally, the EPA 
proposed revisions that would align GHGRP subpart W with other EPA 
programs and regulations, including proposing revisions to certain 
requirements in GHGRP subpart W relative to the requirements proposed 
for NSPS OOOOb and the presumptive standards proposed in EG OOOOc (such 
that, as applicable, facilities would use a consistent method to 
demonstrate compliance with multiple EPA programs once their emission 
sources are required to comply with either the final NSPS OOOOb or an 
approved state plan or applicable Federal plan in 40 CFR part 62).
    CAA section 136(c) directs the Administrator of the EPA to ``impose 
and collect a charge on methane emissions that exceed an applicable 
waste emissions threshold under subsection (f) from an owner or 
operator of an applicable facility that reports more than 25,000 metric 
tons of carbon dioxide equivalent (CO<INF>2</INF> Eq.) of GHG emitted 
per year pursuant to subpart W of part 98 of title 40 (40 CFR part 98), 
regardless of the reporting threshold under that subpart'' 
(hereinafter, waste emissions charge). An ``applicable facility'' is 
defined under CAA section 136(d) to include nine specific industry 
segments as defined in GHGRP subpart W. Pursuant to CAA section 136(g), 
the waste emissions charge ``shall be imposed and collected beginning 
with respect to emissions reported for calendar year 2024 and for each 
year thereafter.''
    CAA section 136(f) includes specific exemption from the waste 
emissions charge for certain applicable facilities that meet certain 
criteria, including what the EPA refers to as a ``regulatory compliance 
exemption.'' Specifically, CAA section 136(f)(6)(A) states that 
``charges shall not be imposed pursuant to subsection (c) on an 
applicable facility that is subject to and in compliance with methane 
emissions requirements pursuant to subsections (b) and (d) of section 
111 upon a determination by the Administrator that: (i) Methane 
emissions standards and plans pursuant to subsections (b) and (d) of 
section 111 have been approved and are in effect in all states with 
respect to the applicable facilities; and (ii) compliance with the 
requirements described in clause (i) will result in equivalent or 
greater emissions reductions as would be achieved by the proposed rule 
of the Administrator entitled `Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for 
Existing Sources: Oil and Natural Gas Sector Climate Review' (86 FR 
63110; (November 15, 2021), if such rule had been finalized and 
implemented.'' Per CAA section 136(f)(6)(B), ``if the conditions in 
clause (i) or (ii) of subparagraph (A) cease to apply after the 
Administrator has made the determination in that subparagraph, the 
applicable facility will again be subject to the charge under 
subsection (c) beginning in the first calendar year in which the 
conditions in either clause (i) or (ii) of that subparagraph are no 
longer met.''
    In the preamble to the December 2022 Supplemental Proposal, the EPA 
noted that implementation of CAA section 136 was outside the scope of 
the present rulemaking, and that the EPA intended to take one or more 
separate actions in the future to implement CAA section 136. However, 
the EPA requested comment on the criteria and approaches that the 
Administrator should consider in making the CAA section 
136(f)(6)(A)(ii) ``equivalency determination'' in such separate future 
action. Consistent with our statements in the December 2022 
Supplemental Proposal, the EPA is not taking any final actions to 
implement CAA section 136 in this action and these comments are 
therefore outside the scope of this final rule.

VII. Summary of Engagement With Pertinent Stakeholders

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

[[Page 16863]]

communities most affected by, and vulnerable to, the impacts of the 
rule.\160\
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    \160\ For a list of the EPA's engagement with pertinent 
stakeholders, please see Memorandum in EPA-HQ-OAR-2021-0317.
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    Prior to the November 2021 Proposal, the EPA opened a public docket 
for pre-proposal input.\161\ Throughout the rulemaking, the EPA engaged 
with pertinent stakeholders likely to be interested in this rulemaking 
in several ways, including through meetings, training webinars, round 
tables, public listening sessions, and a technical workshop. For 
example, the EPA hosted a two-part webinar training specifically 
targeted toward both communities with EJ concerns and Tribal nations on 
November 16 and 17, 2021. The purpose of this training event was for 
the EPA to facilitate stakeholder panel discussions and to provide 
background information and an overview of the November 2021 Proposal, 
as well as information on how to effectively engage in the regulatory 
process. Subsequently, on November 14, 2022, the EPA hosted a call for 
environmental groups and EJ communities; on November 17, 2022, the EPA 
held a webinar for both members of Tribal nations and communities; and 
on November 30, 2022, the EPA held a training for Tribal Environmental 
Professionals. In a second example, the EPA held a training for small 
businesses on May 25, 2021, November 18, 2021, and November 30, 2022, 
that provided an overview of how the oil and natural gas industry is 
regulated and offered information on how to participate in the 
rulemaking process. In a third example, the EPA held calls with the 
Association of Air Pollution Control Agencies and the National 
Association of Clean Air Agencies on December 6, 2022, and December 14, 
2022. In addition, on November 14, 2022, the EPA held a meeting with 
industry and labor groups to provide an overview of the proposed 
supplemental changes to the rulemaking. Throughout the rulemaking 
process the EPA has met individually with hundreds of industry 
representatives, NGOs, technology vendors, academics, data companies, 
and others.\162\ The EPA held 3-day virtual public hearings for all 
stakeholders on both the November 2021 Proposal and the December 2022 
Supplemental Proposal.
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    \161\ EPA Document ID No. EPA-HQ-OAR-2021-0317-0295.
    \162\ See various stakeholder meeting memoranda reflected in 
EPA's Docket ID No. EPA-HQ-OAR-2021-0317.
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    The EPA notes that the implementing regulations (40 CFR part 60, 
subpart Ba) require states to include a description of how they have 
engaged with pertinent stakeholders in the development of their state 
plans implementing the EG in their state plan submission to the EPA (to 
implement EG OOOOc). The EPA has led by example and demonstrated 
various examples of engagement with pertinent stakeholders so that 
states--while not limited by the EPA's outreach examples--will have a 
model for how they can structure their own outreach. For additional 
discussion on meaningful engagement as related to the development of 
state plans implementing the EG, please see section XIII.C.6 of this 
preamble.\163\
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    \163\ To better inform this final rulemaking, the EPA analyzed 
the characteristics of communities with EJ concerns. Please see the 
discussion in section XVI.F of this preamble and the RIA for 
additional information.
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VIII. Overview of Control and Control Costs

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

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

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

    Section 111 of the CAA requires the EPA to consider a number of 
factors, including cost, in determining ``the best system of emission 
reduction . . . adequately demonstrated.'' CAA section 111(a)(1). The 
D.C. Circuit has long recognized that ``[CAA] section 111 does not set 
forth the weight that [ ] should [be] assigned to each of these 
factors;'' therefore, ``[the court has] granted the agency a great 
degree of discretion in balancing them.'' Lignite Energy Council v. 
EPA, 198 F.3d 930, 933 (D.C. Cir. 1999). The courts have recognized 
that the EPA has ``considerable discretion under [CAA] section 111,'' 
id., on how it considers cost under CAA section 111(a)(1). As the 
Supreme Court has more recently noted, ``[i]t will be up to the Agency 
to decide (as always, within the limits of reasonable interpretation) 
how to account for cost.'' Michigan v. EPA, 576 U.S. 743, 759 (2015). A 
more detailed description of relevant case law guiding the EPA's 
consideration of costs is set forth in section IV.A of this document 
and in the November 2021 Proposal. See 86 FR at 63133, 63154 (November 
15, 2021). For the purposes of this final rule, we use the term 
``reasonable'' to describe costs which, based on our evaluation, are 
considered to be well within the boundaries of our discretion granted 
by Congress and recognized by the courts.
    As explained in further detail below, the EPA has determined that 
the costs of controls associated with the BSER for the final NSPS OOOOb 
and EG OOOOc are reasonable. In reaching this determination, the EPA 
conducted numerous cost analyses, described in detail in section XII of 
the November 2021 Proposal, Section IV of the December 2022 
Supplemental Proposal, and section XI of this preamble--all of which 
discuss the BSER determinations for each of the regulated emissions 
sources--and in the final rule TSD in the docket for this rulemaking.
    In evaluating whether the cost of a control is reasonable, the EPA 
considers various associated costs, including capital costs and 
operating costs, when evaluating the BSER for each emission source. In 
addition, as discussed further below, the Agency considered the costs 
of the collective standards for the final NSPS OOOOb and EG OOOOc in 
the context of the industry's overall capital expenditures and 
revenues. As discussed in more detail below, the capital expenditures 
in pollution control estimated to result from this

[[Page 16864]]

rulemaking represent 2-3 percent of the industry's annual capital 
expenditures. The estimated total annual expenditures represent less 
than one percent of the industry's annual revenue. Neither estimate 
includes increased industry revenue from the sales of captured gas 
resulting from pollution controls, which offsets some of these costs. 
At the same time, this rulemaking is estimated to reduce 58 million 
short tons of methane from 2024 to 2038--representing a 79 percent 
reduction in projected emissions from the sources covered in this 
rulemaking.\164\
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    \164\ The percent reduction is calculated as the ratio of the 
sum of estimated emissions reductions for the NSPS from 2024-2038 
and for the EG from 2028-2038 to the sum of estimated baseline 
emissions for the NSPS from 2024-2038 and for the EG from 2028-2038.
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    As discussed in more detail in the November 2021 Proposal, see 86 
FR 63154-7 (November 15, 2021), the EPA also considers a cost 
effectiveness analysis to be a useful metric, as it provides a means of 
evaluating whether a given control achieves emissions reduction at a 
reasonable cost and allows comparisons of relative costs and outcomes 
(effects) of two or more options. Cost effectiveness also provides a 
means of assessing consistency across rules regulating, and sectors 
regulated for, the same pollutant. In the context of an air pollution 
control option, cost effectiveness typically refers to the annualized 
cost of implementing an air pollution control measure divided by the 
amount of pollutant reductions realized annually. Notably, a cost 
effectiveness analysis is not intended to constitute or approximate a 
benefit-cost analysis in which monetized benefits are compared to 
costs, but rather is intended to provide a metric to compare the 
relative cost of emissions reductions. As explained in further detail 
in the November 2021 Proposal and the December 2022 Supplemental 
Proposal, the EPA estimated the cost effectiveness values of the 
various control options assessed for this rulemaking using the best 
information available to the Agency. The sources upon which the EPA 
relied in assessing cost effectiveness are described in detail in the 
TSDs and include studies by academia, non-governmental organizations, 
and state and Federal agencies. The EPA also relied upon costs and 
emissions data, as well as information related to technical 
limitations, submitted by members of the affected industry, including 
oil and gas production companies, and control device vendors and 
numerous other stakeholders,\165\ in the form of public comments in 
this rulemaking and previous rulemakings. The EPA also relied upon 
financial information provided by industry organizations that represent 
small businesses, such as the Michigan Oil & Gas Association 
(MOGA).\166\
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    \165\ For a more detailed summary of engagement and pertinent 
stakeholders that the EPA has engaged with, please see section VII 
of this preamble.
    \166\ See section XVII.C. of this preamble for summary of the 
EPA's final regulatory flexibility analysis (FRFA) for this action.
---------------------------------------------------------------------------

    The EPA used two approaches to determine cost effectiveness in this 
rulemaking. The first approach--the ``single-pollutant cost 
effectiveness approach''--assigns all costs to the emission reduction 
of one pollutant and zero costs to all other concurrent reductions; 
where the cost of the control is reasonable for reducing any of the 
targeted pollutants alone, the cost is reasonable for all concurrent 
emissions reductions (because these additional pollutants are reduced 
at no additional cost). The second approach--the ``multipollutant cost 
effectiveness approach''--apportions annualized cost of all pollutant 
reductions achieved by the control option in proportion to the relative 
percentage reduction of each pollutant controlled. A more detailed 
explanation of these approaches is set forth at 86 FR 63154-56 
(November 15, 2021) and 87 FR 74718-19 (December 6, 2022).
    As such, in the individual BSER analyses set forth in further 
detail section XII of the November 2021 Proposal, Section IV of the 
December 2022 Supplemental Proposal, and section XI of this preamble, 
for each control required in the final NSPS OOOOb, if a device is cost-
effective under either of these two approaches, it is considered cost-
effective. For EG OOOOc, which regulates only methane, a control is 
considered reasonable if it is cost-effective under the single-
pollutant cost effectiveness approach. In addition to evaluating the 
annual average cost effectiveness of a control option, the EPA also 
considered the incremental costs associated with increasing the 
stringency of emissions standards in determining the appropriate level 
of stringency. See 86 FR 63156 (November 15, 2021) and 87 FR 74718-19 
(December 6, 2022) for further details on incremental cost 
effectiveness analysis.
    The EPA provides the cost effectiveness estimates for reducing VOC 
and methane emissions for various control options considered in the 
November 2021 Proposal and the December 2022 Supplemental Proposal, as 
well as in section XI of this preamble and associated TSDs. With 
respect to VOC emissions, the EPA finds that cost effectiveness values 
up to $5,540/ton of VOC reduction are reasonable for controls that we 
have identified as BSER in the final NSPS OOOOb and EG OOOOc. These VOC 
values are within the range of what the EPA has historically considered 
to represent cost-effective controls for the reduction of VOC 
emissions, including in the 2016 NSPS, based on the Agency's long 
history of regulating a wide range of industries.\167\
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    \167\ The EPA has never established a bright line value with 
respect to cost effectiveness of VOC reductions under CAA section 
111, because the cost effectiveness conclusions in individual 
rulemakings can be influenced by a variety of factors. Nonetheless, 
the cost effectiveness values determined to be reasonable for VOC 
reductions in this action are consistent with values the EPA has 
determined to be reasonable in actions for other industries. See, 
e.g., 88 FR 29978 (May 9, 2023) (finding control measures available 
at $6,800/ton of VOC reduced reasonable for Automobile and Light 
Duty Truck Surface Coating Operations); 87 FR 35608 (June 10, 2022) 
(proposing to find control measures available for Bulk Gasoline 
Terminals with incremental cost effectiveness reasonable at $4,020/
ton of VOC reduced and unreasonable at $8,300/ton of VOC reduced).
---------------------------------------------------------------------------

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

[[Page 16865]]

For methane, the controls that we have identified as BSER in the final 
NSPS OOOOb and EG OOOOc to be reasonable at cost-effectiveness values 
up to $2,048/ton of methane reduction. The fact that the cost 
effectiveness estimates for the final standards in this action are 
comparable to (and in many individual instances, lower than) the cost 
effectiveness values estimated for the controls that served as the 
basis (i.e., BSER) for the standards in the 2016 NSPS OOOOa, which have 
been in place for years, reinforces the conclusion that the final NSPS 
and presumptive standards in this rule are also cost-effective and 
reasonable.
    As explained in further detail in the November 2021 Proposal, when 
determining the overall costs of implementation of the control 
technology and the associated cost effectiveness, the EPA takes into 
account cost savings from any natural gas recovered instead of vented 
as a result of the emissions controls. In our analysis, we consider any 
natural gas that is either recovered or not emitted as a result of a 
control option as being ``saved;'' we then apply the monetary value of 
the saved natural gas (estimated at $3.13 per Mcf),\168\ as an offset 
to the control cost. Notably, this offset does not apply where the 
owner or operator does not own the gas and would not likely realize the 
monetary value of the natural gas saved (e.g., transmission stations 
and storage facilities). Detailed discussions of this approach are 
presented in section 2 of the RIA and at 86 FR 63156 (November 15, 
2021).
---------------------------------------------------------------------------

    \168\ This value reflects the forecasted Henry Hub price for 
2022 from: U.S. Energy Information Administration. Short-Term Energy 
Outlook. https://www.eia.gov/outlooks/steo/archives/may21.pdf. 
Release Date: May 11, 2021.
---------------------------------------------------------------------------

    We also updated the two additional analyses that the EPA performed 
for both the November 2021 Proposal and the December 2022 Supplemental 
Proposal to further inform our determination of whether the cost of 
control of the collection of standards would be reasonable, similar to 
compliance cost analyses we have completed for other NSPS.\169\ The two 
additional analyses include: (1) a comparison of the capital costs 
incurred by compliance with the rulemaking to the industry's estimated 
new annual capital expenditures, and (2) a comparison of the annualized 
costs that would be incurred by compliance with the final NSPS and 
presumptive EG standards to the industry's estimated annual revenues. 
In this section, the EPA provides updated information regarding these 
cost analyses based on the standards described in this document. See 86 
FR 63156-7 (November 15, 2021) and 87 FR 74718-19 (December 6, 2022) 
for additional discussion on these two analyses. The results of both 
analyses, described in more detail in the following paragraphs, each 
independently demonstrate the reasonableness of the cost-effectiveness 
values applied in this final NSPS OOOOb and EG OOOOc, as well as 
demonstrate that the collective costs of the suite of final standards 
are reasonable in the context of the industry as a whole.
---------------------------------------------------------------------------

    \169\ For example, see our compliance cost analysis in 
``Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS 
Revision. Final Report.'' U.S. Environmental Protection Agency, 
Office of Air Quality Planning and Standards. EPA-452/R-15-001, 
February 2015.
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    First, for the capital expenditures analysis, the EPA divided the 
nationwide capital expenditures projected to be spent to comply with 
the standards finalized in this rulemaking by an estimate of the total 
sector-level new capital expenditures for a representative year; this 
calculation shows the percentage that the nationwide capital cost 
requirements under the final standards represent of the total capital 
expenditures by the sector. The EPA combined the compliance-related 
capital costs under the final standards for NSPS OOOOb and for the 
presumptive standards in the final EG OOOOc in order to analyze the 
potential aggregate impact of the rulemaking. The equivalent annualized 
value (EAV) of the projected compliance-related capital expenditures 
over the 2024 to 2038 period is projected to be about $2.5 billion in 
2019 dollars. We obtained new capital expenditure data for relevant 
NAICS codes for 2018-2021 from the 2019, 2020, and 2021 editions of the 
U.S. Census Annual Capital Expenditures Survey.\170\ According to these 
data, new capital expenditures for the sector ranged from $79 billion 
in 2021 to $156 billion in 2019 w in 2019 dollars.\171\ The wide range 
of annual expenditures across years are likely due to COVID-19-related 
impacts that dampened spending in 2020 and 2021. As such, while we 
conducted the analysis for all years from 2018 to 2021, we view the 
results for 2018 and 2019 as more representative of expected industry 
outlays going forward. Note that new capital expenditures in 2019 for 
pipeline transportation of natural gas (NAICS 4862) includes only 
expenditures on structures because data on equipment expenditures are 
withheld to avoid disclosing data for individual enterprises. As a 
result, the 2019 capital expenditures used here represent an 
underestimate of the sector's expenditures. Comparing the EAV of the 
projected compliance-related capital expenditures under this rule with 
the 2019 total sector-level new capital expenditures yields a 
percentage of about 1.6 percent, which is well below the percentage 
increase previously upheld by the courts as reasonable under CAA 
section 111. See detailed discussion at 86 FR 63156-7 (November 15, 
2021) (citing Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 437-40 
(D.C. Cir. 1973); Portland Cement Ass'n v. Train, 513 F.2d 506, 508 
(D.C. Cir. 1975)). The same comparison for 2021 total sector-level new 
capital expenditures yields a percentage of about 3.2 percent.
---------------------------------------------------------------------------

    \170\ 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 July 12, 2022.
    \171\ The total capital expenditures for the same NAICS codes 
during 2018 and 2020 were about $154 billion and $90 billion, 
respectively, in 2019 dollars.
---------------------------------------------------------------------------

    Second, for the comparison of compliance costs to revenues, we used 
the EAV of the projected compliance costs both with and without 
projected revenues from product recovery under the rule for the 2024 to 
2038 period, then divided the nationwide annualized costs by the annual 
revenues for the appropriate NAICS code(s) for a representative year in 
order to determine the percentage that the nationwide annualized costs 
represent of annual revenues. Like we do for capital expenditures, we 
combine the costs projected to be expended to comply with the standards 
for NSPS and the presumptive standards in the EG in order to analyze 
the potential aggregate impact of the rule. The EAV of the associated 
increase in compliance cost over the 2024 to 2038 period is projected 
to be about $2.7 billion without revenues from product recovery and 
about $1.7 billion with revenues from product recovery (in 2019 
dollars). Revenue data for relevant NAICS codes were obtained from the 
U.S. Census 2017 County Business Patterns and Economic Census, the most 
recent revenue figures available.\172\ According to these data, 2017 
receipts for the sector were about $357 billion in 2019 dollars. 
Comparing the EAV of the projected compliance costs under the 
rulemaking with the sector-level

[[Page 16866]]

receipts figure yields a percentage of about 0.8 percent without 
revenues from product recovery and about 0.5 percent with revenues from 
product recovery. More data and analysis supporting the comparison of 
capital expenditures and annualized costs projected to be incurred 
under the rule and the sector-level capital expenditures and receipts 
is presented in the TSD for this action, which is in the public docket.
---------------------------------------------------------------------------

    \172\ 2017 County Business Patterns and Economic Census. The 
Number of Firms and Establishments, Employment, Annual Payroll, and 
Receipts by Industry and Enterprise Receipts Size: 2017, https://www.census.gov/programs-surveys/susb/data/tables.2017.html, accessed 
October 16. 2023.
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    Based on all of the cost-related information, data, and analyses 
described above, and as explained in further detail in the individual 
sections describing the BSER for each control in this preamble, the 
November 2021 Proposal, and the December 2022 Supplemental Proposal, 
the EPA concludes that the costs of the controls that serve as the 
basis the final NSPS OOOOb and EG OOOOc are reasonable.
    Some commenters have argued that the EPA was required to perform a 
cost-benefit analysis of this rulemaking demonstrating that the costs 
outweigh the benefits, and have cited the Supreme Court's decision in 
Michigan v. EPA, 576 U.S. 743 (2015) in support of this contention. One 
commenter \173\ contends that the EPA's proposal is not reasonable if 
the climate benefits are illusory, and questions ``[w]hat benefit-cost 
calculation makes the proposed regulatory surge a smart investment of 
public and private resources.'' The commenter also takes issue with the 
EPA's statement in the Supplemental Proposal that our ``monetized 
benefits analysis is entirely distinct from the statutory BSER 
determinations proposed herein and is presented solely for the purposes 
of complying with E.O. 12866,'' 87 FR 74843. The commenter cites one 
excerpt from the Supreme Court's decision Michigan in support of its 
argument: ``One would not say that it is even rational, never mind 
`appropriate,' to impose billions of dollars in economic costs in 
return for a few dollars in health or environmental benefits . . . No 
regulation is `appropriate' if it does significantly more harm than 
good.'' 576 U.S. at 752. Another group of commenters \174\ quotes the 
same language from the case and asserts that the EPA must ``balance the 
costs associated with government regulation against compliance costs,'' 
and that the November 2021 Proposed Rule ``fails the cost-benefits 
test.''
---------------------------------------------------------------------------

    \173\ Document ID No. EPA-HQ-OAR-2021-0317-2359.
    \174\ Document ID No. EPA-HQ-OAR-2021-0317-0790.
---------------------------------------------------------------------------

    The EPA is mindful of the Supreme Court's holding in Michigan and 
has carefully considered how it applies to this rulemaking. The EPA 
disagrees with the commenters insofar as they suggest that the EPA was 
required--under Michigan or any other authority--to undertake a formal 
cost-benefit analysis in this rulemaking. In Michigan, the Supreme 
Court concluded that the EPA erred when it concluded it could not 
consider costs when deciding whether it is ``appropriate and 
necessary'' under CAA section 112(n)(1)(A) to regulate hazardous air 
pollutants from electric utility steam generating units (power plants), 
despite the relevant statutory provision containing no specific 
reference to cost. 576 U.S. at 751. In doing so, the Court held that 
the EPA ``must consider cost--including, most importantly, cost of 
compliance--before deciding whether regulation is appropriate and 
necessary'' under CAA section 112. Id. at 759. In examining the 
language of CAA section 112(n)(1)(A), the Court concluded that the 
phrase ``appropriate and necessary'' was ``capacious'' and held that 
``[r]ead naturally in the present context, the phrase `appropriate and 
necessary' requires at least some attention to cost.'' Id. at 752. This 
capaciousness was relevant in the context of section 112(n)(1)(A) 
because that section directs the EPA to determine ``whether to 
regulate'' the emission source, which is a context in which 
``[a]gencies have long treated cost as a centrally relevant factor.'' 
Id. at 753 (emphasis added).
    The Supreme Court added in Michigan that it ``need not and [does] 
not hold that the law unambiguously required the Agency, when making 
this preliminary estimate [of costs under the `appropriate and 
necessary' standard of CAA 112(n)(a)(1)], to conduct a formal cost-
benefit analysis in which each advantage and disadvantage is assigned a 
monetary value. It will be up to the Agency to decide (as always, 
within the limits of reasonable interpretation) how to account for 
cost.'' Id. at 759.
    Section 111 differs in material respects from the provision the 
Supreme Court interpreted in Michigan. Unlike the circumstances at 
issue in Michigan, the predicate decision whether to regulate the 
emission source has already been made here. CAA section 111(b)(1)(A) 
requires the Administrator to list a source category ``if, in his 
judgment, it causes or contributes significantly to, air pollution 
which may reasonably be anticipated to endanger public health or 
welfare.'' Notably, this provision does not hinge on a determination, 
like that under consideration in Michigan with respect to CAA section 
112, that such listing is ``appropriate and necessary.'' Indeed, the 
EPA has long regulated emissions from the oil and gas source category, 
having first listed the source category in 1979. And once the EPA has 
listed a source category, CAA section 111(b)(1)(B) and (d)(1) require 
the EPA to promulgate new source performance standards and, for certain 
pollutants, emission guidelines for regulation of existing sources. 
Pursuant to this authority, the EPA has regulated VOC emissions since 
1985 and GHG emissions (in the form of limitations on methane) since 
2016. See section IV.B for further explanation of the regulatory 
history for the source category; and section V for further discussion 
of the EPA's authority to promulgate methane regulations.
    Importantly, unlike the statutory provision at issue in Michigan, 
CAA section 111 already requires the EPA to consider costs when 
determining the appropriate level of control. Specifically, the 
``standards of performance'' for new and existing sources finalized in 
this rule are ``standard[s] for emissions of air pollutants which 
reflect[] the degree of emission limitation achievable through the 
application of the best system of emission reduction which (taking into 
account the cost of achieving such reduction and any nonair quality 
health and environmental impact and energy requirements) the 
Administrator determines has been adequately demonstrated.'' CAA 
section 111(a)(1) (emphasis added). Thus, even if the Court's 
examination of CAA 112(n)(a)(1) in Michigan did apply to CAA section 
111--which the EPA disputes--the EPA's decision here, unlike in the 
rule reviewed in Michigan, is not blind to costs. Rather, the EPA has 
satisfied the Court's directive to consider costs, both in the context 
of the individual BSER analyses for individual emissions source (as 
directed by the language of the statute) and in the context of the rule 
as a whole. Moreover, while the EPA is not required to undertake a 
``formal cost-benefit analysis in which each advantage and disadvantage 
[of a regulation] is assigned a monetary value,'' Michigan, 576 U.S. at 
759,\175\ the EPA has contemplated and carefully considered both the 
advantages and disadvantages of the final NSPS OOOOb and EG OOOOc, 
including the qualitative and quantitative benefits of

[[Page 16867]]

the regulation and the costs of compliance.
---------------------------------------------------------------------------

    \175\ Accordingly, the EPA disagrees with the commenters that 
the EPA was required to demonstrate that the monetized benefits of 
the regulations outweigh the costs, and the EPA does not rely on the 
analysis of costs and benefits conducted to comply with E.O. 12866 
for this purpose.
---------------------------------------------------------------------------

    The primary disadvantage that the EPA has weighed in finalizing the 
NSPS OOOOb and EG OOOOc is the cost of compliance and the effects of 
those costs on industry. Notably, neither CAA section 111 nor Michigan 
directs that costs be considered in any particular way, and in this 
action, the EPA has considered costs using the same cost metrics that 
the EPA has historically used in numerous rulemakings under CAA section 
111 for decades. As explained above, the EPA has used cost 
effectiveness as a metric to evaluate whether the costs associated with 
emissions reductions from a given technology are reasonable. This 
metric (widely used in environmental regulation) provides a way for the 
EPA to specifically consider the cost associated with each ton of 
reduction achieved by a particular control measure, and thereby 
determine whether the emission reductions achieved by the control 
measure are worthwhile, both as to the individual control measure in 
comparison to other available control measures, and in comparison to 
the regulation of the same pollutant in other industries. As explained 
in detail in section XI of this preamble, section XII of the November 
2021 Proposal, and Section IV of the December 2022 Supplemental 
Proposal discussing the BSER determinations for each of the regulated 
emissions sources, the EPA has also considered costs in various other 
ways, including capital costs and operating costs, when evaluating the 
reasonableness of various control measures to determine the BSER.
    In addition, the EPA conducted two cost analyses specifically for 
purposes of this action in order to evaluate the costs of compliance 
with the collective standards in the final NSPS OOOOb and EG OOOOc at a 
sector level and consider them in the context of the industry's overall 
capital expenditures and revenues. As explained in detail above, the 
EPA estimates that the capital costs expected to be incurred by 
compliance with the final NSPS OOOOb and EG OOOOc are about two to 
three percent of the industry's estimated new annual capital 
expenditures, and that the annualized compliance costs are less than 
one percent of the industry's estimated annual revenues. Notably, 
neither value includes increased industry revenue from the sales of 
captured gas resulting from pollution controls. Thus, while the 
industry will bear some costs to comply with the final NSPS OOOOb and 
EG OOOOc, each of these analyses supports the EPA's determination that 
the costs associated with compliance with the final standards are 
reasonable and consistent with costs of control that the source 
category has expended for years to comply with existing state and 
Federal standards, and on voluntary actions to reduce emissions.
    In terms of advantages, the final NSPS OOOOb and EG OOOOc will have 
numerous benefits to the climate, the natural environment, and human 
health through their projected reductions in methane and VOC emissions. 
Regarding methane, the oil and natural gas sector is the largest source 
of industrial methane emissions in the U.S. As described in greater 
detail in section III.B.2, it represents 28 percent of U.S. 
anthropogenic methane emissions and three percent of overall U.S. GHG 
emissions. Moreover, methane is a powerful and potent GHG--over a 100-
year timeframe, it is nearly 30 times more powerful at trapping climate 
warming heat than CO<INF>2</INF>, and over a 20-year timeframe, it is 
83 times more powerful. Because it is particularly potent and emitted 
in large quantities, methane mitigation provides one of the best 
opportunities to reduce near-term warming and offers important climate 
benefits.
    The projected methane emissions reductions from the final NSPS 
OOOOb and EG OOOOc standards, for each regulated emission source and 
taken together as a whole, will contribute to avoided climate and human 
health impacts, which are described in greater detail in section 
III.A.1 of this preamble, as well as in section III.A of the November 
2021 Proposal. Warming temperatures in the atmosphere, ocean, and land 
have led to, for example: increased numbers of heat waves, wildfires, 
and other severe weather events; reduced air quality; more intense 
hurricanes and rainfall events; and sea level rise. These environmental 
changes, along with future projected changes, endanger the physical 
survival, health, economic well-being, and quality of life of people 
living in the U.S., particularly those in the most vulnerable 
communities. As discussed in greater detail in section III.A.1, impacts 
from climate change driven by GHG emissions are wide-ranging in type 
and scope, and present serious threats to human life and the natural 
environment. For example, severe weather events and natural disasters 
exacerbated by climate change--such as droughts, floods, storm surges, 
wildfires, and heat waves--affect food security, air quality and 
respiratory health, availability of fresh drinking water, population 
stability, national security, participation in the workforce, and 
infrastructure and property, among many others. Other environmental 
impacts of climate change such as ocean acidification, altered plant 
growth, and increased concentrations of ozone also affect human health 
and well-being, in addition to that of the natural environment.
    The final NSPS OOOOb and EG OOOOc standards are projected to reduce 
58 million short tons of methane emissions from 2024 to 2038, which 
represents a 79 percent reduction in projected emissions from the 
sources covered in NSPS OOOOb and EG OOOOc. Accordingly, significantly 
reducing emissions of methane from the largest U.S. industrial source 
of this highly potent GHG will have meaningful climate benefits and 
environmental impacts, which will in turn have beneficial impacts on 
human health.
    As described in more detail in section III.A.2, reducing VOC 
emissions will also benefit human health and the environment. The oil 
and natural gas sector represents the top anthropogenic U.S. sector for 
VOC emissions (after removing the biogenics and wildfire sectors), 
which is about 23 percent of total VOCs emitted by U.S. anthropogenic 
sources. See section III.B.2. VOCs can cause a variety of health 
concerns, including cancerous and noncancerous illnesses, particularly 
respiratory and neurological ones. VOCs are also one of the key 
precursors in the formation of ozone. Tropospheric, or ground-level, 
ozone is formed through reactions of VOC and NOx in the presence of 
sunlight; ozone formation can be controlled to some extent through 
reductions in emissions of the ozone precursors VOC and NOx. Health 
effects of ozone exposure include premature death from lung or heart 
diseases, as well as harmful symptoms and the development of asthma. 
Repeated exposure to ozone can also have harmful effects on sensitive 
plants and trees, which have the potential to impact ecosystems and the 
services they provide. The final NSPS OOOOb and EG OOOOc standards are 
projected to reduce 16 million short tons of VOC emissions from 2024-
2038, which represent a 47 percent reduction in projected emissions 
from the sources covered in NSPS OOOOb and EG OOOOc.\176\ Significant 
reductions in

[[Page 16868]]

VOCs, like methane reductions, will have significant benefits to human 
health and the environment.
---------------------------------------------------------------------------

    \176\ The percent reduction is calculated as the ratio of the 
sum of estimated emissions reductions for the NSPS from 2024-2038 
and for the EG from 2028-2038 to the sum of estimated baseline 
emissions for the NSPS from 2024-2038 and for the EG from 2028-2038.
---------------------------------------------------------------------------

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

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

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

    NSPS OOOOb would apply to all emissions sources (``affected 
facilities'') identified in the final 40 CFR 60.5365b that commenced 
construction, reconstruction, or modification after December 6, 2022.
    Pursuant to CAA section 111(b), the EPA proposed NSPS for a wide 
range of emissions sources in the Crude Oil and Natural Gas source 
category in November 2021. Some of the proposed standards resulted from 
the EPA's review of the current NSPS codified at 40 CFR part 60 subpart 
OOOOa, while others were proposed standards for additional emissions 
sources that are currently unregulated. The emissions sources for which 
the EPA proposed standards in the November 2021 Proposal are as 
follows:
    <bullet> Well completions
    <bullet> Gas well liquids unloading operations
    <bullet> Associated gas from oil wells
    <bullet> Wet seal centrifugal compressors
    <bullet> Reciprocating compressors
    <bullet> Process controllers
    <bullet> Pumps
    <bullet> Storage vessels
    <bullet> Collection of fugitive emissions components at well sites, 
centralized production facilities, and compressor stations
    <bullet> Equipment leaks at natural gas processing plants
    <bullet> Sweetening units
    The EPA proposed standards for an additional emissions source, 
specifically dry seal centrifugal compressors, in the December 2022 
Supplemental Proposal, while also providing numerous significant 
updates to the standards previously proposed in the November 2021 
Proposal.
    These final standards of performance apply to ``new sources.'' CAA 
section 111(a)(2) defines a ``new source'' as ``any stationary source, 
the construction or modification of which is commenced after the 
publication of regulations (or, if earlier, proposed regulations) 
prescribing a standard of performance under this section which will be 
applicable to such source.'' While the initial rulemaking proposing the 
standards for these emission sources was published November 15, 2021, 
due to many significant updates included in the December 2022 
Supplemental Proposal, and the addition of dry seal centrifugal 
compressor proposed standards, the EPA is specifying that the ``new 
sources'' to which the final standards in NSPS OOOOb apply are those 
that commenced construction, reconstruction, or modification after 
December 6, 2022 (the date the supplemental proposal published in the 
Federal Register).
    We received comments on the November 2021 Proposal that the 
proposal lacked regulatory text and therefore should not be used to 
define new sources for purposes of NSPS OOOOb.\177\ The EPA disagrees 
that absence of a regulatory text in a proposal necessarily means that 
sources constructed after the date of the proposal cannot be ``new 
sources'' for purposes of an NSPS. Regardless, based on the unique 
facts and circumstances here, the EPA has concluded that only sources 
constructed, modified, or reconstructed after the date of the 
supplemental proposal should be considered new sources for the purposes 
of NSPS OOOOb.
---------------------------------------------------------------------------

    \177\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0424, -0539, -
0579, -0598, -0599, -0815, and -0929.
---------------------------------------------------------------------------

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

[[Page 16869]]

2021 Proposal and the December 2022 Supplemental Proposal was not vast. 
Within this single year, the EPA believes that a relatively modest 
number of sources commenced construction. While moving the 
applicability date for NSPS OOOOb does mean that these sources which 
commenced construction between the November 2021 Proposal and the 
December 2022 Supplemental Proposal will be considered ``existing 
sources'' for purposes of EG OOOOc instead of ``new sources'' under 
NSPS OOOOb, the EPA believes that this is an acceptable and preferred 
outcome when compared to the complexities associated with the 
alternative which are explained above. Notably, the EPA is also 
finalizing existing source EG in this action, which will ultimately 
require these sources to comply with standards of performance adopted 
in state plans under EG OOOOc.

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

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

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

    Sources currently subject to 40 CFR part 60, subpart KKK (NSPS 
KKK), 40 CFR part 60, subpart OOOO, or NSPS OOOOa would continue to 
comply with their respective VOC and methane standards until sources 
are subject to and in compliance with a state or Federal plan 
implementing EG OOOOc. While EG OOOOc specifically addresses methane 
and not VOC, any reductions from the methane standards established in a 
state or Federal plan implementing EG OOOOc will similarly reduce VOCs. 
Therefore, the EPA concludes that the methane presumptive standards in 
EG OOOOc will result in the same or greater emission reductions than 
the VOC and methane standards in previous NSPS KKK, NSPS OOOO, or NSPS 
OOOOa. Once sources are subject to and in compliance with a state or 
Federal plan implementing EG OOOOc, and if that plan is just as 
stringent as or more stringent than the presumptive standards in EG 
OOOOc, the source will be deemed to comply with the previous respective 
VOC NSPS, and no longer subject to the methane NSPS, and will comply 
with only the state or Federal plan implementing EG OOOOc. Because the 
EG OOOOc does not contain SO<INF>2</INF> standards, sources subject to 
SO<INF>2</INF> standards in NSPS OOOO or NSPS OOOOa would continue to 
comply with their respective SO<INF>2</INF> standards unless they 
modify and become subject to the requirements in NSPS OOOOb.
    In this rulemaking, the EPA is finalizing standards for dry seal 
centrifugal compressor and intermittent vent process controllers for 
the first time in NSPS OOOOb and presumptive standards in EG OOOOc. 
These designated facilities (i.e., dry seal centrifugal compressors and 
intermittent vent process controllers) are not subject to regulation 
under a previous NSPS. The EPA is also finalizing presumptive standards 
in EG OOOOc for fugitive emissions at compressor stations, pumps at 
natural gas processing plants, and process controllers at natural gas 
processing plants that are all the same or more stringent than previous 
standards in NSPS KKK, NSPS OOOO, and NSPS OOOOa, as applicable. 
Additionally, the final presumptive standards in EG OOOOc for pumps 
(excluding processing) and natural gas processing plant equipment leaks 
are more stringent than the standards in NSPS OOOOa for pneumatic pumps 
and the standards in NSPS KKK, NSPS OOOO, and NSPS OOOOa for natural 
gas processing plant equipment leaks.
    For wet seal centrifugal compressors, two different standards are 
in place in the previous NSPS. NSPS KKK is an equipment standard that 
provides several compliance options including: (1) Operating the 
compressor with the barrier fluid at a pressure that is greater than 
the compressor stuffing box pressure; (2) equipping the compressor with 
a barrier fluid system degassing reservoir that is routed to a process 
or fuel gas system, or that is connected by a CVS to a control device 
that reduces VOC emissions by 95 percent or more; or (3) equipping the 
compressor with a system that purges the barrier fluid into a process 
stream with zero VOC emissions to the atmosphere. NSPS KKK exempts a 
compressor from these requirements if it is either equipped with a 
closed vent system to capture and transport leakage from the compressor 
drive shaft back to a process or fuel gas system or to a control device 
that reduces VOC emissions by 95 percent, or if it is designated for no 
detectable emissions (NDE). NSPS OOOO and NSPS OOOOa require 95 percent 
reduction of emissions from each centrifugal compressor wet seal fluid 
degassing system. NSPS OOOO and OOOOa also allow the alternative of 
routing the emissions to a process. For sources transitioning from NSPS 
KKK to EG OOOOc, the EPA is finalizing a subcategory for wet seal 
centrifugal compressors at onshore natural gas processing plants for 
which construction, reconstruction, or modification commenced after 
January 20, 1984, and on or before August 23, 2011. This subcategory 
will apply to all sources that were previously subject to NSPS KKK, and 
have EG OOOOc presumptive standards that are equivalent to NSPS KKK 
with three compliance options including: (1) operating the compressor 
with the barrier fluid at a pressure that is greater than the 
compressor stuffing box pressure; (2) equipping the compressor with a 
barrier fluid system degassing reservoir that is routed to a process or 
fuel gas system, or that is connected by a CVS to a control device that 
reduces methane emissions by 95 percent or more; or (3) equipping the 
compressor with a system that purges the barrier fluid into a process 
stream with zero methane emissions to the atmosphere. While EG OOOOc 
specifically addresses methane and not VOC, any reductions from the 
methane standards contained in this subcategory that reduce methane as 
established in a state or Federal plan implementing EG OOOOc will 
similarly reduce VOCs. Therefore, wet seal centrifugal compressors 
within this subcategory will only need to comply with a state or 
Federal plan implementing EG OOOOc and will then no longer need to 
comply with NSPS KKK. The EPA is not aware of any wet seal centrifugal 
compressors subject to NSPS OOOO or NSPS OOOOa, and the EPA believes 
that centrifugal compressors installed since those rules went into 
effect (August 2011 and September 2015) are utilizing dry seals rather 
than wet seals.
    Similarly, there are two different standards for reciprocating 
compressors

[[Page 16870]]

in the previous NSPS: (1) NSPS KKK requires the use of a seal system 
and includes a barrier fluid system that prevents leakage of VOC to the 
atmosphere for reciprocating compressors located at natural gas 
processing plants, and (2) NSPS OOOO and NSPS OOOOa require changing 
out the rod packing every 3 years or routing emissions to a control. 
For sources transitioning from NSPS KKK to EG OOOOc, the EPA is 
finalizing a subcategory for reciprocating compressors at onshore 
natural gas processing plants for which construction, reconstruction, 
or modification commenced after January 20, 1984, and on or before 
August 23, 2011. This subcategory will apply to all sources that were 
previously subject to the VOC standards of NSPS KKK and have EG OOOOc 
presumptive standards that are equivalent to the VOC standards of NSPS 
KKK with the requirement of the use of a seal system and including a 
barrier fluid system that prevents leakage of methane to the 
atmosphere. Again, while EG OOOOc specifically regulates methane and 
not VOC, any methane standards contained in this subcategory that 
reduce methane as established in a state or Federal plan implementing 
EG OOOOc will similarly reduce VOCs. Therefore, reciprocating 
compressors within this subcategory will only need to comply with a 
state or Federal plan implementing EG OOOOc and will then no longer 
need to comply with NSPS KKK. For sources transitioning from NSPS OOOO 
and NSPS OOOOa, as previously explained in section XII.E.1.d of the 
November 2021 Proposal \178\ and section IV.I of the December 2022 
Supplemental Proposal, the EPA concludes that the final EG OOOOc 
presumptive methane standard is more efficient at discovering and 
reducing any emissions that may develop than the set 3-year replacement 
interval from NSPS OOOO and NSPS OOOOa. Overall, the final presumptive 
standards in EG OOOOc would result in more rod packing replacements, 
thereby reducing more emissions compared to the 3-year interval. 
Therefore, reciprocating compressors transitioning from NSPS OOOO and 
NSPS OOOOa only need to comply with a state or Federal plan 
implementing EG OOOOc, and will then be no longer needed to comply with 
NSPS OOOO or NSPS OOOOa.
---------------------------------------------------------------------------

    \178\ 86 FR 63215-20 (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 (PTE) greater than 6 tons of VOC per year and the standard that 
applies is 95 percent emissions reduction. Under the final EG OOOOc, 
the designated facility is a tank battery with the PTE greater than 20 
tons of methane per year with the same 95 percent emission reduction 
standard. Affected facilities under NSPS OOOO or OOOOa that are part of 
a designated facility under the EG presumptive standard would be 
required to meet the 95 percent reduction standard, and therefore only 
need to comply with a state or Federal plan implementing EG OOOOc and 
will then no longer need to comply with NSPS OOOO or OOOOa. Affected 
facilities under NSPS OOOO or OOOOa that emit 6 tpy or more of VOCs but 
that do not meet the PTE 20 tons of methane per year definition would 
continue to comply with the 95-percent emissions reduction standard in 
their respective NSPS. Scenarios regarding further physical or 
operational changes in NSPS OOOOb that would reclassify sources from 
the previous NSPS and/or EG OOOOc into NSPS OOOOb are discussed in 
section IV.J.1.b of this preamble.
    Similarly, process controller affected facilities not located at 
natural gas processing plants are defined as single high-bleed 
controllers with a low-bleed standard under NSPS OOOO and NSPS OOOOa, 
while the designated facility under EG OOOOc is defined as a collection 
of natural gas-driven process controllers at a site with a zero-
emissions standard (discussed further in section IV.D of this 
preamble). Because the final zero-emissions presumptive standard in EG 
OOOOc is more stringent than the low-bleed standard found in the 
previous NSPS, sources only need to comply with a state or Federal plan 
implementing EG OOOOc and will then no longer need to comply with NSPS 
OOOO and OOOOa (assuming the state or Federal plan implementing EG 
OOOOc is as stringent as the presumptive standard of zero emissions in 
the final EG).
    Lastly, standards for fugitive emissions from well sites under NSPS 
OOOOa require semiannual OGI monitoring on all components at the well 
site except for wellhead only well sites (which are not affected 
facilities), while the presumptive standards under the final EG OOOOc 
would require quarterly OGI monitoring with bimonthly audible, visual, 
and olfactory (AVO) inspections at well sites with major production and 
processing equipment, semiannual OGI combined with quarterly AVO 
inspections at multi-wellhead only well sites,\179\ and quarterly AVO 
inspections for small sites and single wellhead well sites, as 
described in sections X and XI of this preamble. It is clear that the 
final presumptive standards in EG OOOOc for well sites with major 
production and processing equipment and the final presumptive standards 
for multi-wellheads only well sites are both more stringent than the 
semiannual OGI monitoring standard under NSPS OOOOa because one would 
require more frequent OGI monitoring while the other would require AVO 
inspections in addition to semiannual OGI monitoring. Therefore, these 
existing well sites only need to comply with a state or Federal plan 
implementing EG OOOOc and will then no longer need to comply with NSPS 
OOOOa. Likewise, as the EPA has concluded that the advanced methane 
detection technology periodic screening work practice being finalized 
in EG OOOOc is equivalent to the standard fugitive emissions work 
practice using OGI and AVO, the advanced methane detection technology 
periodic screening work practice being finalized in EG OOOOc is also 
more stringent than the OGI monitoring standard in NSPS OOOOa. In order 
to allow owners and operators to adopt implementation of these advanced 
methane detection technologies early, the EPA is finalizing in NSPS 
OOOOa an option for owners and operators to comply with the advanced 
methane detection technology work practices in NSPS OOOOb in lieu of 
the OGI surveys required in 40 CFR 60.5397a. The EPA recognizes that 
there are some differences between the definition of fugitive emissions 
component between EG OOOOc and NSPS OOOOa. In NSPS OOOOa, the EPA has 
clarified that if an owner or operator subject to NSPS OOOOa chooses to 
implement the advanced methane detection technology work practices in 
NSPS OOOOb the definitions in 40 CFR 60.5430b, which would include the 
definition of fugitive emissions component, apply for the purposes of 
the advanced methane detection technology work practice.
---------------------------------------------------------------------------

    \179\ 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.
---------------------------------------------------------------------------

    For existing single wellhead only well sites and small sites that 
are previously subject to the semiannual monitoring under NSPS OOOOa 
and transitioning to EG OOOOc, the EPA is concluding that, as explained 
in more detail in section IV.A of this preamble, AVO is effective, and 
therefore OGI is unnecessary, for detecting fugitive emissions from 
many of the fugitive emissions components at these sites. By

[[Page 16871]]

requiring more frequent visits to the sites, the final presumptive 
standard in EG OOOOc would allow earlier detection and repair of 
fugitive emissions, in particular large emissions from components such 
as thief hatches on uncontrolled storage vessels. The EPA concludes 
that the final presumptive standards under the proposed EG OOOOc would 
effectively address the fugitive emissions at these well sites and that 
semiannual OGI monitoring would no longer be necessary for these well 
sites. Therefore, these sources need to comply with NSPS OOOOa until 
they are in compliance with a state or Federal plan implementing EG 
OOOOc. Once subject to and in compliance with such a plan, then they no 
longer need to comply with NSPS OOOOa.

X. Summary of Final Standards NSPS OOOOb and EG OOOOc

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

    As described in section IV.A of the December 2022 Supplemental 
Proposal preamble (87 FR 74722, December 6, 2022) and section XI.A of 
the November 2021 Proposal preamble (86 FR 63169, November 15, 2021), 
fugitive emissions are unintended emissions that can occur from a range 
of components at any time due to leaks. Collectively, these emissions 
constitute one of the largest sources of methane from this source 
category, representing approximately 700 kt of the 2019 methane 
emissions from this source category reported in the GHGI. The magnitude 
of these emissions can also vary widely across different facilities and 
over time. The EPA has historically addressed fugitive emissions from 
the Crude Oil and Natural Gas source category through ground-based 
component level monitoring using OGI or EPA Method 21 of appendix A-7 
to 40 CFR part 60.
    This section of the preamble presents a summary of the final 
standards for NSPS OOOOb and final presumptive standards for EG OOOOc 
regarding fugitive emissions components affected facilities and 
designated facilities located at well sites, centralized production 
facilities, and compressor stations. As defined in the final NSPS 
OOOOb, a fugitive emissions component is ``any component that has the 
potential to emit fugitive emissions of methane or VOC at a well site, 
centralized production facility, or compressor station, such as valves 
(including separator dump valves), connectors, pressure relief devices, 
open-ended lines, flanges, covers and closed vent systems not subject 
to Sec.  60.5411b, thief hatches or other openings on a storage vessel 
not subject to Sec.  60.5395b, compressors, instruments, meters, and 
yard piping.'' \180\
---------------------------------------------------------------------------

    \180\ The definition of a fugitive emissions component in EG 
OOOOc is the same except for the reference to 60.5411c instead of 
60.5411b and 60.5396c instead of 60.5395b.
---------------------------------------------------------------------------

1. Fugitive Emissions at Well Sites and Centralized Production 
Facilities
a. NSPS OOOOb
i. Affected Facility
    The standards apply to each fugitive emissions components affected 
facility, which is the collection of fugitive emissions components at a 
well site or centralized production facility.
ii. Final Standards
    In this final rule, the EPA is finalizing the work practice 
standards for monitoring and repairing (including replacing) fugitive 
emissions components at fugitive emissions components affected 
facilities located at well sites and centralized production facilities, 
as proposed in the December 2022 Supplemental Proposal. Specifically, 
the EPA is finalizing monitoring and repair programs for four 
subcategories of well sites as follows:
    1. Single wellhead only well sites: Quarterly AVO inspections,
    2. Multi-wellhead only well sites: Semiannual OGI (or EPA Method 
21) monitoring following the monitoring plan required in 40 CFR 
60.5397b and quarterly AVO inspections,
    3. Well sites with major production and processing equipment and 
centralized production facilities: Quarterly OGI (or EPA Method 21) 
monitoring following the monitoring plan required in 40 CFR 60.5397b 
and bimonthly AVO inspections, and
    4. Small well sites: Quarterly AVO inspections.
    The third subcategory includes well sites and centralized 
production facilities that have:
    1. One or more controlled storage vessels or tank batteries,
    2. One or more control devices,
    3. One or more natural gas-driven process controllers or pumps, or
    4. Two or more pieces of major production or processing equipment 
not listed in items 1-3.
    The EPA explained in the December 2022 Supplemental Proposal that 
it was proposing to define this third subcategory as such (in 
particular items 1-3 above) ``because those sources individually are 
known sources of super-emitter emissions events (see section IV.C) and 
are subject to quarterly OGI for compliance assurance (storage vessels 
and pneumatic controllers) or are subject to other continuous 
monitoring requirements (control devices).'' \181\ As discussed in 
section XI.D.3 of this preamble, we have changed the terminology from 
``pneumatic controllers'' to ``process controllers'' in the final rule.
---------------------------------------------------------------------------

    \181\ 87 FR 74735.
---------------------------------------------------------------------------

    Also, as explained in the December 2022 Supplemental Proposal, the 
fourth subcategory, small well sites, includes single wellhead well 
sites that do not contain any controlled storage vessels, control 
devices, natural gas-driven process controllers, or natural gas-driven 
pumps and contain only one piece of certain major production and 
processing equipment. Major production and processing equipment that 
would be allowed at a small well site would include a single separator, 
glycol dehydrator, centrifugal or reciprocating compressor, heater/
treater, or a storage vessel that is not controlled. Id. at 74723.
    For the second subcategory, multi-wellhead only well sites, where 
semiannual OGI monitoring is required, subsequent semiannual monitoring 
would be required to occur at least 4 months apart and no more than 7 
months apart. For the third subcategory, well sites with major 
production and processing equipment and centralized production 
facilities, where quarterly OGI monitoring is required, subsequent 
quarterly monitoring would occur at least 60 days apart. Quarterly OGI 
monitoring may be waived when temperatures are below 0 [deg]F for two 
of three consecutive calendar months of a quarterly monitoring period.
    In the final rule, the EPA clarified that the monitoring 
requirements for fugitive emissions components do not apply to buried 
yard piping and associated buried fugitive emissions components (e.g., 
buried connectors on the buried yard piping).
    In addition to clarifying in the fugitive emissions component 
definition that ``valves'' include dump valves, the EPA specifies in 
the final rule the requirement to visually inspect the separator dump 
valve while at the site conducting regular AVO monitoring surveys 
(either quarterly or bimonthly, depending on the site) to ensure that 
it is operating as designed and not stuck in an open position. As 
proposed in the December 2022 Supplemental Proposal, the EPA is also 
finalizing the closed and sealed requirement for thief hatches or other 
openings (on storage vessels or tank batteries) that are fugitive 
emissions components and the

[[Page 16872]]

requirement to visually inspect the hatch to confirm compliance during 
the AVO monitoring survey.
    The EPA is finalizing the following repair timelines. A first 
attempt at repair of malfunctioning separator dump valves, open or 
unsealed thief hatches and other storage vessel openings, or other 
sources of fugitive emissions identified with AVO must be made within 
15 days after the detection, with final repair required within 15 days 
after the first attempt. A first attempt at repair of the source of 
fugitive emissions identified with OGI or EPA Method 21 must be made 
within 30 days after the detection, with final repair required within 
30 days after the first attempt. The EPA is also finalizing provisions 
to allow a delay of repair if the repair is technically infeasible, 
would require a vent blowdown, well shutdown, or well shut-in, would be 
unsafe to repair during operation of the unit, or would require 
replacement parts that are unavailable for certain reasons (see section 
XI.A.1.e for details); in no case is delay allowed beyond 2 years.
    Monitoring surveys of fugitive emissions components affected 
facilities at a well site or centralized production facility must 
continue until the site or facility is permanently closed following the 
required well closure plan. After all well closure activities are 
completed, a final OGI survey of the site must be conducted (and 
recorded in the well closure plan) and any emissions detected must be 
eliminated.
iii. Recordkeeping and Reporting Requirements
    The final rule requires specific recordkeeping and reporting 
requirements for each fugitive emissions components affected facility 
located at a well site or centralized production facility. The 
recordkeeping requirements closely follow those in the December 2022 
Supplemental Proposal but incorporate the addition of new delay of 
repair recordkeeping requirements. In the case of delay of repair due 
to parts unavailability, operators must document the date the leak was 
added to the delay of repair list, the date the replacement fugitive 
emissions component or part thereof was ordered, the anticipated 
delivery date, and the actual delivery date.
    The reporting requirements are unchanged from the December 2022 
Supplemental Proposal. Sources would be required to report the 
designation of the type of site (i.e., well site or centralized 
production facility) at which the fugitive emissions components 
affected facility is located. In addition, for each fugitive emissions 
components affected facility that becomes an affected facility during 
the reporting period, the date of the startup of production or the date 
of the first day of production after the modification would be required 
to be reported for well sites or centralized production facility. Each 
fugitive emissions components affected facility at a well site would 
also be required to specify in the annual report what type of site it 
is (i.e., a single wellhead only well site, small well site, a multi-
wellhead only well site, or a well site with major production and 
processing equipment) and to report information on changes such as the 
removal of all major production and processing equipment or well 
closure activities during the reporting period.
    For fugitive emissions components affected facilities located at 
well sites and centralized production facilities, the following 
information is required to be included in the annual report for 
fugitive emissions monitoring surveys conducted using AVO, OGI, or 
Method 21:
    <bullet> Date of the survey,
    <bullet> Monitoring instrument or, if the survey was conducted 
using AVO, notation that AVO was used,
    <bullet> Any deviations from key monitoring plan elements or a 
statement that there were no deviations from these elements of the 
monitoring plan,
    <bullet> Number and type of components for which fugitive emissions 
were detected,
    <bullet> Number and type of fugitive emissions components that were 
not repaired as required,
    <bullet> Number and type of fugitive emissions components 
(including designation as difficult-to-monitor or unsafe-to-monitor, if 
applicable) on delay of repair and explanation for each delay of 
repair, and
    <bullet> Date of planned shutdown(s) that occurred during the 
reporting period if there are any components that have been placed on 
delay of repair.
    For fugitive emissions components affected facilities located at 
well sites and centralized production facilities complying with an 
alternative fugitive emissions standard under 40 CFR 60.5399b, the 
annual report must identify the alternative standard and include either 
the site-specific report or the same information described above. For 
fugitive emissions components affected facilities located at well sites 
and centralized production facilities complying with an alternative 
fugitive emissions standard under 40 CFR 60.5398b, the annual report 
must include information specified in 40 CFR 60.5424b.
b. EG OOOOc
i. Designated Facility
    These final EG define designated facilities as the collection of 
fugitive emissions components at a well site or a centralized 
production facility.
ii. Final Presumptive Standards
    The presumptive methane standards for existing sources under EG 
OOOOc are the same as the methane standards for new sources under NSPS 
OOOOb.
2. Fugitive Emissions at Compressor Stations
a. NSPS OOOOb
i. Affected Facility
    The standards apply to each fugitive emissions components affected 
facility, which is the collection of fugitive emissions components at a 
compressor station.
ii. Final Standards
    In this final rule, the EPA is finalizing the quarterly OGI (or EPA 
Method 21) monitoring requirement for fugitive emissions components 
affected facilities located at compressor stations, as proposed in the 
December 2022 Supplemental Proposal. Specifically, the EPA is 
finalizing the requirement that quarterly surveys be performed using 
OGI or EPA Method 21 following the monitoring plan required in the 
final regulatory text at 40 CFR 60.5397b. The EPA is also finalizing 
the requirement to conduct monthly AVO monitoring at compressor 
stations. Any indications of fugitive emissions identified via AVO 
would be subject to repair requirements.
    The EPA is also finalizing the repair timelines proposed in the 
December 2022 Supplemental Proposal. A first attempt at repair of the 
source of fugitive emissions identified with AVO must be made within 15 
days after the detection, with final repair required within 15 days 
after the first attempt. A first attempt at repair of the source of 
fugitive emissions identified with OGI or EPA Method 21 must be made 
within 30 days after the detection, with final repair required within 
30 days after the first attempt. The EPA is also finalizing provisions 
to allow a delay of repair if the repair is technically infeasible, 
would require a vent blowdown, a compressor station shutdown, a well 
shutdown or well shut-in, would be unsafe to repair during operation of 
the unit, or would require replacement parts that are unavailable for 
certain reasons (see section XI.A.2.b for details); in no case is delay 
allowed beyond 2 years.
    The final rule for fugitive emissions components affected 
facilities located at

[[Page 16873]]

compressor stations includes the requirement that consecutive quarterly 
monitoring surveys be conducted at least 60 days apart. As proposed, 
the EPA is finalizing the provision that the quarterly OGI monitoring 
may be waived when temperatures are below 0 [deg]F for 2 of 3 
consecutive calendar months of a quarterly monitoring period.
iii. Recordkeeping and Reporting Requirements
    The final rule requires specific recordkeeping and reporting 
requirements for each fugitive emissions components affected facility. 
The recordkeeping requirements closely follow those in the December 
2022 Supplemental Proposal but incorporate the addition of new delay of 
repair recordkeeping requirements. In the case of delay of repair due 
to parts unavailability, operators must document the date the leak was 
added to the delay of repair list, the date the replacement fugitive 
emissions component or part thereof was ordered, the anticipated 
delivery date, and the actual delivery date.
    The reporting requirements are unchanged from the December 2022 
Supplemental Proposal. Sources would be required to report the 
designation of the type of site (i.e., compressor station) at which the 
fugitive emissions components affected facility is located. For 
fugitive emissions components affected facilities located at compressor 
stations, the following information is required to be included in the 
annual report for monthly surveys conducted using AVO, OGI, or Method 
21:
    <bullet> Date of the survey,
    <bullet> Monitoring instrument or, if the survey was conducted 
using AVO, notation that AVO was used,
    <bullet> Any deviations from key monitoring plan elements or a 
statement that there were no deviations from these elements of the 
monitoring plan,
    <bullet> Number and type of components for which fugitive emissions 
were detected,
    <bullet> Number and type of fugitive emissions components that were 
not repaired as required,
    <bullet> Number and type of fugitive emissions components 
(including designation as difficult-to-monitor or unsafe-to-monitor, if 
applicable) on delay of repair and explanation for each delay of 
repair, and
    <bullet> Date of planned shutdown(s) that occurred during the 
reporting period if there are any components that have been placed on 
delay of repair.
    For fugitive emissions components affected facilities located at 
compressor stations complying with an alternative fugitive emissions 
standard under 40 CFR 60.5399b, the annual report must identify the 
alternative standard and include either the site-specific report or the 
same information described above. For fugitive emissions components 
affected facilities located at compressor stations complying with an 
alternative fugitive emissions standard under 40 CFR 60.5398b, the 
annual report must include information specified in 40 CFR 60.5424b.
b. EG OOOOc
i. Designated Facility
    These final EG define designated facilities as the collection of 
fugitive emissions components at a compressor station.
ii. Final Presumptive Standards
    The presumptive methane standards for existing sources under EG 
OOOOc are the same as the methane standards for new sources under NSPS 
OOOOb.

B. Advanced Methane Detection Technology Work Practices

    The EPA has included the use of advanced methane detection 
technologies in this final rule, in recognition of the rapid and 
continued advancement of these technologies and their current use by 
owner or operators to supplement their existing ground based OGI 
surveys and AVO inspections. Industry has applied many such 
technologies, from on-site sensor networks to aerial flyovers using 
remote sensing technology that can screen hundreds of sites in a single 
deployment, to efficiently detect methane emissions at a variety of 
facilities and focus their methane mitigation efforts. In the November 
2021 Proposal, we proposed to allow owners and operators to undertake 
an approach with bimonthly periodic screening events using these 
technologies as an alternative to periodic OGI surveys. In doing so, 
the EPA acknowledged that these advanced methane detection technologies 
have important advantages, including the ability to detect fugitive 
emissions quickly and cost-effectively in a manner that may be less 
susceptible to operator error or judgement than traditional leak 
detection technologies. Because many of these advanced methane 
detection technologies are designed to scan multiple sites at once, 
owners and operators have used them as an effective ``screening'' tool 
to rapidly identify particular high-emitting sites that warrant 
targeted inspection and repair efforts.
    The inclusion of these advanced methane detection technologies in 
NSPS OOOOb and EG OOOOc received widespread support from stakeholders. 
We also received feedback on how the EPA could improve on its proposal 
and expand this approach to maximize its efficacy in reducing methane 
emissions and its utility as a compliance flexibility for owners and 
operators. In the December 2022 Supplemental Proposal, we provided 
additional flexibility for advanced methane technologies using the 
periodic screening approach by allowing the frequency of the surveys to 
vary according to the sensitivity of the technology used, instead of 
requiring the same frequency of monitoring for all technologies (i.e., 
periodic screening surveys performed with technologies with lower 
detection thresholds would need to be performed less frequently than 
screening surveys performed with technologies with higher detection 
thresholds). We also introduced a separate alternative work practice 
using continuous methane monitoring systems. Finally, we proposed a 
streamlined approach to approving new technology that is similar to our 
current alternative test method approval process. This approach ensures 
that the advanced methane detection technologies used to conduct 
periodic screening or continuous monitoring will provide consistent and 
reliable information for emission reductions, while also allowing an 
easier pathway for owners and operators to adopt the use of the 
technologies. We believe that this approach will continue to 
incentivize the continued development and improvement of these 
technologies, thus leading to even greater emission reductions.
    This section summarizes the final provisions in NSPS OOOOb and in 
the model rule implementing EG OOOOc for the use of advanced methane 
detection technologies in lieu of OGI and/or AVO at well sites, 
centralized production facilities, and compressor stations. As 
described here, the EPA is finalizing a compliance option that would 
allow the use of these advanced methane detection technologies as an 
alternative to the use of ground-based OGI surveys, EPA Method 21 
(which the final rule continues to allow as an alternative to OGI), and 
AVO inspections to identify emissions from the collection of fugitive 
emissions components located at well sites, centralized production 
facilities, and compressor stations. In response to comments received 
on the December 2022 Supplemental Proposal, the EPA has made revisions 
and clarifications to the periodic screening approach, continuous 
monitoring provisions, and alternative test method process for

[[Page 16874]]

approving advanced methane detection technologies for use in these work 
practices.
1. Periodic Screening
    In this final rulemaking, the EPA is expanding the proposed 
alternative periodic screening approach to provide more flexibility in 
selection of appropriate advanced methane detection technology and to 
account for the spatial resolution of these technologies. The EPA has 
also re-evaluated the equivalency modeling from the December 2022 
Supplemental Proposal used to develop the screening frequency matrix 
and is finalizing revisions to these tables to account for uncertainty 
in the models as discussed in the revised Supplemental TSD Fugitive 
Emissions Abatement Simulation Toolkit (FEAST) Memo.\182\ The updated 
periodic screening frequency matrices are specified in tables 3 and 4 
of the final NSPS OOOOb and the model rule implementing the final EG 
OOOOc. The EPA is also finalizing an interim periodic screening option 
that will expire on March 9, 2026. See section XI.B.1 of this preamble 
for more information on this interim periodic screening matrix.
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    \182\ See Memorandum in EPA-HQ-OAR-2021-0317.
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    For periodic screening using advanced methane detection technology, 
the final rules provide greater flexibility by allowing the owner or 
operator to utilize multiple detection technologies in combination, 
instead of requiring the owner or operator to choose one technology. 
This approach will allow end-users to optimize their periodic screening 
program by choosing the most suitable technology based on time of year 
and availability of technology providers. The periodic screening 
frequency will be based on the technology with the highest aggregate 
detection threshold that the owner or operator lists as a technology 
they plan to use in their monitoring plan (e.g., if you use methods 
with aggregate detection thresholds of 15 kg/hr, your periodic 
screenings must be conducted monthly). The final rule also allows an 
owner or operator to replace any periodic screening survey with an OGI 
survey.
    This final rulemaking will require owners and operators to develop 
a monitoring plan, which can be site-specific or cover multiple sites. 
The monitoring plan must contain the following information at a 
minimum, consistent with the December 2022 Supplemental Proposal:
    <bullet> Identification of each site, including latitude and 
longitude;
    <bullet> Identification of the alternative test methods(s) used 
(i.e., advanced methane detection technology) and required frequency;
    <bullet> Contact information of the entities performing the 
screening;
    <bullet> Procedures for conducting OGI surveys;
    <bullet> Procedures for identifying and repairing fugitive 
emissions components, covers, and closed vents systems when emissions 
are detected; and
    <bullet> Procedures for verifying repairs of fugitive emissions 
components, covers, and closed vents system.
    The final rulemaking finalizes the proposed timeframe in the 
December 2022 Supplemental Proposal that an owner or operator must 
initiate periodic screenings using advanced methane detection 
technology, within 90 days after startup or modification of a fugitive 
emissions components affected facility and storage vessel affected 
facility at new, modified, or existing well sites, centralized 
production facilities, and/or compressor stations, as well as 
timeframes for initiating periodic screenings if an owner or operator 
opts to switch to periodic screenings at a later time (i.e., the owner 
or operator was originally conducting fugitive emissions surveys with 
OGI or EPA Method 21). The final rule also sets timeframes for 
conducting annual OGI surveys, if an owner or operator is required to 
do so based on the periodic screening matrix.
    The final rulemaking finalizes the requirement in the December 2022 
Supplemental Proposal that owners and operators must receive the data 
from a periodic screening event within 5 calendar days. If the 
screening event indicates a confirmed detection, the owner or operator 
must conduct follow-up monitoring. In the final rule, we are allowing a 
more targeted follow-up survey, dependent on the spatial resolution of 
the advanced methane detection technology used during the periodic 
screening event. The final rulemaking includes three different 
classifications for spatial resolution: facility-level, which must be 
able to identify emissions within the boundary of a well site, 
centralized production facility, or compressor station; area-level, 
which must be able to identify emissions within a radius of 2 meters of 
the emission source; and component-level, which must be able to 
identify emissions within a radius of 0.5 meters of the emission 
source. The follow-up monitoring that must be conducted for a confirmed 
detection during a periodic screening event using a technology with 
facility-level spatial resolution includes:
    <bullet> A monitoring survey of all the fugitive emissions 
components in an affected facility using either OGI or EPA Method 21;
    <bullet> Inspection of all covers and closed vent systems of the 
affected facility with either OGI or EPA Method 21; and
    <bullet> Visual inspection of all closed vent systems and covers to 
identify if there are any defects.
    The follow-up monitoring that must be conducted for a confirmed 
detection during a periodic screening event using a technology with 
area-level spatial resolution includes:
    <bullet> A monitoring survey of all the fugitive emissions 
components located within a 4-meter radius of the location of the 
confirmed detection using either OGI or EPA Method 21; and
    <bullet> If the confirmed detection occurred in a portion of a site 
with a storage vessel or closed vent system, inspection of all covers 
and closed vent systems that are connected to all storage vessels and 
closed vent systems that are within a 2-meter radius of the confirmed 
detection location (i.e., you must inspect the whole system that is 
connected to the portion of the system, not just the portion of the 
system that falls within the radius of the detected event). Inspection 
must be conducted using either OGI or EPA Method 21, as well as 
visually to identify defects.
    The follow-up monitoring that must be conducted for a confirmed 
detection during a periodic screening event using a technology with 
component-level spatial resolution includes:
    <bullet> A monitoring survey of all the fugitive emissions 
components located within a 1-meter radius of the location of the 
confirmed detection using either OGI or EPA Method 21; and
    <bullet> If the confirmed detection occurred in a portion of a site 
with a storage vessel or closed vent system, inspection of all covers 
and closed vent systems that are connected to all storage vessels and 
closed vent systems that are within a 0.5-meter radius of the confirmed 
detection location (i.e., you must inspect the whole system that is 
connected to the portion of the system, not just the portion of the 
system that falls within the radius of the detected event). Inspection 
must be conducted, as well as visually to identify defects.
    As proposed, the final rulemaking requires that the owner or 
operator follow the repair requirements and timelines in the December 
2022 Supplemental Proposal for fugitive emissions components where 
emissions are detected from fugitive components, and the repair 
requirements for covers

[[Page 16875]]

and closed vent systems (CVS) if emissions are detected during the 
follow-up monitoring survey. We are also finalizing as proposed the 
requirement to conduct an investigative analysis when the source of a 
confirmed detection is determined to be a control device subject to the 
rule or an emission from or defect from a cover or closed vent system 
associated with an affected facility, although we have refined the 
requirements. These requirements include:
    <bullet> Repair all fugitive emissions components, covers, and 
closed vent systems within 30 days after receiving the periodic 
screening data (except where delay of repair is allowed).
    <bullet> Initiate an investigative analysis within 5 days if an 
emission or defect in a closed vent system or cover is determined to be 
the cause of the emissions.
    <bullet> Initiate an investigative analysis within 24 hours of 
receiving the monitoring survey and inspection results if a failed 
control device is determined to be the cause of the emissions.
    <bullet> Investigative analyses must be used to determine the 
underlying primary cause and other contributing causes to the emissions 
event. Owners and operators must determine the actions needed to bring 
the control device into compliance; how to prevent future failures of 
the control device from the same underlying cause(s); and updates are 
necessary to the engineering analysis for the cover or closed vent 
system to prevent future emissions from the cover and closed vent 
system.
2. Continuous Monitoring Screening
    In this final rulemaking, the EPA is finalizing the continuing 
monitoring approach and associated work practice in the December 2022 
Supplemental Proposed Rule with some changes to better account for 
background methane concentrations and to better incorporate additional 
types of measurement systems. The EPA has reexamined the proposed 
detection threshold for these systems and has adjusted that threshold 
in the final rule to better account for background methane 
concentrations.
    The final rule includes defined requirements for operating 
continuous monitoring systems, including using advanced methane 
monitoring technology approved by the EPA for this purpose. This system 
must be set-up in a manner to generate a valid methane mass emission 
rate (or equivalent) once at least every twelve-hour block, have an 
operation downtime of less than 10 percent, and have checks in place to 
monitor the health of the system. We have revised the proposed 
sensitivity requirements to allow systems with detection thresholds of 
0.40 kg/hr of methane or lower and, are requiring systems to transmit 
data at least once every 24 hours. The final rule maintains the 
timeframe in the December 2022 Supplemental Proposal for when the owner 
or operator must initiate continuous monitoring using advanced methane 
detection technology (i.e., within 120 days after startup of a fugitive 
emissions components affected facility and storage vessel affected 
facility at new, modified, and existing well sites, centralized 
production facilities, and/or compressor stations), as well as 
timeframes for initiating continuous monitoring if an owner or operator 
opts to switch to periodic screenings at a later time (i.e., the owner 
or operator was originally conducting fugitive emissions surveys with 
OGI or EPA Method 21).
    In the final rulemaking, we have revised the ``action-levels'' in 
the December 2022 Supplemental Proposal to account for the potential 
for background methane emission levels at many of these sites. An 
action-level is the time weighted average that triggers an 
investigative analysis to identify the cause(s) of the exceedance. For 
affected facilities located at wellhead only well sites, these 
``action-levels'' are as follows:
    <bullet> Rolling 90-day average of 1.2 kg/hr of methane over the 
site-specific baseline.
    <bullet> Rolling 7-day average of 15 kg/hr of methane over site-
specific baseline.
    For affected facilities located at well sites with major production 
and processing equipment, small well sites, centralized production 
facilities, and compressor stations, the action levels are as follows:
    <bullet> Rolling 90-day average of 1.6 kg/hr of methane over the 
site-specific baseline.
    <bullet> Rolling 7-day average of 21 kg/hr of methane over the 
site-specific baseline.
    The final rule includes a new and defined set of criteria for the 
timeframe and site conditions under which to establish the site-
specific baseline emissions since the December 2022 Supplemental 
Proposal, finalizes as proposed how to calculate emissions after the 
baseline has been established, and has refined the proposed actions the 
owner or operator must take when an ``action-level'' is exceeded. Prior 
to establishing the site-specific baseline, the owner or operator must 
perform inspections of the fugitive emissions components, any covers 
and closed vent systems, and control devices to ensure the site is leak 
free and in compliance with the requirements in NSPS OOOOb and/or the 
applicable state plan implementing EG OOOOc. The owner or operator must 
then record the site-level emissions from the continuous monitoring 
system for 30 days and determine the mean emission rate, less any time 
periods when maintenance activities were conducted.
    The final rule has changed the requirements in the December 2022 
Supplemental Proposal for how to calculate the 7-day and 90-day rolling 
average to account for the site-specific baseline and has maintained 
the intent of required follow-up activities when exceedances of the 
action-level have occurred. We have also changed the nomenclature of 
the follow-up activities from ``root cause analysis'' to 
``investigative analysis'' and from ``corrective action'' to ``mass 
emission rate reduction plan'' to eliminate confusion caused by the 
terminology we used in the December 2022 Supplemental Proposal. We have 
also more clearly specified the requirements for these activities. The 
requirements for an investigative analysis are as follows:
    <bullet> The investigative analysis must be initiated within 5 days 
after an exceedance of an action-level to determine the underlying 
primary and contributing cause(s).
    <bullet> When the 7-day action-level is exceeded, within 5 days 
after the exceedance the investigative analysis must be completed and 
initial steps must be taken to reduce the mass emission rate.
    <bullet> When the 90-day action-level is exceeded, within 30 days 
after the exceedance the investigative analysis must be completed and 
initial steps must be taken to reduce the mass emission rate.
    An owner or operator must develop a mass emission rate reduction 
plan when any of the following conditions have been met:
    <bullet> For an exceedance of the 90-day action-level, 30-day 
average mass emission rate for the 30 days following the completion of 
the investigative analysis and initial steps to reduce the mass 
emission rate is not below the applicable 90-day action-level.
    <bullet> For an exceedance of the 7-day action-level, the mass 
emission rate for the 24-hour period after the completion of the 
investigative analysis and initial steps to reduce the mass emission 
rate is not below the applicable 7-day action-level.
    <bullet> The actions needed to reduce the emission rate below the 
applicable action-level will take more than 30 days to implement.

[[Page 16876]]

3. Alternative Test Method for Methane Detection Technology
    In this final rule, the EPA has strengthened the alternative test 
method approval process for advanced methane detection technology used 
in periodic screening and continuous monitoring. The EPA has further 
clarified the Administrator authority in the approval process, the 
criteria for who may submit requests for approval, and the requirements 
for what information must be submitted by those entities seeking 
approval.
    This final rule specifies a process for applying and obtaining the 
EPA's approval for the use of an advanced methane detection technology 
in lieu of the required monitoring methods in the rule by submitting 
the test method for the alternative technology. However, instead of 
relying on existing provisions for alternative test methods 40 CFR 
60.8(b), we are in the final rule citing a new alternative test method 
provision in 40 CFR 60.5398b(d). This provision incorporates specific 
criteria for the review, evaluation, and potential use of advanced 
methane detection technology for use in periodic screening, continuous 
monitoring, and/or super-emitter detection.
    This final rule maintains the procedures in the December 2022 
Supplemental Proposal for submitting an alternative test method for 
methane detection technology request. These requests must be submitted 
to the Leader, Measurement Technology Group along with any supporting 
data to the methane detection portal at (www.epa.gov/emc/oil-and-gas-alternative-test-methods). Confidential Business Information (CBI) must 
not be submitted through this portal; detailed instructions for 
submitting information for which an entity submits a claim of CBI are 
provided in 40 CFR 60.5398b(d)(1). The Administrator will complete an 
initial completeness review of submissions within 90 days. An approval 
or disapproval will be issued in writing within 270 days after 
receiving a request. Submission approvals may be considered on a site-
specific basis or more broadly applicable, depending on the technology 
and the information provided in the request.
    The December 2022 Supplemental Proposal included limitations on 
which entities could submit an alternative test method request. The 
final rule retains these provisions while also providing improvements 
to allow for proprietary advanced methane measurement technology 
internally developed by owners and operators. Any entity that meets the 
following specifications may submit an alternative test method request:
    <bullet> The entity must be an individual or organization located 
in or that has representation in the United States.
    <bullet> The entity must be an owner or operator of an affected 
facility under NSPS OOOOb or EG OOOOc.
    <bullet> If the entity is the not the owner or operator of an 
affected facility, the entity must directly represent the provider of 
the candidate measurement system using advanced methane detection 
technology and the measurement system must have been applied to 
measurements and monitoring in the oil and gas sector (domestically or 
internationally).
    <bullet> The candidate measurement system must have been sold, 
leased, or licensed, or offered for sale, lease, or license to the 
general public or developed by an owner or operator for internal use 
and/or use by external partners.
    The final rule also expands upon the information you are required 
to provide to the Administrator when submitting a request to use an 
alternative test method for advanced methane detection technology. 
These expanded requirements represent the minimum amount of material 
required by the EPA to completely understand the functionality of 
candidate measurement technology systems, how these systems are applied 
to generate a methane mass emission rate (kg/hr) or equivalent emission 
rate, data management, detection threshold, and spatial resolution.
    The final rule requires an entity to provide the Administrator 
contact information for the requester, the desired applicability of the 
technology, and a description of the candidate measurement technology 
system, including:
    <bullet> A description of the scientific theory and appropriate 
references outlining the underlying technology;
    <bullet> A description of the physical instrument;
    <bullet> Type of measurement and desired application (e.g., 
airborne, in-situ); and
    <bullet> Potential limitations of the candidate measurement system, 
including application limitations.
    The request must also include information on how the system 
converts results to a mass emission rate or equivalent. This 
information must include the following:
    <bullet> Workflow and description covering all steps and processes 
from measurement technology signal output to final, validated mass 
emission rate (i.e., kg/hr) or equivalent.
    <bullet> Description of how any meteorological data are used, 
including how they are collected and/or sourced.
    <bullet> Identification of any model(s) used, including how inputs 
are determined or derived.
    <bullet> All calculations used, including the defined variables for 
any calculations.
    <bullet> A-priori methods and datasets used.
    <bullet> Explanation of any algorithms/machine learning procedures 
used in the data processing, if applicable.
    The request must also include a description of how data collected 
and generated by the system are collected, maintained, and stored; how 
these data streams are processed and manipulated, including how the 
resultant data processing is documented; and a description of which 
data streams are provided to the end-user of the data and how that 
information is delivered or supplied.
    The EPA has further refined the supporting information that must be 
used to verify detection thresholds and information on how the 
candidate measurement system must be applied to ensure the detection 
thresholds are maintained during monitoring events. We have also 
revised the detection threshold to an average aggregate detection 
threshold, which is defined as the average of all site-level detection 
thresholds from a single deployment (e.g., a singular flight that 
surveys multiple well sites, centralized production facility, and/or 
compressor stations). The information provided in the request must 
include published reports produced by either the submitting entity or 
an outside entity evaluating the technology, standard operating 
procedures, alternative testing procedure(s) (preferably in the format 
described in Guideline Document 45),\183\ and documents provided to 
end-users of the data.
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    \183\ Available at https://www.epa.gov/sites/default/files/2020-08/documents/gd-045.pdf.
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    The final rule includes a new requirement for entities to verify 
the spatial resolution of the candidate measurement system. The 
supporting information verifying the spatial resolution must be in the 
form of published report (e.g., scientific papers) produced by either 
the submitting entity or an outside entity evaluating the submitted 
measurement technology that has been independently evaluated.

C. Super Emitter Program

    This section presents a summary of the final standards for the 
Super Emitter Program. As described in section IV.C of the December 
2022 Supplemental Proposal preamble (87 FR 74722,

[[Page 16877]]

December 6, 2022), the EPA proposed the Super Emitter Program to ensure 
that this rulemaking comprehensively addresses the widespread problem 
of abnormally large emissions events known as super-emitters. The EPA 
is including the Super Emitter Program in this final rulemaking, 
previously proposed as the Super Emitter Response Program in the 
December 2022 Supplemental Proposal. The EPA has developed this program 
in response to recent studies, which indicate that a small portion of 
sources contribute almost 50 percent of the methane emissions in the 
oil and gas sector, and on a global scale, the largest of these 
emissions sources may represent as much as 12 percent of global methane 
emissions from oil and gas production. For purposes of this rule, a 
super-emitter event is one that has a quantified emission rate of 100 
kg/hr of methane or greater.
    As described here, this program is designed to provide a 
transparent, reliable, and efficient mechanism by which the EPA will 
provide owners and operators with timely notifications of super-emitter 
emissions data collected by the EPA-certified third parties using the 
EPA-approved remote sensing technologies (e.g., satellites). Where such 
an event is attributable to a source regulated under CAA section 111 
(NSPS OOOO, OOOOa, or OOOOb, or a state or Federal plan implementing EG 
OOOOc), the responsible owner or operator will take action in response 
to such notifications in accordance with the applicable regulation.
    The EPA anticipates that the NSPS and presumptive standards for 
existing sources that are included in this final rulemaking will reduce 
many sources of super-emitters. However, these events sometimes arise 
from planned maintenance, other routine operations, and are also 
frequently attributable to major malfunctions or improperly operating 
control devices. These events are unpredictable and can occur in 
between routine inspections and/or fugitive emissions monitoring 
surveys. Moreover, these events are sufficiently large to result in 
significant emissions of the harmful air pollutants regulated under 
this rule in a short span of time. By leveraging data collected by the 
EPA-approved third parties using the EPA-approved methods to identify 
such events and providing a mechanism for the EPA to promptly notify 
owners and operators of such events for appropriate follow-up action, 
the Super Emitter Program serves as both a complement and a backstop to 
the other requirements of this rulemaking.
    As described in our response to comments, the EPA received several 
comments--including from owners and operators of regulated facilities--
supporting the objectives of the Super Emitter Program and the 
importance of timely identifying and resolving super-emitter events. In 
this final rulemaking, the EPA has also made a number of changes to the 
Super Emitter Program in order to provide appropriate oversight by the 
EPA, address implementation concerns raised by commenters, and ensure 
that the program provides owners and operators with transparent, 
reliable, and timely information about super-emitter events.
    As described in section IV.C of the December 2022 Supplemental 
Proposal preamble (87 FR 74746, December 6, 2022), the EPA proposed a 
Super Emitter Program as a backstop to address large methane super-
emitters from this sector. This program is designed for the EPA to 
receive super-emitter emission data collected by the EPA-certified 
third parties using the EPA-approved remote sensing technologies (e.g., 
satellites) in a timely manner. In response to comments objecting to or 
otherwise expressing concerns with requiring owners and operators to 
respond directly to third-party notifications of super-emitter events, 
the EPA has revised the program in the final rulemaking such that it is 
the EPA, and not third parties, that will notify an identified owner or 
operator after reviewing third-party notifications of the presence of a 
super-emitter event at or near its oil and gas facility (e.g., a 
specific well site, centralized production facility, gas processing 
plant, or compressor station), requiring the owner or operator to 
investigate and report the results to the EPA. Also, in response to 
comments, the EPA emphasizes that certified third parties will only be 
authorized to use remote sensing technologies such as satellites or 
aerial surveys--i.e., this program does not authorize third parties to 
enter well sites or other oil and gas facilities, and it does not allow 
for the use of technologies such as OGI that would require close access 
to such facilities.
1. Statutory Authority
    The Super Emitter Program finalized in this rule is based on the 
EPA's authority under CAA section 114(a) to require ``any person who 
owns or operates any emission source'' (except mobile sources) \184\ to 
provide information necessary for purposes of carrying out the CAA and 
its authority to regulate sources under CAA section 111. In the 2022 
Supplemental Proposal, the EPA proposed two separate legal frameworks 
for the Super Emitter Program. 87 FR 74752. The final Super Emitter 
Program is based on the second legal framework. Under this framework, 
the EPA's authority to require sources (regardless of whether those 
sources are regulated under CAA section 111) to investigate potential 
sources of super-emitter events and report to EPA is CAA section 114. 
The EPA's authority to require regulated sources to repair or otherwise 
address the cause of the super-emitter event is CAA section 111. In 
particular, for sources regulated under CAA section 111, the Super 
Emitter Program will serve as: (1) an additional work practice standard 
under NSPS OOOOb (and presumptive standard under EG OOOOc) for fugitive 
emissions at well sites, centralized production facilities and 
compressor stations, and as (2) an additional compliance assurance 
measure for other NSPS OOOOb affected facilities, NSPS OOOO and OOOOa 
affected facilities, and designated facilities under EG OOOOc.
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    \184\ The EPA has similar information collection authority with 
respect to mobile sources under CAA section 208.
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a. Authority To Require Investigation and Reporting for all Sources
    The EPA's authority to require all sources, regardless of whether 
they are regulated under CAA section 111, to investigate potential 
super-emitter events and report back to the EPA stems from the EPA's 
broad authority under CAA section 114(a) to require, among other 
things, monitoring, reporting, and recordkeeping from owners and 
operators of stationary sources. CAA section 114(a)(1) gives the EPA 
broad authority to ``require any person . . . to (A) establish and 
maintain such records; (B) make such reports; (C) install, use and 
maintain such monitoring equipment, and use such audit procedures, or 
methods; . . . and (G) provide such other information as the 
administrator may reasonably require . . . .'' The EPA can impose such 
obligations on ``any person who owns or operates any emission source,'' 
whether or not the emission source is regulated under the CAA, ``[f]or 
the purpose of assisting in the development of any implementation plan 
under . . . section 7411(d) of this title, any standard of performance 
under section 7411 of this title,'' ``determining whether any person is 
in violation of any such standard or any requirement of such plan,'' or 
``carrying out any provision of this chapter.'' CAA section 111(b) 
requires that the EPA review and, if appropriate, revise an NSPS at 
least every 8 years

[[Page 16878]]

following its promulgation.\185\ The information on super-emitter 
events from both regulated and unregulated oil and gas sources can help 
inform the EPA on the effectiveness of its current NSPS for this sector 
and potential focus in its future review. Therefore, based on the 
authority under CAA section 114(a), the Super Emitter Program requires 
owners and operators to investigate and report all sources, including 
non-NSPS/EG sources, that they suspect may have caused or contributed 
to the super-emitter event specified in the EPA notice that they have 
received, to ensure that a regulated source is not contributing to the 
event, as well as to provide useful information to the EPA in carrying 
out its review obligation under CAA section 111(b). The information on 
super-emitter events can also help owners and operators prevent or 
minimize losing a valuable product (natural gas).
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    \185\ As explained earlier in section IV.A of this preamble, CAA 
section 111(b)(1)(B) provides the EPA discretion to determine the 
pollutants and sources to be regulated. In addition, concurrent with 
the 8-year review (and though not a mandatory part of the 8-year 
review), the EPA may examine whether to add standards for pollutants 
or emission sources not currently regulated for that source 
category.
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b. Authority To Require Repair for Regulated Sources: Work Practice 
Standards for Fugitive Emissions
    Pursuant to CAA section 111, the EPA has incorporated the Super 
Emitter Program, in particular the requirement to repair fugitive 
emissions components that are sources of super-emitter events, as a 
part of the BSER and therefore work practice standards for fugitive 
emissions components affected/designated facilities under NSPS OOOOb/EG 
OOOOc. As the first part of the fugitive emissions BSER and work 
practice standards, discussed in section X.A of this document, the EPA 
has established periodic monitoring and repair work practice standards 
as the BSER for these fugitive emissions components affected/designated 
facilities under NSPS OOOOb and EG OOOOc. Fugitive emissions may 
nevertheless occur from these components between the specified periodic 
monitoring. Emissions from certain fugitive emissions components can be 
significant (as one example, a stuck-open thief hatch) and can remain 
undetected until the next scheduled periodic monitoring. Accordingly, 
as the second part of the fugitive emissions BSER and work practice 
standard for affected/designated facilities under NSPS OOOOb and EG 
OOOOc, the EPA is requiring repair of fugitive emissions components 
that are the cause of super-emitter events in between routine 
monitoring. While the EPA has determined that it is not cost effective 
to require more frequent periodic monitoring, where a super-emitter 
event (i.e., 100 kg/hr) is caused by fugitive emissions components, 
repair to reduce such large emissions is clearly cost effective. To 
that end, the Super Emitter Program supplements the periodic monitoring 
and repair work practice standards in NSPS OOOOb (and presumptive 
standards in EG OOOOc) by requiring repair of fugitive emissions 
components affected/designated facilities under these subparts that the 
owner or operator has identified as the source of the super-emitter 
event through this program.\186\ The owner or operator will conduct 
repair in accordance with the same repair requirements as those for 
fugitive emissions detected during the periodic monitoring, as 
specified in the applicable standard (i.e., NSPS OOOOb or a state plan 
implementing EG OOOOc).
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    \186\ As explained in the 2022 Supplemental Proposal (87 FR 
74753), despite our incorporation of this additional repair 
requirement under the Super Emitter Program into the work practice 
standards for the fugitive emissions components at well sites, 
centralized production facilities and compressor stations, this 
repair requirement is nevertheless severable from the periodic 
monitoring and repair work practices that we have separately 
analyzed and established as the BSER for fugitive emissions at each 
of these facilities. In addition, the additional repair requirement 
of the Super Emitter Program is severable from the CAA section 
114(a)(1) monitoring and reporting aspect of the Program.
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c. Authority To Require Monitoring and Reporting for Regulated Sources: 
Compliance Assurance for Other Regulated Sources
    For regulated sources that are not fugitive emissions components 
affected/designated facilities under NSPS OOOOb/EG OOOOc, the presence 
of a super-emitter event suggests that the source may not be in 
compliance with the applicable requirements for that source contained 
in the EPA's regulations. The compliance assurance aspect of the Super 
Emitter Program is based on the EPA's regulations for individual 
emissions sources in the NSPS and EG promulgated pursuant to CAA 
section 111. NSPS OOOO/OOOOa/OOOOb and the model rule implementing EG 
OOOOc all include design and/or operational requirements \187\ and 
monitoring, recordkeeping, and reporting requirements \188\ to assure 
that standards of performance \189\ are being met. However, as 
explained above, super emitter events are unpredictable; they can occur 
between routine inspections and release significant emissions in a 
short span of time. To address this concern, the Super Emitter Program 
provides additional monitoring, reporting and recordkeeping for 
affected/designated facilities under NSPS OOOO/OOOOa/OOOOb and EG OOOOc 
based on the EPA's authority under CAA section 114(a) to impose such 
requirements for purposes of determining whether or not standards under 
these subparts are being met. Where a super-emitter event originates 
from one of these affected/designated facilities or associated 
equipment regulated under NSPS OOOO, OOOOa, OOOOb, or a state or 
Federal plan implementing EG OOOOc, the Super Emitter Program serves as 
an additional source of monitoring data to inform and alert owners and 
operators to check and make sure that the source and associated control 
device and equipment are operating as required under the applicable 
NSPS or State or Federal plan implementing EG OOOOc. For example, a 
super-emitter event may be caused by an open thief hatch on a storage 
vessel subject to NSPS OOOOa, which is not permitted except for very 
limited circumstances as defined in the rule. In that event, the Super 
Emitter Program serves to alert an owner or operator of the need to 
close the thief hatch pursuant to the requirements of NSPS OOOOa, but 
the Super Emitter Program does not itself impose a requirement to close 
the thief hatch. Since there are already requirements in place to bring 
emissions down to or below the applicable NSPS standards (and will be 
in state or Federal plans implementing EG OOOOc), the Super Emitter 
Program does not itself independently require specific actions

[[Page 16879]]

to address emissions from super-emitter events attributed to NSPS or EG 
sources; it merely puts owners and operators on notice that action may 
be required to bring a source back into compliance with the applicable 
emission standards. To clarify this point, the final rule includes 
amendments to NSPS OOOO and OOOOa to incorporate relevant compliance 
assurance provisions of the Super Emitter Program, specifically the 
requirement to investigate and report whether the super-emitter event 
was caused by a NSPS OOOO or OOOOa affected facility or associated 
equipment.
---------------------------------------------------------------------------

    \187\ The EPA establishes ``standards of performance'' pursuant 
to CAA section 111. CAA section 302(l) defines a ``standard of 
performance'' to include not only standards limiting the quantity, 
rate, or concentration of emissions, but also requirements 
``relating to the operation or maintenance of a source to assure 
continuous emission reduction.'' Examples of such compliance 
assurance requirements include 40 CFR 60.5411/60.5411a (cover and 
closed vent system requirements) and 60.5412/60.5412a (control 
device requirements) in NSPS OOOO/OOOOa.
    \188\ The EPA has long relied on CAA section 114 to establish 
monitoring, recordkeeping, and reporting requirements to implement 
and enforce the emissions standards promulgated under CAA section 
111 (see, e.g., 36 FR 24876 (December 23, 1971) (NSPS for the 
initial five listed source categories, citing both CAA sections 111 
and 114 as the statutory authorities). That was the case with the 
2012 NSPS OOOO and 2016 NSPS OOOOa, and the EPA has similarly 
included such measures in the present rule in NSPS OOOOb and in the 
model rule for EG OOOOc.
    \189\ These do not include fugitive emissions components 
affected/designated facilities under NSPS OOOOb and EG OOOOc, which 
the EPA has separately addressed, as discussed above.
---------------------------------------------------------------------------

2. Major Elements
    The following describes the major elements in the Super Emitter 
Program that serve to assure the reliability of the super-emitter data 
that the EPA receives under this program. These elements ensure that 
the data the EPA receives is meaningful and lead to expeditious and 
effective mitigation of super-emitter events by owners and operators, 
whether required or voluntarily.
a. Qualifications for Third-Party Notifiers
    A third party can be any independent entity, meaning that the third 
party does not own or operate the site where a super-emitter is 
detected. In this final rulemaking, the EPA is maintaining the 
requirements for the qualification of the third-party notifiers in the 
December 2022 Supplemental Proposal, including the requirement that 
notifiers use remote sensing technologies. These technologies and their 
method for operation must be approved under the advanced methane 
detection technology program in 40 CFR 60.5398b(d). Third parties are 
limited to using remote sensing technologies such as satellites or 
aerial surveys and would not be authorized by this program to enter a 
site.
b. Third-Party Notifier Certification
    In this final rulemaking, the EPA establishes a framework by which 
we will certify third-party notifiers from whom the EPA would accept 
data from super-emitter events under the Super Emitter Program. The 
final rulemaking includes provisions governing how the third-party must 
submit a request to be certified, requirements that a third-party must 
meet to be certified and/or re-certified, obligations for notifiers to 
maintain records of surveys performed to maintain certification, and 
procedures for revoking a notifiers certification.
    A third-party notifier certification request must be submitted to 
the Leader, Measurement Technology Group, 109 T.W. Alexander Drive, 
P.O. Box 12055, Research Triangle Park, NC 27711. If your request 
contains CBI, you must transmit these data electronically using email 
attachments, File Transfer Protocol, or other online file sharing 
services.\190\ This request must include general identification for the 
entity submitting the request, including the mailing address, physical 
address, and contact information for the principal officer and 
certifying officials(s). This request must also include the following 
information:
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    \190\ Please email <a href="/cdn-cgi/l/email-protection#07686676777464656e4762776629606871"><span class="__cf_email__" data-cfemail="e8878999989b8b8a81a88d9889c68f879e">[email protected]</span></a> to request a file transfer 
link.
---------------------------------------------------------------------------

    <bullet> Description of the advanced methane detection technologies 
that the third party intends to use, including reference to any 
alternative test method approval under 40 CFR 60.5398b(d), and any 
agreements with the technology providers.
    <bullet> Curriculum vitae of the certifying official(s) detailing 
training for evaluating results of the chosen advanced methane 
detection technology.
    <bullet> The entity's standard operating procedure(s) detailing the 
procedures and processes used by the entity for data review, including 
the accuracy of emissions data and locality data provided by the 
technology provider, how the entity will identify the owner or operator 
of a site, and procedures for handling potentially erroneous data.
    <bullet> Description of the system for maintaining essential 
records.
    <bullet> A Quality Management Plan consistent with the EPA's 
Quality Management Plan Standard (Directive No: CIO 2015-S-01.0, 
January 17, 2023).
    An entity that has received third-party approval must maintain the 
following records in order to retain its certification status:
    <bullet> Records for all surveys conducted by or sponsored by the 
certified third-party notifier that are the basis for a third-party 
super-emitter identification submitted to the EPA.
    <bullet> Records for any notifications provided to the EPA and any 
additional data collected supporting the notification not required by 
the EPA to be reported.
    <bullet> Records or identification of databases used to identify 
owner or operators of sites where super-emitter events reported to the 
EPA occurred.
    The Administrator will assess the completeness, reasonableness, and 
accuracy of the third party's request based on the updated 
certification criteria in the final rule. Once certified, the third-
party notifier will receive a unique notifier ID which will be posted 
at www.epa.gov/emc-third-party-certifications. If there is any material 
change to the information included in the third party's initial 
certification request, e.g., a change to the technology that the third 
party intends to use or a change to the certifying official(s), the 
final rule requires the third party to submit a revised request and be 
recertified before implementing those changes.
    As proposed, the EPA is finalizing provisions providing for the 
revocation of a third party's certification under certain conditions. 
In response to comments, the EPA has expanded in the final rule the 
circumstances for removing a third-party certification, which are as 
follows:
    <bullet> Submitting super-emitter notifications after making 
material changes to the third party's procedures for identifying super-
emitters without seeking recertification.
    <bullet> If the Administrator finds that the certified third-party 
notifier has persistently submitted data with significant errors.
    <bullet> Having engaged in illegal activity during the assessment 
of a super-emitter event (e.g., trespassing).
    <bullet> Upon determination by the Administrator, following 
petition from the owner or operator, that the owner or operator has 
received from the EPA more than three notices with meaningful and/or 
demonstrable errors of a super-emitter event at the same oil and 
natural gas facility (e.g., a well site, centralized production 
facility, natural gas processing plant, or compressor station), that 
were submitted to the EPA by the same third party, and the owner or 
operator demonstrates that the claimed super-emitter event did not 
occur. The failure of the owner or operator to find the source of the 
super-emitter emissions event upon subsequent inspection would not be 
proof, by itself, of demonstrable error on the part of the third-party 
notifier.
c. Notification of Super-Emitter Events
    In the final rules, the EPA has amended the super-emitter 
notification process in the December 2022 Supplemental Proposal to now 
include a step whereby the EPA will receive and review the super-
emitter data from certified third-party notifiers before triggering any 
obligation on the part of the owner or operator. The final rules 
require the third-party notifier to submit notifications to the EPA 
within 15 calendar days after detection of a super-emitter event to 
ensure timely notice and includes standards for the content of the 
notification to aid in the EPA's

[[Page 16880]]

review of the data. Third-party notifications must be submitted into 
the Super Emitter Program Portal at https://www.epa.gov/super-emitter 
and must include the following:
    <bullet> Unique Third-Party Notifier ID.
    <bullet> Date of detection of the super-emitter event.
    <bullet> Location of super-emitter event in latitude and longitude 
coordinates.
    <bullet> Owner(s) or operator(s) of an oil and natural gas facility 
of any individual well site, centralized production facility, or 
compressor station within 50 meters of the latitude and longitude 
coordinates of the super-emitter event, if available, and the method 
used by the third party to identify the owner or operator.
    <bullet> Identification of the detection technology and reference 
to the approval of the technology.
    <bullet> Documentation (e.g., imagery) depicting the detected 
super-emitter event and the site from which the super-emitter event was 
detected.
    <bullet> Quantified emission rate of the super-emitter event in kg/
hr.
    <bullet> Attestation statement that the information submitted by 
the third-party notifier is true and accurate to the best of the 
notifier's knowledge.
    Upon receiving a third-party notification of super-emitter data 
through the Super Emitter Program Portal, the EPA will evaluate the 
notifications for completeness and accuracy to a reasonable degree of 
certainty. When the EPA determines that a notification has met these 
conditions, the EPA shall assign the notification a unique notification 
identification number, provide the notification to the owner/operator. 
and post the notification, except for the owner/operator attribution, 
at www.epa.gov/super-emitter. This approach responds to comments asking 
that notice of super-emitter events be provided as quickly as possible, 
both to the public and the identified owner/operator, but also that the 
owner/operator have an opportunity to respond before the super-emitter 
event is publicly attributed to a particular owner/operator. The EPA 
shall post owner/operator attributions that have been confirmed through 
the responses received; where response submittal deadlines have passed 
but no responses have been received, the EPA intends to post owner/
operator attributions that the EPA reasonably believes to be accurate.
d. Identification of a Super-Emitter Event
    In the final rules, the owner or operator must initiate an 
investigation within 5 days after receiving an EPA notification of a 
super-emitter event and report the results to the EPA within 15 days 
after receiving such notification. If an owner or operator determines 
that they do not own or operate a well site, centralized production 
facility, or compressor station within 50 meters from the latitude and 
longitude provided in the notification, the owner or operator must 
report that to the EPA and the investigation is then complete. 
Otherwise, the owner or operator must investigate to determine the 
source of the super-emitter event.
    As explained earlier in this section X.C, a super-emitter event may 
have been emitted from one or more of the following: (1) an affected 
facility or associated equipment (e.g., a control device or CVS) 
subject to regulation under NSPS OOOO, OOOOa, or OOOOb (``NSPS 
sources''); (2) a designated facility or associated equipment subject 
to a state or Federal Plan promulgated pursuant to EG OOOOc (``EG 
sources''); or (3) an unregulated source (i.e., one that is not (1) or 
(2) above). Therefore, the investigation is not limited to NSPS or EG 
sources but also includes other sources that the owner or operator may 
suspect could be the source of the super-emitter event.
    The owner or operator must investigate and report to the EPA the 
results of the investigation within 15 days after receiving a 
notification from the EPA. The owner and operator must also maintain a 
record of these investigations. To provide confidence in the reported 
information, the final rule has updated the list of investigations that 
the EPA believes will most likely reveal the source of the super-
emitter event. Because the relevant investigations for identifying the 
source(s) of the super-emitter event may vary depending on what the 
third-party data reveals, the final rules defer to the owner and 
operator in deciding the appropriate investigation(s). However, where 
there are affected or designated facilities or associated equipment 
onsite, the owner and operator may conclude that they are unable to 
identify the source of the super-emitter event only after having 
conducted the applicable investigation listed in the respective final 
rule for each affected or designated facility and associated equipment.
    The list of potential actions to identify the potential cause of 
super-emitter events may include but are not limited to the following:
    <bullet> Review any maintenance activities (e.g., liquids 
unloading) or process activities starting from the date of detection of 
the super-emitter event as identified in the notification.
    <bullet> Review all monitoring data from control devices (e.g., 
flares) over the same time period.
    <bullet> Review any fugitive emissions survey performed under a 
fugitive emissions monitoring plan over the same time period.
    <bullet> Review data from any continuous alternative technology 
systems over the same time period.
    <bullet> Screen the entire well site, centralized production 
facility, or compressor station with OGI, EPA Method 21, or an 
alternative test method(s).
e. Super-Emitter Event Report
    As was proposed, the final rules require that the owner or operator 
submit a report to the EPA within 15 days after receiving a Super-
Emitter Event notification through the Super Emitter Program Portal, 
including an attestation that the report is complete and accurate. The 
report must include the following information:
    <bullet> Notification Report ID
    <bullet> Confirmation that you are the owner or operator of the oil 
and gas facility within the immediate area (i.e., 50 meters) of the 
latitude and longitude provided in the notification. If you do not own 
or operate an oil and gas facility within 50 meters of the of the 
latitude and longitude provided in the notification, you are not 
required to provide the additional information described below.
    <bullet> General identification for the facility, including 
physical address and applicable ID (e.g., EPA ID Number, American 
Petroleum Institute (API) Well ID) and the responsible official.
    <bullet> Whether there are affected facilities or associated 
equipment subject to NSPS OOOO, OOOOa or OOOOb or designated facilities 
or associated equipment subject to a state or Federal plan pursuant EG 
OOOOc.
    <bullet> Attestation that investigations were conducted to verify 
the presence or the absence of a super-emitter event.
    <bullet> If you were unable to identify the source of the super-
emitter and if there are NSPS OOOO, OOOOa or OOOOb affected facilities 
or associated equipment, or designated facilities or associated 
equipment subject to a state or Federal plan pursuant EG OOOOc, onsite, 
confirmation that you have conducted all investigations listed in the 
Super Emitter Program (as specified above in section X.C.2.d) that are 
applicable to such affected or designated facilities and associated 
equipment.

[[Page 16881]]

    <bullet> If a super-emitter source is identified, what the source 
is and whether it is (i) an affected facility or associated equipment 
subject to NSPS OOOO, OOOOa, or OOOOb or (ii) a designated facility or 
associated equipment subject to a state or Federal plan under EG OOOOc.
    <bullet> If a super-emitter event is found, the date and time the 
super-emitter event ended.
    Upon receiving this information from the owner or operator, the EPA 
will update the notification report with the information provided by 
the owner or operator and will make the updated report publicly 
available at www.epa.gov/super-emitter. If a super-emitter event 
emitted from an NSPS OOOO, OOOOa or OOOOb affected facility or 
associated equipment or a designated facility or associated equipment 
subject to a state or Federal plan pursuant EG OOOOc, or associated 
equipment, is ongoing, you are also required to report to the Super 
Emitter Program Portal the following information:
    <bullet> A short narrative on how you intend to end the super-
emitter event, including the targeted date for completion.
    <bullet> Within 5 days after the super-emitter event has ended, the 
date and time the super-emitter event ended.
    As discussed earlier in this section X.C, CAA 114(a) gives the EPA 
broad authority to require that owners and operators investigate and 
report all sources that they suspect may have caused or contributed to 
the super-emitter event specified in the EPA notice that they have 
received under the Super Emitter Program. CAA 114(a) does not require 
regulatory text for the EPA to exercise its information gathering 
authority under CAA 114(a), and the EPA believes that adequate notice 
is provided in this Federal Register document, which clearly sets forth 
the required investigations and reporting requirements under the Super 
Emitter Program and their applicability to all oil and gas emission 
sources, whether or not they are subject to any applicable CAA section 
111 standard. Nevertheless, to facilitate the implementation of the 
Super Emitter Program, the EPA has codified provisions of the Super 
Emitter Program into the regulatory text of the new NSPS OOOOb and, as 
appropriate, in the model rule implementing EG OOOOc and amendments to 
NSPS OOOO and OOOOa. Specifically, NSPS OOOOb provides the major 
framework for the Super Emitter Program, including criteria for 
certifying third-party notifiers, criteria for third-party 
notifications to the EPA, and provisions governing the EPA's 
notification of identified owners and operators.\191\ In addition, NSPS 
OOOOb includes regulatory text governing the investigation and 
reporting as they relate to NSPS OOOOb affected facilities and 
associated equipment. Similarly, the EPA has amended NSPS OOOO and 
OOOOa to include super-emitter event investigation and reporting 
requirements as they relate to affected facilities and associated 
equipment under those NSPS. Such provisions are also included in the 
model rule implementing EG OOOOc. In addition, both NSPS OOOOb and the 
model rule implementing EG OOOOc includes a requirement to repair 
fugitive component(s) that owners and operators have identified as the 
source of super-emitter event specified in the EPA notice; as explained 
earlier in this section X.C, the standards for fugitive emissions 
components affected facilities under NSPS OOOOb (and presumptive 
standards under EG OOOOc) include a requirement to repair fugitive 
component(s) that owners and operators have identified as the source of 
super emitter-event specified in the EPA notice.
---------------------------------------------------------------------------

    \191\ Unlike the EPA, the Super Emitter Program imposes no 
obligations on States; their obligation under this final rule is to 
promulgate a state plan implementing EG OOOOc, as required under CAA 
111(d) and EPA's implementing regulation at 40 CFR part 60, subpart 
Ba.
---------------------------------------------------------------------------

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

D. Process Controllers

    Process controllers are automated instruments used for maintaining 
a process condition, such as liquid level, pressure, pressure 
difference, or temperature. In the oil and gas industry, many process 
controllers are powered by pressurized natural gas and emit natural gas 
to the atmosphere. However, process controllers may also be powered by 
electricity or compressed air, and these types of controllers do not 
use or emit natural gas. Natural gas-driven process controllers are a 
significant source of methane emissions. For instance, in the 2019 
GHGRP, methane emissions from process controllers made up 65 percent of 
the total methane emissions from petroleum system onshore production 
and 28 percent of the total methane emissions from natural gas systems 
onshore production.
    In the December 2022 Supplemental Proposal, the EPA proposed a 
``zero emissions'' VOC and methane standard in NSPS OOOOb and a ``zero 
emissions'' methane presumptive standard in EG OOOOc. This standard can 
be achieved by using a process controller that is not powered by 
natural gas, by capturing the emissions from the natural gas-driven 
controllers and routing them to a process, or by using self-contained 
controllers. The proposed rules included an exemption from the zero-
emissions requirement for process controllers in Alaska at locations 
where access to electrical power from the power grid is not available. 
The proposed requirements for these sources in Alaska were to use lower 
emitting natural gas-driven process controllers and to perform 
inspections to ensure that they are operating properly. While there are 
changes to some compliance aspects in the final rules, such as a 
further-out compliance date than proposed with an interim standard for 
the NSPS, the zero-emissions standard in NSPS OOOOb and presumptive 
standard in EG OOOOc (with the Alaska exemption) are being finalized as 
proposed.
1. NSPS OOOOb
a. Affected Facility
    The standards apply to the collection of new, modified, and 
reconstructed natural gas-driven process controllers at a site (i.e., a 
well site, centralized production facility, onshore natural gas 
processing plant, or compressor station). Process controllers that are 
emergency shutdown devices (ESD) or that are not

[[Page 16882]]

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

                           Table 12--Summary of Process Controller Emissions Standards
----------------------------------------------------------------------------------------------------------------
                                                                                    Emissions
                                     Site has access to           Emissions         standard
       Location of site               electrical power            standard         compliance
                                                                                     method
------------------------------------------------------------------------------------------------
Outside Alaska................  Yes or No...................  Zero GHG and VOC  Use process
                                                               emissions.        controllers not
                                                                                 driven by
                                                                                 natural gas
                                                                                Or
                                                                                Route natural
                                                                                 gas-driven
                                                                                 process
                                                                                 controller
                                                                                 emissions
                                                                                 through a
                                                                                 closed vent
                                                                                 system to a
                                                                                 process
                                                                                Or
                                                                                Use self-
                                                                                 contained
                                                                                 natural gas-
                                                                                 driven process
                                                                                 controllers
                                                                                Or
                                                                                Other means to
                                                                                 achieve zero-
                                                                                 emissions
                                                                                 standard.
In Alaska.....................  Yes.........................  Zero GHG and VOC  Use process
                                                               emissions.        controllers not
                                                                                 driven by
                                                                                 natural gas
                                                                                Or
                                                                                Route natural
                                                                                 gas-driven
                                                                                 process
                                                                                 controller
                                                                                 emissions
                                                                                 through a
                                                                                 closed vent
                                                                                 system to a
                                                                                 process
                                                                                Or
                                                                                Use self-
                                                                                 contained
                                                                                 natural gas-
                                                                                 driven process
                                                                                 controllers
                                                                                Or
                                                                                Other means to
                                                                                 achieve zero-
                                                                                 emissions
                                                                                 standard.
In Alaska.....................  No..........................  95 percent        Route natural
                                                               emissions         gas-driven
                                                               control.          process
                                                              Or..............   controller
                                                              Emissions          emissions
                                                               achieved by use   through a
                                                               of low-           closed vent
                                                               emitting          system to a
                                                               controllers.      control device
                                                                                 that reduces
                                                                                 emissions by
                                                                                 >=95 percent
                                                                                Or
                                                                                Use low-bleed or
                                                                                 intermittent
                                                                                 vent natural
                                                                                 gas-driven
                                                                                 process
                                                                                 controllers
                                                                                 with monitoring
                                                                                 for
                                                                                 intermittent
                                                                                 process
                                                                                 controllers.
----------------------------------------------------------------------------------------------------------------

    Based on comments expressing concerns about new sources' ability to 
obtain the equipment necessary to demonstrate compliance with the final 
standard of zero emissions immediately upon the effective date of the 
final rule, the EPA is finalizing a NSPS compliance deadline for 
process controllers that allows for up to 1 year from the effective 
date of the final rule. This means that new sources will have up to 1 
year to come into full compliance with the final standard of zero 
emissions. Until that final date of compliance, owners and operators 
must demonstrate compliance with an interim standard which mirrors the 
requirements for sites in Alaska that do not have access to electrical 
power. This topic is explained in detail in section XI.D.4 below.
c. Monitoring Requirements
    Monitoring is required for most natural gas-driven process 
controllers. For self-contained process controllers, initial and 
periodic monitoring is required to demonstrate that there are no 
identifiable emissions from the process controller. For intermittent 
process controllers (allowed at sites in Alaska without access to 
electrical power), initial and periodic monitoring is required to 
demonstrate that there are no identifiable emissions from the process 
controller when the process controller is idle. For process controllers 
that have emissions routed through a closed vent system to a process or 
to a

[[Page 16883]]

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

    Table 13--Summary of Process Controller Inspection and Monitoring
                              Requirements
------------------------------------------------------------------------
                                                           Monitoring
        Equipment type          Monitoring requirement      frequency
------------------------------------------------------------------------
Natural gas-driven self-        Use OGI or EPA Method   Initially and
 contained controllers.          21 to demonstrate no    quarterly.
                                 identifiable
                                 emissions from the
                                 process controller.
Natural gas-driven              Use OGI or EPA Method   Initially and
 intermittent vent controllers   21 to demonstrate no    quarterly.
 (Alaska-only sites without      identifiable
 electrical power).              emissions occur
                                 during idle periods.
Closed vent system on a         Use OGI or EPA Method   Initially and
 natural gas-driven process      21 to demonstrate no    quarterly..
 controller.                     identifiable
                                 emissions from the
                                 closed vent system.
                                AVO monitoring........  Initially and bi-
                                                         monthly.
                                Inspection for defects  Annually.
                                 that could result in
                                 air emissions.
Control device for a natural    Parameter monitoring..  Continuously
 gas-driven process controller  Visible emissions       Monthly.
 (Alaska-only sites without      inspections for
 electrical power).              enclosed combustion
                                 devices and flares.
                                Or
                                Surveillance camera     Continuously.
                                 monitoring.
------------------------------------------------------------------------

d. Recordkeeping and Reporting Requirements
    Owners or operators of a process controller affected facility are 
required to submit information about the affected process controller 
facility in annual reports. The information required for the first 
annual report includes an identification of each natural gas-driven 
controller included in the process controller affected facility and an 
identification of the emissions standards compliance method that will 
be used for the affected facility. The initial annual report must also 
include a demonstration that a natural gas-driven process controller 
with a bleed rate greater than 6 scfh is required if such a process 
controller is used in Alaska at a site without access to electricity 
(the standard allows a process controller with a bleed rate greater 
than 6 scfh in certain circumstances), and also a certification that 
the closed vent system is adequately designed if a closed vent system 
is used for a process controller affected facility. After the initial 
annual report, this information about the affected facility is only 
required to be submitted in the annual report if there are changes to 
the previously submitted information. Each annual report must include 
the dates and results of inspections conducted for self-contained and 
intermittent vent natural gas-driven process controllers, inspections 
of closed vent systems (for sites routing emissions to a process or 
sites in Alaska routing emissions to a control device), monitoring and 
inspections of control devices (for sites in Alaska using a control 
device to reduce emissions by 95 percent), and information for any 
deviations from the process controller emissions standards that 
occurred during the reporting period.
    Owners and operators are also required to keep records of the 
information submitted in the annual reports regarding the process 
controller affected facility, and if applicable, the records required 
for monitoring and inspections of closed vent systems, control devices, 
self-contained process controllers, and intermittent vent process 
controllers. Records of each deviation must also be kept.
2. EG OOOOc
a. Designated Facility
    The final EG define designated facilities for purposes of process 
controllers as the collection of existing natural gas-driven process 
controllers at a well site, centralized production facility, onshore 
natural gas processing plant, or compressor station. Process 
controllers that are emergency safety devices (ESD) or that are not 
natural gas-driven are not included in the designated facility.
b. Final Presumptive Standards
    The presumptive methane standards for existing sources under EG 
OOOOc are the same as the final methane standards for new sources under 
NSPS OOOOb.
c. Monitoring Requirements
    The monitoring requirements in EG OOOOc are the same as those for 
NSPS OOOOb.
d. Recordkeeping and Reporting Requirements
    The recordkeeping and reporting requirements in EG OOOOc are the 
same as those for NSPS OOOOb.

E. Pumps

    In the oil and natural gas industry, pumps are used for many 
purposes, including chemical injection, hot glycol circulation for heat 
tracing/freeze protection, and glycol circulation in dehydrators. These 
pumps are generally either piston pumps or diaphragm pumps that can be 
powered by compressed air, compressed natural gas, or electricity. Of 
these pumps, those that are pneumatic units driven by natural gas emit 
methane and VOC to the atmosphere as part of their normal operation. In 
many situations across all segments of the oil and gas industry, 
natural gas-driven pneumatic pumps are used where electricity is not 
readily available.
    In the December 2022 Supplemental Proposal, the proposed standard 
in NSPS OOOOb and presumptive standard in EG OOOOc was zero emissions 
of methane and VOC. The proposed standards may be achieved by the use 
of pumps not powered by natural gas. In that situation, the pump would 
not be an affected or designated facility because it would not be 
powered by natural gas. For sites in the

[[Page 16884]]

production or transmission and storage segment of the industry without 
access to electricity from the power grid, the proposed standards in 
the December 2022 Supplemental Proposal included a complex hierarchical 
structure that allowed the use of natural gas-driven pumps in certain 
situations based on the technical feasibility of pump control measures 
and the existence of situations that would allow the emissions to be 
routed to a process or to a control device already on a site. In the 
final rule, the complex hierarchical structure has been removed, and 
final NSPS OOOOb and EG OOOOc (presumptive standard) specify zero 
emissions for all pumps except those at sites without access to 
electricity with fewer than three natural gas-driven diaphragm pumps. 
For those sites, the final standards in NSPS OOOOb and presumptive 
standards in EG OOOOc are based on whether an existing situation exists 
that allows the emissions to be routed to a process or to a control 
device already on site.
1. NSPS OOOOb
a. Affected Facility
    The pump standards apply to the collection of new, modified, and 
reconstructed natural gas-driven pumps at a well site, centralized 
production facility, onshore natural gas processing plant, or 
compressor station. Pumps that are in operation less than 90 days per 
calendar year or that are not natural gas-driven are not included in 
the affected facility.
b. Final Standards
    The standards that apply differ depending on the number of natural 
gas-driven diaphragm pumps at the site (i.e., well site, centralized 
production facility, onshore natural gas processing plant, or 
compressor station) and whether the site has access to electrical grid 
power. For any site with access to electrical power and for sites 
without access to electrical power that have three or more natural gas-
driven diaphragm pumps, the standard for all pumps in the affected 
facility is zero emissions of VOC and GHG (in the form of methane). 
Zero emissions of VOC and GHG may be achieved by either using pumps 
that are not driven by natural gas (and are therefore not affected 
facilities), by routing natural gas-driven pump vapors through a closed 
vent system to a process, or by other means that achieves the standard 
of zero emissions. For sites without access to electrical power that 
have fewer than three diaphragm pumps (two or one), the standards 
require that GHG and VOC emissions from all natural gas-driven pumps in 
the affected facility be routed to a process if a vapor recovery unit 
(VRU) is onsite. If a VRU is not onsite, emissions must be reduced by 
95 percent if a control device with at least this emissions reduction 
capability is already available onsite, or be reduced by less than 95 
percent if a control device is onsite but is not capable of reducing 
GHG and VOC emissions by 95 percent or more. Table 14 summarizes the 
emissions standards for pumps.

                                  Table 14--Summary of Pump Emissions Standards
----------------------------------------------------------------------------------------------------------------
                                        Number of natural gas-
 Facility site  electrical access  to  driven  diaphragm pumps
                power?                    at pump  affected             Standard            Compliance method
                                            facility site
----------------------------------------------------------------------------------------------------------------
Yes..................................  Any....................  Zero GHG and VOC         Use pumps not driven by
                                                                 emissions.               natural gas
                                                                                         Or
                                                                                         Route pump emissions
                                                                                          through a closed vent
                                                                                          system to a process
                                                                                         Or
                                                                                         Other means to achieve
                                                                                          zero-emissions
                                                                                          standard.
No...................................  Has >=3 diaphragm pumps  Zero GHG and VOC         Use pumps not driven by
                                                                 emissions.               natural gas
                                                                                         Or
                                                                                         Route pump emissions
                                                                                          through a closed vent
                                                                                          system to a process
                                                                                         Or
                                                                                         Other means to achieve
                                                                                          zero-emissions
                                                                                          standard.
No...................................  Has <3 diaphragm pumps.  Control emissions if     Route pump emissions
                                                                 VRU or control device    through a closed vent
                                                                 is already present at    system to a process if
                                                                 site and can accept      a VRU is onsite; if no
                                                                 emissions from pumps.    VRU onsite, route
                                                                                          emissions to a control
                                                                                          device that reduces
                                                                                          emissions by >=95
                                                                                          percent; if no control
                                                                                          device capable of
                                                                                          reducing emission by
                                                                                          >=95 percent is
                                                                                          present then still
                                                                                          route to control
                                                                                          device if present.
----------------------------------------------------------------------------------------------------------------

    Just as with process controllers, and based on comments expressing 
concerns about new sources' ability to obtain the equipment necessary 
to demonstrate compliance with the final standard of zero emissions 
immediately upon the effective date of the final rule, the EPA is 
finalizing a NSPS compliance deadline for pumps that allows for up to 1 
year from the effective date of the final rule. This means that new 
sources will have up to 1 year to come into full compliance with the 
final standard of zero emissions. Until that final date of compliance, 
owners/operators must demonstrate compliance with an interim standard 
which mirrors the requirements for pumps at sites without access to 
grid electricity that have fewer than three diaphragm pumps found at 40 
CFR 60.5393b(b). This topic is explained in detail in section XI.E.2 
below.
c. Monitoring Requirements
    Monitoring is required for pump affected facilities that have 
emissions routed to a process or control device. For these affected 
facilities, initial and periodic monitoring is required to demonstrate 
that there are no identifiable emissions from the closed vent system. 
In addition to the closed vent system monitoring requirements, pumps 
that have emissions routed through a closed vent system to a control 
device reducing emissions by 95 percent or more must perform the 
monitoring specified in 40 CFR 60.5417b for the particular type of 
control device that is used. As further discussed in sections X.H and 
XI.H of this document, each control device must have a continuous 
parameter system installed and a continuous recording device for the 
monitoring results.

[[Page 16885]]

Enclosed combustion devices and flares also must have either periodic 
visible emissions inspections or use a surveillance camera system to 
monitor for visible emissions. A summary of the required monitoring for 
pump affected facilities is shown in table 15.

    Table 15--Summary of Pump Inspection and Monitoring Requirements
------------------------------------------------------------------------
                                      Monitoring          Monitoring
         Equipment type               requirement          frequency
------------------------------------------------------------------------
Closed vent system on a natural   Use OGI or EPA      Initially and
 gas-driven pump.                  Method 21 to        quarterly.
                                   demonstrate no
                                   identifiable
                                   emissions from
                                   the closed vent
                                   system.
                                  AVO monitoring....  Initially and bi-
                                                       monthly.
                                  Inspection for      Annually.
                                   defects that
                                   could result in
                                   air emissions.
Control device achieving 95       Control device      Continuously.
 percent emissions reduction for   parameter
 a natural gas-driven pump.        monitoring..
                                  Visible emissions   Monthly.
                                   inspections for
                                   enclosed
                                   combustion
                                   devices and
                                   flares.
                                  Or
                                  Surveillance        Continuously.
                                   camera monitoring.
------------------------------------------------------------------------

d. Recordkeeping and Reporting Requirements
    Owners or operators of a pump affected facility are required to 
submit information about the affected pump facility in annual reports 
after becoming subject to NSPS OOOOb. The information required for the 
first annual report includes an identification of each natural gas-
driven pump included in the pump affected facility and an 
identification of the emissions standards compliance method that will 
be used for the affected facility. The initial annual report must also 
include a certification that the closed vent system is adequately 
designed if a closed vent system is used for the pump affected 
facility. If complying by using a control device that achieves less 
than 95 percent emissions control or if no control device will be used, 
owners or operators must include a certification that no control device 
is on site that is capable of achieving a 95 percent emissions 
reduction or a certification that no control device is present at the 
site. After the initial annual report, this information about the 
affected facility is only required to be submitted in the annual report 
if there are changes to the previously submitted information. Each 
annual report must include the dates and results of inspections 
conducted of closed vent systems, monitoring and inspections of control 
devices that reduce emissions by 95 percent or more, and information 
for any deviations from the pump emissions standards that occurred 
during the reporting period.
    Owners and operators are also required to keep records of the 
information submitted in the annual reports regarding the pump affected 
facility, and if applicable, the records required for monitoring and 
inspections of closed vent systems and control devices. Records of each 
deviation must also be kept.
2. EG OOOOc
a. Designated Facility
    These final EG define designated facilities as the collection of 
natural gas-driven pumps at a well site, centralized production 
facility, onshore natural gas processing plant, or compressor station. 
Pumps that are in operation less than 90 days per calendar year or that 
are not natural gas-driven are not included in the designated facility.
b. Final Presumptive Standards
    The presumptive methane standards for existing sources under EG 
OOOOc are the same as the methane standards for new sources under NSPS 
OOOOb.
c. Monitoring Requirements
    The monitoring requirements in EG OOOOc are the same as those for 
NSPS OOOOb.
d. Recordkeeping and Reporting Requirements
    The recordkeeping and reporting requirements in EG OOOOc are the 
same as those for NSPS OOOOb.

F. Wells and Associated Operations

    A well is a hole drilled for the purpose of producing oil or 
natural gas. Many of the sources covered by NSPS OOOOb and addressed by 
EG OOOOc are associated with processes and equipment that is used to 
handle, store, move, and process the oil and natural gas downstream of 
the well. There are three sources, however, that are more directly 
related to the well itself. These are well completions, liquids 
unloading from gas wells, and associated gas from oil wells. In the 
November 2021 Proposal, the EPA proposed separate NSPS OOOOb affected 
facility definitions for each of these three sources. The result of 
including all three definitions would have been that a single well 
could have three different affected facilities for three different 
emissions sources. In the December 2022 Supplemental Proposal, to 
eliminate the potential confusion from this complex regulatory 
structure, the EPA proposed to change its approach as part of the 
supplemental proposal. Rather than three separate well affected 
facilities, the EPA proposed a definition of well affected facility, 
which is defined as a single well. Separate standards were proposed for 
well completions, liquids unloading from gas wells, and associated gas 
from oil wells. This structure is retained in the final rule.
    For existing sources, there will never be well completions, as that 
activity is only performed for newly constructed or reconstructed/
modified wells. Therefore, the proposed EG OOOOc in the 2022 
Supplemental Proposal included the same basic definition for well 
designated facility, but only included presumptive standards for 
liquids unloading from gas wells and associated gas from oil wells. 
This structure is also retained in the final EG OOOOc.
    The following sections summarize the final NSPS OOOOb and EG OOOOc. 
Specifically, section X.F.1 addresses the affected facility and 
designated facility definitions, section X.F.2 addresses the standards 
and presumptive standards for associated gas wells, section X.F.3 
addresses the standards and presumptive standards for liquids 
unloading, and section X.F.4 addresses the standards for well 
completions.

[[Page 16886]]

1. Well Affected and Designated Facility Definitions
a. NSPS OOOOb
    Well affected facility. Each well affected facility, which is a 
single well.
    (1) In addition to 40 CFR 60.14, a ``modification'' of an existing 
well occurs when:
    (i) An existing well is hydraulically fractured, or
    (ii) An existing well is hydraulically refractured.
b. EG OOOOc
    Well designated facility. Each well designated facility, which is a 
single well.
2. Associated Gas From Wells Producing Primarily Oil
a. NSPS OOOOb
i. Affected Facility and Final Work Practice Standards
    Each well affected facility that produces associated gas is subject 
to the standards, where associated gas is defined as natural gas which 
originates at wells operated primarily for oil production that is 
released from the liquid hydrocarbon during the initial stage of 
separation after the wellhead. For the purpose of distinguishing wells 
operated primarily for oil production that produce associated gas from 
wells operated primarily for gas production, the EPA refers to the 
former as associated gas wells in this final rule. To provide 
additional clarity regarding which wells are affected facilities 
subject to the associated gas standards, the EPA added a definition of 
associated gas to this final rule. In order to clearly distinguish 
associated gas from gas vented during well completion activities, the 
definition of associated gas specifies that associated gas production 
begins at the startup of production after the flow back period ends. 
Further, the EPA has chosen not to define oil wells or gas wells in 
NSPS OOOOb or EG OOOOc.
    The NSPS OOOOb final rule separates new associated gas wells into 
multiple groups based on when construction is commenced. This grouping 
serves the purpose of a ``phase-in'' of the final rule standards which 
the EPA believes is appropriate in this situation because of certain 
changes that the EPA made to these standards between the December 2022 
Supplemental Proposal and final rule. These groups are: (1) Wells that 
commence construction after May 7, 2026, (2) wells that commence 
construction between May 7, 2024 and May 7, 2026, and (3) wells that 
commenced construction between December 6, 2022, and May 7, 2024, and 
wells that are modified or reconstructed after December 6, 2022. The 
definition of ``commenced'' within the NSPS general provisions apply 
for purposes of the NSPS OOOOb. 40 CFR 60.2.
    The final work practice standard for all three groups is largely 
the same. The associated gas must either be recovered from the 
separator and routed into a gas gathering flow line or collection 
system to a sales line, recovered from the separator and used as an 
onsite fuel source, recovered from the separator and used for another 
useful purpose that a purchased fuel, chemical feedstock, or raw 
material would serve, or recovered from the separator and reinjected 
into the well or injected into another well. The final work practice 
standard for wells in the second and third group, is very similar to 
what the EPA proposed in the December 2022 Supplemental Proposal, 
although there are certain limitations that were not included in the 
supplemental proposal, which we discuss below.
    Wells in the first group (i.e., those wells that commence 
construction after May 7, 2026) are required to route the gas to a 
sales line, use the gas as an onsite fuel source, for another useful 
purpose that a purchased fuel, chemical feedstock, or raw material 
would serve, or reinject it into the well or into another well upon 
start-up. The final standards do not allow these wells to routinely 
flare emissions because we have determined that, with advance planning, 
at least one of the options to avoid routine flaring will be feasible 
at such wells (including routing the gas to a sales line, using the gas 
as an onsite fuel source, using the gas for another useful purpose that 
a purchased fuel, chemical feedstock, or raw material would serve, or 
reinjecting it into the well or into another well). These sites must 
handle the associated gas using one of these options, but the final 
rule still includes provisions to allow short-term flaring for specific 
circumstances such as safety concerns. The EPA recognizes that this is 
a change from what was included in the December 2022 Supplemental 
Proposal because there the EPA proposed to allow certain wells to 
routinely flare provided they made a technical infeasibility 
demonstration that was certified. Because of this change at final, the 
EPA is applying this requirement (no routine flaring) to wells that 
commence construction later than 24 months after the effective date of 
this final rule. This additional time beyond the rule's effective date 
will provide owners and operators with a sufficient period to adjust to 
this change so that they can ensure compliance with the final standard 
as soon as the well starts to produce associated gas.
    Wells in the second group (i.e., wells that commence construction 
between May 7, 2024 and May 7, 2026) must comply with the final 
standard of no routine flaring on or before May 7, 2026. At that time, 
these wells will no longer be allowed to flare routinely with a showing 
of technical infeasibility, and must route associated gas to a sales 
line, use the gas for another useful purpose that a purchased fuel, 
chemical feedstock, or raw material would serve, or reinject the gas 
into the well or inject it into another well. In the interim period not 
to exceed 24 months from the effective date of the final rule, these 
wells may route the associated gas to a flare or control device that 
reduces methane and VOC emissions by at least 95.0 percent provided the 
owner/operator can demonstrate that the other control options discussed 
above are technically infeasible. Again, this will allow for a 
sufficient phase in period for owners and operators of wells in this 
group to adjust to the final standard, which is different than what the 
EPA included in the December 2022 Supplemental Proposal.
    For wells in the third group (wells that commenced construction, 
modified, or reconstructed, between December 6, 2022 (the date that the 
supplemental proposal published in the Federal Register), and May 7, 
2024), the final rule allows routing the associated gas to a flare or 
control device that reduces methane and VOC emissions by at least 95.0 
percent on a routine basis, provided that the owner or operator 
documents and certifies that routing the associated gas to a sales 
line, using it as onsite fuel or for another beneficial purpose, or 
injecting/reinjecting it are technically infeasible. This allowance for 
technical infeasibility is provided for a period of 1 year at a time. 
Owners and operators of wells in the third group must renew the 
technical infeasibility determination/certification annually to be able 
to continue to route the associated gas to a flare or control device.
    Table 16 summarizes the different groups of associated gas wells 
under NSPS OOOOb for purposes of phasing in the final rule standards 
and when routine flaring is, or is not, allowed for each group.

[[Page 16887]]



  Table 16--Summary of Allowance to Routinely Route Associated Gas to a
                 Flare or Control Device for NSPS OOOOb
------------------------------------------------------------------------
                                            Routinely route to flare/
     Construction commencement date                  control
------------------------------------------------------------------------
New well commencing construction after   Not Allowed.
 May 7, 2026.
New well commencing construction         One year upon certification of
 between May 7, 2024, and May 7, 2026.    technical infeasibility. May
                                          not exceed 790 days from
                                          publication date of the rule.
                                          Thereafter no routine flaring
                                          allowed.
New well commencing construction         One year upon certification of
 between December 6, 2022, and May 7,     technical infeasibility.
 2024.                                    Renewable upon annual
                                          recertification.
------------------------------------------------------------------------

    When associated gas is routed to a flare or control device, the 
control device must meet all the requirements specified in 40 CFR 
60.5412b. See section X.H of this preamble for more information on 
control device requirements, including requirements for flares. In 
addition, the CVS routing the associated gas to the flare or control 
device must comply with the provisions in 40 CFR 60.5411b(a) and (c).
    The EPA recognizes that temporary situations can occur beyond the 
control of an owner/operator that could make it technically infeasible 
or unsafe to comply with the standard for a limited period of time. 
Therefore, for all wells subject to NSPS OOOOb, the final rule allows 
owners and operators to route the associated gas to a flare or control 
device temporarily. Specifically, the final rule allows this for the 
situations and durations shown in table 17.

 Table 17--Situations and Durations Where Associated Gas May Temporarily
                 Be Routed to a Flare or Control Device
------------------------------------------------------------------------
    Situations where temporary routing
   associated gas to a flare or control           Maximum duration
             device is allowed
------------------------------------------------------------------------
During a deviation caused by malfunction,   24 hours.
 including for reasons of safety.
During repair, maintenance including        24 hours.
 blowdowns, a bradenhead test, a packer
 leakage test, a production test, or
 commissioning.
During temporary interruption in service    30 days.
 from the gathering or pipeline system.
If associated gas does not meet pipeline    72 hours.
 specifications.
------------------------------------------------------------------------

    The final rule requires that during any period when associated gas 
is temporarily routed to a flare, the owner or operator demonstrate 
that the flare is meeting the requirements in 40 CFR 60.5412b. See 
section X.H of this preamble for more information on control device 
standards.
    The final rule also allows short-term venting in malfunction 
situations where flaring the associated gas would cause an unsafe 
environment. This venting would be limited to 12 hours.
    As noted earlier in this preamble, for wells for which construction 
commenced between December 6, 2022, and May 7, 2024, and for wells that 
are reconstructed or modified after December 6, 2022, the final rule 
allows routinely routing the associated gas to a flare or control 
device that achieves 95.0 percent VOC and methane reduction provided a 
yearly technical infeasibility demonstration. This means routinely 
routing the associated gas to a flare or control device is allowed only 
if the owner or operator demonstrates that all four options included in 
the work practice standard discussed previously are infeasible due to 
technical reasons. In order to demonstrate such technical 
infeasibility, the final rule requires that a detailed analysis be 
performed, and that documentation be prepared that demonstrates the 
technical reasons for this infeasibility. The demonstration must 
address the technical infeasibility for all options identified in the 
rule, specifically: (1) Route into a gas gathering flow line or 
collection system to a sales line, (2) recover from the separator and 
use as an onsite fuel source, (3) recover from the separator and use 
for another useful purpose that a purchased fuel, chemical feedstock, 
or raw material would serve, or (4) recover from the separator and 
reinject into the well or injected into another well.
    The two components of a technical infeasibility demonstration are 
the list of technologies to be evaluated, and reason that each of 
technologies is infeasible. The first is the technologies or solutions 
to be evaluated. For three of the options--route into a gas gathering 
flow line or collection system to a sales line, recover from the 
separator and use as an onsite fuel source, reinject into the well or 
another well--this is straightforward. However, the third option--use 
the associated gas for another useful purpose that a purchased fuel, 
chemical feedstock, or raw material would serve--is more open ended.
    The final rule does not specify the ``other useful purpose'' 
solutions that must be evaluated, but it is the responsibility of the 
owner and operator, along with the qualified professional engineer or 
other qualified personnel performing the evaluation, to ensure that the 
list of options evaluated is comprehensive to address technically 
viable solutions.
    Technologies that are in the evaluation, pilot-plant, or testing 
stages are not considered to be technically viable.
    In summary, to demonstrate technical infeasibility in order to 
route to a flare or control device, you must establish that it is not 
technically feasible to route the associated gas into a gas gathering 
flow line or collection system to a sales line, and not technically 
feasible to use the associated gas as an onsite fuel source such as a 
generator, fuel cell, or other power-producing use, and not technically 
feasible to reinject into the well or another well, and not technically 
feasible to utilize ``other useful purposes'' of the associated gas. A 
technically viable ``other useful purpose'' is likely to require the 
routing of the associated gas to on-site or nearby equipment that 
compresses, liquifies, or transforms the gas into a physical state that 
can be transported by pipeline or other transportation mode to an 
eventual user. A determination of technical infeasibility requires a

[[Page 16888]]

showing of site-specific conditions that make these operations 
infeasible for even the most basic of such uses. One such basic use is 
capture and truck transportation offsite to a user or processing 
facility.
    The second component of the demonstration is the determination that 
each of the possibilities is infeasible. While the final rule does not 
specify criteria for technical infeasibility, the EPA generally 
characterizes acceptable reasons in the general categories of physical, 
logistical, or legal factors. Examples could include, but are not 
limited to, the following. It may be infeasible to connect to a sales 
line because of inability to secure necessary easements and/or rights-
of-way, inability to obtain necessary specialized equipment, inadequate 
capacity of gathering system to accept the gas, or production sharing 
contract restrictions. It may be infeasible to use the associated gas 
as an onsite fuel source because there are no onsite power needs or 
power needs have been met with less gas than produced, there is 
insufficient associated gas to support a small electricity generation 
plant, and there is no local demand for the power. Note that it would 
be difficult to claim technical infeasibility based on no onsite power 
needs if the site has equipment that is burning diesel or other fuel 
which could be replaced by using the associated gas. Reinjection may be 
infeasible because there is no subsurface reservoir or other storage 
available for reinjection in the vicinity. To demonstrate that the 
``other beneficial use'' option is not technically feasible an owner or 
operator could show that there is an observable or demonstrable reason 
that the operator cannot install equipment to convert associated gas to 
compressed natural gas (CNG) at the well site due to physical or 
technical constraints and/or that CNG transport in the region is not 
available. It is expected that owners and operators will conduct 
detailed evaluations of all such options. The analysis must show clear 
evidence that the owner and operator has conducted due diligence to 
understand the situations where the solution is being successfully 
utilized and a demonstration of why it is not feasible at their site. 
Note that the EPA acknowledges that the unavailability of a solution, 
even one that has been demonstrated at one or more sites in the U.S., 
is a valid reason for an infeasibility conclusion. One overarching 
factor that may impact technical feasibility is the composition of the 
gas. The EPA recognizes that there are situations (e.g., high sulfur 
content, high CO<INF>2</INF> and low methane content) where some 
solutions may be infeasible.
    Each infeasibility demonstration must be certified by a qualified 
professional engineer or other qualified individual with expertise in 
the uses of associated gas. This certification must state: ``I certify 
that the assessment of technical and/or safety infeasibility was 
prepared under my direction or supervision. I further certify that the 
assessment was conducted, and this report was prepared, pursuant to the 
requirements of 40 CFR 60.5377b(b)(1). Based on my professional 
knowledge and experience, and inquiry of personnel involved in the 
assessment, the certification submitted herein is true, accurate, and 
complete.''
    Where available, each properly executed infeasibility determination 
and certification allows the owners and operators of that particular 
well site to routinely flare the associated gas for a one-year period. 
While some new and modified sites can make such showings to routinely 
flare, this mechanism is not available to all new well sites. See table 
16 above. In the fast-moving landscape of the oil and natural gas 
industry, there are a variety of factors that could change the 
circumstances present when the previous infeasibility determination was 
performed. For example, a gathering system could have been built or 
extended in the vicinity of the well, the site could have expanded 
operations and have a need for onsite power, or a new commercially 
viable solution could become available. For this reason, the final rule 
requires that an updated infeasibility determination and certification 
be performed each year and submitted in the annual compliance report. 
If an option that was technically infeasible before has since become 
available, meaning that the reason that such option was technically 
infeasible before has changed in a way that the option is now feasible, 
then the owner/operator of the well must utilize that option going 
forward and must cease routine flaring.
ii. Recordkeeping and Reporting Requirements
    For affected facilities, required records include documentation of 
the specific type(s) of compliance methods used (i.e., routed into a 
gas gathering flow line or collection system to a sales line, used as 
an onsite fuel source, used for another useful purpose that a purchased 
fuel or raw material would serve, reinjected into the well or injected 
into a another well). For those temporary situations where the 
associated gas must be routed to a flare or control device, owners/
operators must document the reason for this temporary flaring, along 
with the duration. If the gas is routed to a flare either on a 
temporary or routine basis, records must be kept demonstrating that 
flares meet the requirements outlined in 40 CFR 60.5412b. This 
information must also be reported in the annual report. For those 
temporary situations where the associated gas is vented due to 
malfunction situations where flaring or routing to a control device 
would cause an unsafe environment, the owner or operator must document 
the reason for this venting, along with the duration, the volume of gas 
vented, and the VOC and methane emissions. The annual report must 
include all information for each venting episode.
    For wells that properly demonstrate technical infeasibility and 
therefore routinely route the associated gas to a flare or control 
device that achieves 95.0 percent reduction in VOC and methane, 
detailed records must be maintained supporting the infeasibility 
determination due to technical reasons, along with the signed 
certification by a qualified professional engineer or other qualified 
individual. This information must also be included in the annual 
report. As discussed previously, this demonstration and certification 
is required to be updated annually.
    In addition, all records associated with a demonstration of proper 
design and operation of the control device, where used, must be 
maintained (see section X.H of this preamble). For all instances where 
associated gas is temporarily vented due to malfunction situations 
where flaring or routing to a control device would cause an unsafe 
environment, an owner or operator must also document the reason for 
this venting, along with the duration, the volume of gas vented, and 
the VOC and methane emissions. The annual report must include all 
information for each venting episode.
b. EG OOOOc
i. Designated Facility
    Consistent with the NSPS OOOOb affected facility, each existing 
well that produces associated gas which commenced construction before 
December 6, 2022, is a designated facility for purposes of EG OOOOc. 
Associated gas is defined as natural gas which originates at wells 
operated primarily for oil production that is released from the liquid 
hydrocarbon during the initial stage of separation after the wellhead. 
To distinguish associated gas from gas vented during the completion 
activities, the definition of associated gas specifies that associated 
gas production begins at the

[[Page 16889]]

startup of production after the flow back period ends.
ii. Final Work Practice Presumptive Standards
    The final EG separates (subcategorizes) existing oil wells with 
associated gas into two groups based on the amount (mass) of methane in 
the associated gas. The demarcation between these two groups is 40 tons 
of methane per year. The presumptive standard in the final EG for wells 
that produce associated gas with over 40 tpy of methane is the same as 
what the EPA proposed for existing sources within the 2022 Supplemental 
Proposal.
    The presumptive standard for existing wells that produce associated 
gas with over 40 tpy of methane is summarized as follows. For these 
sites, the associated gas must either be recovered from the separator 
and routed into a gas gathering flow line or collection system to a 
sales line, recovered from the separator and used as an onsite fuel 
source, recovered from the separator and used for another useful 
purpose that a purchased fuel, chemical feedstock, or raw material 
would serve, or recovered from the separator and reinjected into the 
well or injected into another well. If all of these options are 
technically infeasible, then these existing wells (producing associated 
gas with more than 40 tpy of methane) can route associated gas to a 
flare or control device that achieve 95.0 percent reduction in methane. 
The determination of technical infeasibility must be certified by a 
professional engineer or other qualified personnel, the flare or 
control device must meet the requirements of 40 CFR 60.5412b, and 
technical infeasibility must be re-certified on an annual basis. For 
purposes of this presumptive standard, the EPA intends that technical 
infeasibility be defined in the same manner as explained above for new 
sources. See the discussion under the NSPS (see section X.F.1 of this 
document) related to the requirements for an infeasibility 
determination and certification.
    The presumptive standard in the final EG for wells that produce 
associated gas with 40 tpy of methane or less is to route associated 
gas to a flare or control device that achieves 95.0 percent reduction 
in methane. The difference between the two groups is that, for those 
existing wells with annual methane in the associated gas greater than 
40 tpy, owners and operators are required to demonstrate that it is 
infeasible for technical reasons to utilize any of the work practice 
options before they can route associated gas to a flare or control 
device. For existing wells that produce associated gas containing 40 
tpy or less of methane, flaring or routing to control is allowed 
without an infeasibility determination and certification. However, 
existing wells that produce associated gas containing 40 tpy or less of 
methane can still utilize any of the control options that result in 
zero emissions to meet the standard.
    The EPA has created subcategories for designated facilities because 
EPA's analysis conducted after reviewing comments on the 2022 
Supplemental Proposal indicates that it is not reasonable with respect 
to cost to require sources that produce less than 40 tpy methane of 
associated gas to route their associated gas to a sales line. The EPA 
analyzed the task of routing to a sales line and found that the two 
factors that controlled whether routing to a sales line was BSER was 
the distance that a pipeline would need to go to reach the sales line, 
and the amount of gas that could be recovered as measured at the 
separator. Over even short distances, the cost of routing to a sales 
line was not reasonable at very low levels of available associated gas. 
Given this and the comments that we received on this point, the EPA 
agreed with commenters that at low levels of associated gas production 
the flaring of associated gas is the BSER. See the final rule TSD 
chapter 3 on Associated Gas for further information on the 
determination of BSER for designated sources.
    In order to determine whether the methane contained in the 
associated gas is 40 tpy or less, owners and operators must utilize a 
gas-to-oil ratio (GOR)-based method derived from paragraphs 40 CFR 
98.234(m)(1) through (4) of GHGRP subpart W. Sources with methane 
contained in the associated gas greater than 40 tpy, and sources with 
methane contained in the associated gas 40 tpy or less that elect to 
comply with one of the work practices, are not required to calculate 
and document the annual methane content in the associated gas.
iii. Recordkeeping and Reporting
    The recordkeeping and reporting requirements included in EG OOOOc 
are the same as those included in the NSPS OOOOb. Wells that elect to 
demonstrate that the methane contained in the associated gas is 40 tpy 
or less are required to maintain records of this calculation and submit 
it in the annual reports.
3. Gas Well Liquids Unloading Operations
a. NSPS OOOOb
i. Affected Facility
    Each well affected facility gas well that undergoes liquids 
unloading.
ii. Final Standards
    Each affected gas well that unloads liquids is required to employ 
techniques or technology(ies) that minimize or eliminate venting of 
emissions during liquids unloading events to the maximum extent. For 
the EPA's rationale for prescribing a work practice standard over a 
numeric standard, see section XI.F.3.a of this preamble. Owners or 
operators are also allowed the option to comply with the GHG and VOC 
standards by reducing methane and VOC emissions from each gas well 
liquids unloading event by 95 percent by routing emissions to a control 
device via a CVS.
    For unloading technologies or techniques that eliminate venting of 
emissions during liquids unloading events, the final rule requires 
minimal recordkeeping and reporting.
    For unloading technologies or techniques that could result in 
venting to the atmosphere, the final rule requires work practices be 
followed. Specifically, the final rule requires that owners or 
operators employ and document best management practices to minimize or 
eliminate venting of methane and VOC emissions for each gas well 
liquids unloading operation.
    Specifically, owners or operators of well affected facilities that 
are gas wells that unload liquids must develop, maintain, and follow a 
best management practice plan to eliminate or minimize venting of 
methane and VOC emissions to the maximum extent possible from each gas 
well liquids unloading operation. This best management practice plan 
must meet the following minimum criteria: (1) Include steps that create 
a differential pressure to minimize the need to vent a well to unload 
liquids; (2) include steps to reduce wellbore pressure as much as 
possible prior to opening the well to the atmosphere; (3) unload 
liquids through the separator where feasible; and (4) close all 
wellhead vents to the atmosphere and return the well to production as 
soon as practicable.
    The best management practice plan that provides steps to minimize 
or eliminate venting of emissions would apply for both planned venting 
events and unintended/unplanned venting events due to malfunctions or 
error. In some instances, depending on the non-venting liquids 
unloading technology or

[[Page 16890]]

technique employed, the best management plan for planned and unplanned 
events may differ. In such cases, an owner or operator may choose to 
develop a separate plan to cover unplanned events. However, to minimize 
emissions, depending on technology or technique employed, the same 
minimum best management practice criteria should apply, i.e.: (1) 
Include steps that create a differential pressure to minimize the need 
to vent a well to unload liquids; (2) include steps to reduce wellbore 
pressure as much as possible prior to opening the well to the 
atmosphere; (3) unload liquids through the separator where feasible; 
and (4) close all wellhead vents to the atmosphere and return the well 
to production as soon as practicable. Where a planned or unplanned 
event occurs where best management practices were unable to be 
followed, an owner or operator is required to report those events as 
deviations. Specifically, owners or operators are required to report 
the number of liquids unloading events during the year where deviations 
from your best management practice plan occurred, the date and time the 
deviation began, the duration of the deviation in hours, documentation 
of why best management practice plan steps were not followed, and what 
steps, in lieu of your best management practice plan steps, were 
followed to minimize emissions to the maximum extent possible.
    For owners or operators that comply with the GHG and VOC standards 
by reducing methane and VOC emissions from each gas well liquids 
unloading event by 95 percent by routing emissions to a control device 
via a CVS, an owner or operator is required to maintain records and 
report that it is complying by using this option. In instances where a 
deviation from the standard has occurred during the reporting period, 
an owner or operator would be required to provide information on the 
date and time the deviation began, the duration of the deviation, and a 
description of the deviation. Additionally, the dates of each cover and 
CVS inspection, whether emissions are identified, and the date of 
repair or the date of anticipated repair if repair is delayed would be 
required in the annual report. Where bypass requirements apply, the 
date and time of each bypass alarm or each instance the key is checked 
out would be included in the annual report. For the reports and records 
that must be maintained to demonstrate proper design and operation of 
the control device, see sections X.H.1 and X.H.2 of this preamble.
iii. Recordkeeping and Reporting Requirements
    For each gas well liquids unloading operation where the technique/
technology employed eliminates venting to the atmosphere, owners or 
operators are only required to maintain the identification of the well 
affected facility and the zero-emitting technology or technique used; 
and the number of liquids unloading events conducted during the 
reporting period that had unplanned venting events (if any) that 
required that they employ best management practices to minimize 
emissions to the maximum extent possible during the unplanned event. As 
noted previously, any unplanned venting events would be subject to the 
required best management practices and associated recordkeeping and 
reporting requirements for those events.
    For each gas well liquids unloading operation where emissions are 
vented to the atmosphere, owners or operators of affected facilities 
are required to keep the following records: (1) Identification of each 
well affected facility that conducted liquids unloading during the 
reporting period that vented to the atmosphere; (2) the number of 
liquids unloading events during the reporting period that vented to the 
atmosphere; (3) documentation of your best management practice plan 
developed that meets the criteria specified in 40 CFR 60.5376b(d) of 
the final NSPS OOOOb; (4) a log of each best management practice plan 
step taken to minimize emissions to the maximum extent possible for 
each gas well liquids unloading event; and (5) documentation of each 
gas well liquids unloading event where deviations from your best 
management practice plan steps occurred, the date and time the 
deviation began, the duration of the deviation, documentation of best 
management practice plans steps were not followed, and the steps taken 
in lieu of your best management practice plan steps during those events 
to minimize emissions to the maximum extent possible. These 
requirements apply for both planned and unintended/unplanned venting 
events due to malfunctions or error.
    For each well affected facility where gas well liquids unloading 
operations are conducted, an annual report is required to include a 
summary of the information required to be maintained.
b. EG OOOOc
i. Designated Facility
    Each well designated facility gas well that undergoes liquids 
unloading.
ii. Final Presumptive Standards and Recordkeeping and Reporting 
Requirements
    The work practice standards and recordkeeping and reporting 
requirements for well designated facilities that undergo gas well 
liquids unloading under EG OOOOc are the same as those finalized for 
NSPS OOOOb.
4. Well Completions
a. NSPS OOOOb
i. Affected Facility
    Each well affected facility well completion of hydraulically 
fractured (or refractured) wells.
ii. Final Standards
    For well completion of hydraulically fractured (or refractured) 
wells, there are two subcategories of hydraulically fractured wells for 
which well completions are conducted: (1) Non-wildcat and non-
delineation wells (subcategory 1 wells); and (2) wildcat and 
delineation wells, and non-wildcat and non-delineation low-pressure 
wells (subcategory 2 wells). A wildcat well is a well drilled outside 
known fields or is the first well drilled in an oil or gas field where 
no other oil and gas production exists. A delineation well is a well 
drilled to determine the boundary of a field or producing reservoir.
    For non-wildcat and non-delineation wells (subcategory 1 wells), 
owners or operators are required to use a combination of reduced 
emissions completion (REC) equipment/practices and a completion 
combustion device to control emissions from a completion event. For 
each flowback stage (i.e., initial flowback stage, separation flowback 
stage) of the well completion, the EPA specifies requirements in the 
final rule. During the initial flowback stage, owners or operators are 
required to route the flowback to a storage vessel or completion vessel 
(frac tank, lined pit, or other vessel) and separator. During the 
separation flowback stage, owners or operators are required to route 
all salable gas from the separator to a gas flow line or collection 
system, re-inject the gas into the well or another well, use the gas as 
an onsite fuel source or use for another useful purpose that a 
purchased fuel or raw material would serve. If technically infeasible 
to route recovered gas as specified previously, recovered gas must be 
combusted. All

[[Page 16891]]

liquids, during the separation phase, must be routed to a storage 
vessel or well completion vessel, collection system, or be reinjected 
into the well or another well. The final rule requires the operator to 
have the separator available and to use the separator for the entirety 
of flowback, either by having the separator on-site or at a nearby 
centralized facility or well pad that services the well affected 
facility. A well that is not hydraulically fractured or refractured 
with liquids, or that does not generate condensate, intermediate 
hydrocarbon liquids, or produced water such that there is no liquid 
collection system at the well site is not required to have a separator 
on-site or at a centralized production facility or well pad that 
services the well completion well affected facility.
    For each wildcat and delineation well, and non-wildcat and non-
delineation low pressure wells (subcategory 2 wells), owners or 
operators must either: (1) Route all flowback to a completion 
combustion device equipped with a continuous pilot flame; or (2) route 
all flowback into one or more well completion vessels and commence 
operation of a separator unless it is technically infeasible for a 
separator to function. Gas recovered from the separator must be 
captured and routed to a completion combustion device equipped with a 
continuous pilot flame. Option (2) may only be used where the owner or 
operator is able to operate a separator, and the separator must be 
available (onsite or otherwise available for use) and must be used for 
the entirety of flowback. For both options (1) and (2), combustion is 
not required in conditions that may result in a fire hazard or 
explosion, or where high heat emissions from a completion combustion 
device may negatively impact tundra, permafrost, or waterways.
    Oil wells with a gas-to-oil ratio less than 300 scf of gas per 
stock tank barrel of oil produced are well affected facilities but have 
no requirements other than to maintain records of the low GOR 
certification and a claim signed by the certifying official.
iii. Recordkeeping and Reporting Requirements
    Owners or operators of a well affected facility must notify the 
Administrator no later than 2 days prior to the commencement of each 
well completion operation listing the anticipated date of the well 
completion operation. If an owner or operator is subject to state 
regulations that require advance notification of well completions and 
you have met those notification requirements, then you are considered 
to have met the advance notification requirements of the final rule.
    Owners or operators of well affected facilities must maintain a log 
for each well completion operation at each well affected facility. The 
log must be completed daily for the duration of the well completion 
operation and must contain specified record information (see 40 CFR 
60.5420b(c)(1)(iii)).
    Annual reports are required to include general information for all 
well affected facility reports, and for each well affected facility 
subject to well completion requirements. Owners or operators are 
required to maintain records and report information regarding each well 
completion operation conducted during the reporting period, including 
the location of the well, type of well, duration of completion event, 
and information related to the well completion itself (e.g., actions 
taken to mitigate emissions). Additionally, if venting occurs, the 
annual report is required to include the specific reasons for venting 
in lieu of capture or combustion, as well as any deviations recorded 
(i.e., the date and time the deviation began, the duration of the 
deviation in hours, and a description of the deviation).
    For each well affected facility that is an oil well with a gas-to-
oil ratio less than 300 scf of gas per stock tank barrel of oil 
produced, the annual report must include a record of the well type 
(i.e., wildcat well, delineation well, or low-pressure well) and 
supporting inputs and calculations, if applicable. The records required 
to be maintained by the owner or operator include: (1) A record of the 
analysis performed in order to make that claim, including but not 
limited to, GOR values for established leases and data from wells in 
the same basin and field; (2) the latitude and longitude of the well in 
decimal degrees to an accuracy and precision of five decimals of a 
degree using North American Datum of 1983; (3) the United States Well 
Number; and (4) a record of the claim signed by the certifying 
official.
    For each well meeting affected facility claiming an exemption at 40 
CFR 60.5375b(h) for a well modified in accordance with 40 CFR 
60.5365b(a)(1)(ii) (i.e., an existing well that is hydraulically 
refractured), the annual report must include a statement that the well 
completion operation requirements of 40 CFR 60.5375b(a)(1) through (3) 
were met. Records required to be maintained include: (1) A record of 
the latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five decimals of a degree using North 
American Datum of 1983; (2) the United States Well Number; (3) the date 
and time of the onset of flowback following hydraulic fracturing or 
refracturing; and (4) a record of the claim that the well completion 
operation requirements of 40 CFR 60.5375b(a)(1) through (3) were met.
b. EG OOOOc
    Because the fracturing or re- fracturing of an existing well would 
constitute a modification under NSPS OOOOb, it would make the existing 
well a well affected facility under NSPS OOOOb. Thus, no requirements 
are specified for well completions under EG OOOOc.

G. Centrifugal Compressors

1. NSPS OOOOb
a. Affected Facility
    The centrifugal compressor affected facility is defined as a single 
centrifugal compressor. A centrifugal compressor located at a well site 
is not a centrifugal compressor affected facility under NSPS OOOOb. A 
centrifugal compressor located at a centralized production facility is 
a centrifugal compressor affected facility under NSPS OOOOb.
b. Final Standards
    Centrifugal compressor affected facilities with wet seals must 
comply with the GHG and VOC standards by reducing methane and VOC 
emissions from each centrifugal compressor wet seal fluid degassing 
system by 95 percent by routing emissions via a CVS to a control 
device. As an alternative to routing the CVS to a control device, an 
owner or operator may also route the CVS to a process. If an owner or 
operator chooses to comply with this requirement either by using a 
control device to reduce emissions or by routing to a process to reduce 
emissions, an owner must equip the wet seal fluid degassing system with 
a cover and the cover must be connected through a CVS meeting specified 
requirements, such as design and operation with no identifiable 
emissions.
    For specified centrifugal compressors (i.e., self-contained wet 
seal compressor, wet seal compressor equipped with a mechanical seal, 
centrifugal compressors equipped with sour seal oil separator and 
capture system, centrifugal compressors equipped with dry seals), an 
owner or operator has the option to comply with the rule by meeting the 
following work practice performance-based volumetric flow rate 
standards in lieu of requiring that emissions be routed to a control 
device or process:

[[Page 16892]]

    (1) If an owner or operator uses a self-contained wet seal 
centrifugal compressor or a wet seal compressor equipped with a 
mechanical seal, an owner or operator must conduct monitoring and 
repair of the wet seal (as necessary) to maintain volumetric flow rate 
at or below 3 standard cubic feet per minute (scfm), in operating or 
standby pressurized mode, per seal. The volumetric flow rate of 3 scfm 
is an action level that, if exceeded, triggers the requirement to 
repair or replace the seal and is not a numeric limit.
    (2) Owners or operators of centrifugal compressors on the Alaska 
North Slope that are equipped with a seal oil recovery system (i.e., 
centrifugal compressors equipped with sour seal oil separator and 
capture system, such as a seal oil gas separation system that separates 
gas from the sour seal oil exiting the compressor seal assembly, 
upstream from the degassing drum) must conduct monitoring and repair of 
the wet seal (as necessary) to maintain a volumetric flow rate at or 
below 9 scfm (in operating or standby pressurized mode) per seal. The 
volumetric flow rate of 9 scfm is an action level that, if exceeded, 
triggers the requirement to repair or replace the seal and is not a 
numeric limit.
    (3) If an owner or operator uses a centrifugal compressor equipped 
with a dry seal, an owner or operator must conduct monitoring and 
repair of the dry seal to maintain a volumetric flow rate at or below 
10 scfm (in operating or standby pressurized mode) per seal. The 
volumetric flow rate of 10 scfm is an action level that, if exceeded, 
triggers the requirement to repair or replace the seal and is not a 
numeric limit. In addition to the volumetric flow rate monitoring 
required every 8,760 hours of operation, additional preventative 
(maintenance) or corrective measures may be required to maintain 
compliance with the centrifugal compressor wet and dry seal volumetric 
flow rate performance standard. Specifically, if the volumetric flow 
rate measured exceeds the flowrate specified for a centrifugal 
compressor seal, the seals connected to the measured vent must be 
repaired. Seal repair must be conducted within 90 calendar days from 
the date of the volumetric emissions measurement. If the repair of the 
wet or dry seal is technically infeasible, would require a vent 
blowdown, a compressor station shutdown, or would be unsafe to repair 
during operation of the unit, the repair can be delayed but must be 
completed during the next scheduled compressor station shutdown for 
maintenance, after a scheduled vent blowdown, or within 2 years, 
whichever is earliest. A vent blowdown is the opening of one or more 
blowdown valves to depressurize major production and processing 
equipment, other than a storage vessel. In addition, if the repair 
requires replacement of the compressor seal or a part thereof, but the 
necessary replacement seal or part cannot be acquired and installed 
within the repair timelines specified due to supplies being unavailable 
(where previously sufficiently-stocked), a delay of repair is allowed. 
However, in order to qualify for a delay of repair, the required seal 
or part replacement must be ordered no later than 10 calendar days 
after the centrifugal compressor seal is added to the delay-of-repair 
list due to parts unavailability.
    Owners or operators must conduct volumetric flow rate measurements 
from each centrifugal compressor wet and dry seal vent within 15 days 
after the repair to document that the rate has been reduced to less 
than applicable flow rate per seal. If the individual seals are 
manifolded to a single open-ended vent line, the volumetric flow rate 
must be reduced to less than the sum of the individual seals multiplied 
by the applicable required flow rate per seal.
    For the EPA's rationale for prescribing a work practice standard 
over a numeric standard, see section XI.G.2 of this preamble.
c. Recordkeeping and Reporting Requirements
    For a centrifugal compressor affected facility complying by routing 
emissions from the wet seal degassing system to a process through a 
CVS, an owner or operator is required to maintain records and report 
that it is complying by using this option. In instances where a 
deviation from the standard has occurred during the reporting period, 
an owner or operator would be required to provide information on the 
date and time the deviation began, the duration of the deviation, and a 
description of the deviation. Additionally, they would be required to 
report of the dates of each cover and CVS inspection, whether emissions 
are identified, and the date of repair or the date of anticipated 
repair if repair is delayed would be included in the annual report. 
Where bypass requirements apply, the date and time of each bypass alarm 
or each instance the key is checked out would be included in the annual 
report.
    For a centrifugal compressor affected facility complying by routing 
emissions from the wet seal degassing system to a control device 
through a CVS, an owner or operator is required to maintain records and 
report that it is complying by using this option. In instances where a 
deviation from the standard has occurred during the reporting period, 
an owner or operator would be required to provide information on the 
date and time the deviation began, the duration of the deviation, and a 
description of the deviation. Additionally, the dates of each cover and 
CVS inspection, whether emissions are identified, and the date of 
repair or the date of anticipated repair if repair is delayed would be 
required in the annual report. Where bypass requirements apply, the 
date and time of each bypass alarm or each instance the key is checked 
out would be included in the annual report. For the reports and records 
that must be maintained to demonstrate proper design and operation of 
the control device, see sections X.H.1 and X.H.2 of this preamble.
    Owners or operators complying with a performance-based emissions 
standard for specified centrifugal compressors equipped with wet seals 
and dry seals must track and report in their annual report the 
cumulative number of hours of operation of each centrifugal compressor 
since startup, or since the previous screening/volumetric flow rate 
emissions measurement, as applicable. The annual report must also 
include a description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable. 
Lastly, owners or operators must maintain records and report each 
measurement that exceeds the applicable performance-based emissions 
standard per seal during the reporting period, and the date and time 
the compressor seal was repaired to meet the required performance-based 
emissions standard per seal. In the case of delay of repair due to 
parts unavailability, operators must document the date the centrifugal 
compressor was added to the delay-of-repair list, the date the 
replacement seal or part thereof was ordered, the anticipated delivery 
date, and the actual delivery date; and the annual report needs to 
provide the reason for the needed delay and the date of anticipated 
repair.
2. EG OOOOc
a. Designated Facility
    The centrifugal compressor designated facility is defined as a 
single centrifugal compressor. A centrifugal compressor located at a 
well site is not a centrifugal compressor designated facility under EG 
OOOOc. A centrifugal compressor located at a centralized production 
facility is a centrifugal compressor designated facility under EG 
OOOOc.

[[Page 16893]]

b. Final Presumptive Standards
    For centrifugal compressor designated facilities with wet seals 
(including self-contained wet seal centrifugal compressors and 
centrifugal compressors equipped with mechanical seals) the presumptive 
GHG standards are work practice performance-based volumetric flow rate 
standards. These designated facilities must reduce methane emissions by 
maintaining a volumetric flow rate at or below 3 scfm (in operating or 
standby pressurized mode) per seal. Centrifugal compressors designated 
facilities operating on the Alaska North Slope that are equipped with a 
seal oil recovery system (i.e., centrifugal compressors equipped with 
sour seal oil separator and capture system, such as a seal oil gas 
separation system that separates gas from the sour seal oil exiting the 
compressor seal assembly, upstream from the degassing drum) must 
maintain a volumetric flow rate at or below 9 scfm (in operating or 
standby pressurized mode) per seal. The volumetric flow rates of 3 and 
9 scfm are action levels that, if exceeded, trigger the requirement to 
repair or replace the seal and are not numeric limits.
    Centrifugal compressor designated facilities with dry seals must 
maintain a volumetric flow rate at or below 10 scfm (in operating or 
standby pressurized mode) per seal. The volumetric flow rate of 10 scfm 
is an action level that, if exceeded, triggers the requirement to 
repair or replace the seal and is not a numeric limit.
    In addition to the flow rate monitoring required every 8,760 hours 
of operation, additional preventative (maintenance) or corrective 
measures may be required to maintain compliance. Specifically, if the 
volumetric flow rate measured exceeds the flowrate specified for a 
centrifugal compressor seal, the seals connected to the measured vent 
must be repaired. Seal repair must be conducted within 90 calendar days 
from the date of the volumetric emissions measurement. If the repair of 
the wet or dry seal is technically infeasible, would require a vent 
blowdown, would require a compressor station shutdown, or would be 
unsafe to repair during operation of the unit, the repair can be 
delayed but must be completed during the next scheduled compressor 
station shutdown for maintenance, after a scheduled vent blowdown, or 
within 2 years, whichever is earliest. A vent blowdown is the opening 
of one or more blowdown valves to depressurize major production and 
processing equipment, other than a storage vessel. In addition, if the 
repair requires replacement of the compressor seal or a part thereof, 
but the necessary replacement seal or part cannot be acquired and 
installed within the repair timelines specified due to supplies being 
unavailable (where previously sufficiently-stocked), a delay of repair 
is allowed. However, in order to qualify for a delay of repair, the 
required seal or part replacement must be ordered no later than 10 
calendar days after the centrifugal compressor seal is added to the 
delay-of-repair list due to parts unavailability.
    Owners or operators must conduct volumetric flow rate measurements 
from each centrifugal compressor wet and dry seal vent within 15 days 
after the repair to document that the rate has been reduced to less 
than applicable flow rate per seal. If the individual seals are 
manifolded to a single open-ended vent line, the volumetric flow rate 
must be reduced to less than the sum of the individual seals multiplied 
by the applicable required flow rate per seal.
    Owners or operators must conduct volumetric flow rate measurements 
from each centrifugal compressor wet and dry seal vent within 15 days 
after the repair to document that the rate has been reduced to less 
than applicable flow rate per seal. If the individual seals are 
manifolded to a single open-ended vent line, the volumetric flow rate 
must be reduced to less than the sum of the individual seals multiplied 
by the applicable required flow rate per seal.
    For the EPA's rationale for prescribing a work practice standard 
over a numeric standard, see section XI.G.2 of this preamble.
    As an alternative, an owner or operator may reduce methane 
emissions from each centrifugal compressor wet seal fluid degassing 
system or dry seal system by 95 percent by routing emissions via a CVS 
to a control device, or by routing emissions via a CVS to a process. If 
an owner or operator chooses to comply with the requirement either by 
using a control device to reduce emissions or by routing to a process 
to reduce emissions, an owner or operator must equip the wet seal fluid 
degassing system with a cover and the cover must be connected through a 
CVS meeting specified requirements, such as design and operation with 
no identifiable emissions.
c. Recordkeeping and Reporting Presumptive Work Practice Requirements
    Owners or operators complying with a performance-based emissions 
standard must track and report in their annual report the cumulative 
number of hours of operation of each centrifugal compressor since 
startup, or since the previous screening/volumetric flow rate emissions 
measurement, as applicable. The annual report must also include a 
description of the method used and the results of the volumetric flow 
rate measurement or emissions screening, as applicable. Lastly, owners 
or operators must maintain records and report each measurement that 
exceeds the applicable performance-based emissions standard per seal 
standard during the reporting period, and the date and time the 
compressor wet or dry seal was repaired to meet the applicable 
performance-based emissions standard. Where a delay of repair is 
needed, the annual report needs to provide the reason for the needed 
delay and the date of anticipated repair.
    For a centrifugal compressor designated facility complying with the 
routing emissions from the wet seal compressor degassing system to a 
process through a CVS, an owner or operator is required to maintain 
records and report each centrifugal compressor during the reporting 
period that is complying by using this option. In instances where a 
deviation from the standard has occurred during the reporting period, 
an owner or operator would be required to provide information on the 
date and time the deviation began, the duration of the deviation, and a 
description of the deviation. Additionally, the dates of each cover and 
CVS inspection, whether emissions are identified, and the date of 
repair or the date of anticipated repair if repair is delayed would be 
included in the annual report. Where bypass requirements apply, the 
date and time of each bypass alarm or each instance the key is checked 
out would be included in the annual report.
    For a centrifugal compressor designated facility complying with the 
routing emissions from the wet seal fluid degassing system to a control 
device through a CVS, an owner or operator is required to maintain 
records and report each centrifugal compressor during the reporting 
period that is complying by using this option. In instances where a 
deviation from the standard has occurred during the reporting period, 
an owner or operator would be required to provide information on the 
date and time the deviation began, the duration of the deviation, and a 
description of the deviation. Additionally, they would be required to 
report the dates of each cover and CVS inspection, whether emissions 
are identified, and the date of repair or the date of anticipated 
repair if repair is delayed. Where bypass requirements apply, the date 
and time of

[[Page 16894]]

each bypass alarm or each instance the key is checked out would be 
included in the annual report. For the reports and records that must be 
maintained to demonstrate proper design and operation of the control 
device, see sections X.H.1 and X.H.2 of this preamble.

A. Combustion Control Devices

1. NSPS OOOOb
a. Compliance Assurance Requirements
    NSPS OOOOb contains various compliance requirements to ensure that 
combustion control devices that are being used to meet a 95 percent 
emission reduction standard can continuously demonstrate this level of 
control of emissions from affected facilities. Except as noted in 
section XI.H of this preamble, the final compliance assurance 
requirements for combustion control devices reflect the requirements 
that were proposed in the December 2022 Supplemental Proposal.\192\ 
This section of the preamble presents a summary of the final 
requirements for combustion control devices.
---------------------------------------------------------------------------

    \192\ See section IV.H, 87 FR 74792 (December 6, 2022).
---------------------------------------------------------------------------

    Except for boilers and process heaters that introduce the vent 
stream with the primary fuel into the flame zone and flares, combustion 
control devices must demonstrate compliance with this control 
efficiency \193\ through a performance test, which must be repeated 
every 5 years. In lieu of conducting the initial performance test, 
owners and operators may purchase an enclosed combustion device that is 
tested by the manufacturer according to procedures outlined in 40 CFR 
60.5413b(d). For combustion devices where temperature is an indicator 
of destruction efficiency (e.g., incinerators), the owner or operator 
must establish a temperature limit during the performance test and 
continuously monitor the temperature after the performance test. Owners 
and operators using catalytic vapor incinerators must establish a limit 
on the temperature at the inlet of the catalyst bed and the temperature 
differential across the catalyst bed during the performance test and 
continuously monitor these temperatures after the performance test. For 
all other enclosed combustion devices and flares, the owner and 
operator must maintain the net heating value (NHV) of the gas sent to 
the device above a minimum amount if the combustion device is pressure-
assisted or uses no assist gas. If an owner or operator uses a steam-
assisted enclosed combustion device, the owner or operator must 
maintain the combustion zone NHV above a minimum level. If the owner or 
operator uses an air-assisted enclosed combustion device, the owner or 
operator must maintain the NHV dilution parameter above a minimum 
level. The combustion zone NHV and NHV dilution parameter terms account 
for the reduction in heating value caused by the introduction of air 
and/or steam. These terms ensure that the assist gas does not overwhelm 
the heating value provided by the vent gas to the point where proper 
combustion is no longer occurring.
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    \193\ Alternatively, the performance test can demonstrate 
compliance with a total organic compounds outlet concentration of 
275 ppmv on a wet basis, as propane. See section XI.H.1 of this 
preamble for more information on the alternative outlet 
concentration limit.
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    All flares and all enclosed combustion devices, other than boilers 
and process heaters that introduce the vent stream with the primary 
fuel into the flame zone and catalytic incinerators, must operate above 
a minimum flow rate established by the manufacturer. Additionally, the 
flow rate to a flare must be maintained at a level that ensures 
compliance with the flare tip velocity limits in the 40 CFR part 60 
General Provisions, and the flow rate to an enclosed combustion device 
must be below a maximum flow rate established during the performance 
test or by the manufacturer, if the initial performance test is 
performed by the manufacturer. Flares and enclosed combustion devices 
that use pressure-assisted tips to promote mixing at the burner tip are 
not subject to this maximum flow rate limit because these units are 
designed to operate at high flow rates.
    All flares and all enclosed combustion devices must also operate 
with a continuous burning pilot flame and with no visible emissions, 
except for periods not to exceed a total of 1 minute during any 15-
minute period. Compliance with the visible emissions requirement can be 
confirmed either through monthly testing using EPA Method 22 or through 
continuous use of a video surveillance camera. Additionally, during 
each fugitive emissions inspection conducted using an OGI camera, 
including those conducted in response to periodic screening events 
using alternative technologies, owners and operators must observe each 
enclosed combustion device and flare to determine if it is operating 
properly, ensuring that a flame is present and that there is no 
indication of uncontrolled emissions. During each fugitive emissions 
inspection conducted using AVO, owners and operators must observe each 
enclosed combustion device and flare to determine if it is operating 
properly, visually confirming that the pilot flame is lit and operating 
properly.
    Owners and operators also have the option to request an alternative 
test method to demonstrate continuous 95.0 percent control of 
emissions. In this option, the owner or operator would demonstrate that 
the combustion device continuously achieves 95.0 percent combustion 
efficiency or that the combustion device continuously complies with the 
combustion zone NHV and NHV dilution parameter requirements. The 
alternative test method would be used in lieu of the other monitoring 
required for combustion device (e.g., vent gas NHV, flow rate).
b. Recordkeeping and Reporting Requirements
    Owners and operators are required to maintain records and report 
the results of all performance tests conducted on combustion control 
devices. Additionally, for each continuous parameter monitoring system 
(CPMS) that is used to demonstrate continuous compliance for a 
combustion control device, owners and operators must report the 
identity of the CPMS, the date of last calibration, and the date, 
duration, and cause of all deviations. Owners and operators must also 
record and report the date, duration, and cause of events where 
emissions bypassed the control device and any period when visible 
emissions exceeded 1 minute during a 15-minute period. For each visible 
emissions test following return to operation from a maintenance or 
repair activity, owners and operators must record and report the date 
of the visible emissions test, the length of the test in minutes, and 
the number of minutes for which visible emissions were present.
    If an owner or operator conducts a demonstration to prove that the 
NHV of the inlet gas to an enclosed combustion device or flare is 
consistently above the minimum required NHV, the owner or operator must 
record and report the results of the demonstration. Likewise, if an 
owner or operator conducts a demonstration that the maximum potential 
pressure of units manifolded to an enclosed combustion device or flare 
cannot cause the maximum inlet flow rate or the flare tip velocity 
limit to be exceeded, the owner or operator must record and report the 
results of the demonstration.
    In addition to the information that must be reported, owners and 
operators must keep records of continuous

[[Page 16895]]

compliance with the monitoring requirements, including indications that 
the pilot flame is lit, CPMS limits, CPMS hourly and average values, 
and results of visible emissions observations or surveillance camera 
feed. Owners and operators are also required to keep records of CPMS 
checks and audits, maintenance activities and repairs for each control 
device failing a visible emissions test, and the manufacturer's written 
operating instructions, procedures, and maintenance schedule to ensure 
good air pollution control practices for minimizing emissions. If an 
owner or operator uses a backpressure regulator valve to control the 
minimum flow rate to the combustion device, the owner or operator must 
keep records of the engineering evaluation and manufacturer 
specifications used to identify the set point and annual confirmation 
that the backpressure regulator valve set point is set correctly and 
that the valve fully closes when not in open position.
2. EG OOOOc
a. Compliance Assurance Requirements
    The compliance requirements for combustion control devices on 
designated facilities specified in EG OOOOc are almost identical to the 
requirements specified in the NSPS OOOOb final rule. The only 
difference between the requirements in NSPS OOOOb and EG OOOOc is that 
for enclosed combustion devices and flares that are air-assisted or 
steam-assisted, the owner and operator would be required to maintain 
the NHV of the gas sent to the device above a minimum amount instead of 
monitoring the combustion zone NHV and the NHV dilution parameter. See 
section XI.H.5 of this preamble for more information on monitoring 
steam-assisted and air-assisted enclosed combustion devices and flares.
b. Recordkeeping and Reporting Requirements
    The EG OOOOc recordkeeping and reporting requirements for 
combustion control devices on designated facilities specified in EG 
OOOOc are the same as those specified in the NSPS OOOOb final rule.

I. Reciprocating Compressors

1. NSPS OOOOb
a. Affected Facility
    The reciprocating compressor affected facility is each 
reciprocating compressor, which is a single reciprocating compressor. A 
reciprocating compressor located at a well site is not a reciprocating 
compressor affected facility under this subpart. A reciprocating 
compressor located at a centralized production facility is a 
reciprocating compressor affected facility under this subpart.
b. Final Standards
    The NSPS OOOOb standard of performance for reciprocating compressor 
affected facilities is a performance-based emissions standard of 2 scfm 
(in operating or standby pressurized mode) per cylinder. The volumetric 
flow rate of 2 scfm is an action level that, if exceeded, triggers the 
action of repairing or replacing the rod packing and is not a numeric 
limit. The volumetric flow rate measurement from each reciprocating rod 
packing must be maintained to be less than or equal to a flow rate of 2 
scfm (in operating or standby pressurized mode) per cylinder. An owner 
or operator is required to repair or replace the rod packing and to 
conduct other necessary repair and maintenance in order to ensure the 
emission rate is maintained at or below 2 scfm (in operating or standby 
pressurized mode) per cylinder. Owners and operators must conduct 
volumetric flow rate measurements from each reciprocating compressor 
rod packing using the screening and monitoring methods specified in 40 
CFR 60.5386b.
    The EPA is requiring that the first and subsequent volumetric flow 
rate measurements from a reciprocating compressor affected facility be 
conducted on or before 8,760 hours of operation after the effective 
date of the final rule, on or before 8,760 hours of operation after the 
previous flow rate measurement, or on or before 8,760 hours of 
operation after the date of the most recent compressor rod packing 
replacement, whichever is later. Preventative maintenance or other 
corrective actions (e.g., repair or replacement of rod packing) may be 
necessary in addition to monitoring every 8,760 hours of operation for 
owners or operators to ensure compliance (consistent with the general 
duty clause 40 CFR 60.5470b(b)) with the required flow rate of 2 scfm 
(in operating or standby pressurized mode) or less per cylinder). As an 
alternative to conducting required volumetric flow rate measurements, 
the final rule also allows an owner or operator the option to comply by 
replacing the rod packing on or before 8,760 hours of operation after 
the effective date of the final rule, on or before 8,760 hours of 
operation after the previous flow rate measurement, or on or before 
8,760 hours of operation after the date of the most recent compressor 
rod packing replacement, whichever is later.
    In the final rule, repair or replacement of the rod packing is 
required when the volumetric emission measurement of the reciprocating 
compressor rod packing has a flow rate greater than 2 scfm (in 
operating or standby pressurized mode) per cylinder or a combined rod 
packing flow rate greater than the number of compressor cylinders 
multiplied by 2 scfm. An owner or operator must repair or replace the 
reciprocating compressor rod packing within 90 calendar days from the 
date of the volumetric emissions measurement.
    The final rule allows for a delay of repair if the repair or 
replacement would require a vent blowdown, or it would otherwise be 
infeasible or unsafe, until the next process unit shutdown. 
Specifically, if the repair or replacement is technically infeasible, 
would require a vent blowdown, a process unit or facility requires 
shutdown, parts or materials are unavailable, or it would be unsafe to 
repair during operation of the unit, the repair can be delayed but must 
be completed during the next scheduled process unit or facility 
shutdown for maintenance, after a scheduled vent blowdown, or within 2 
years, whichever is earliest. In addition, if the repair requires 
replacement of the compressor rod packing or a part, but the necessary 
replacement rod packing or part cannot be acquired and installed within 
the repair timelines specified due to supplies being unavailable (where 
previously sufficiently-stocked), a delay of repair is allowed. 
However, in order to qualify for a delay of repair, the required rod 
packing or part replacement must be ordered no later than 10 calendar 
days after the reciprocating compressor is added to the delay-of-repair 
list due to parts unavailability.
    Owner or operators must conduct volumetric flow rate measurements 
from each reciprocating compressor vent within 15 days after the repair 
to document that the rate has been reduced to less than the applicable 
flow rate per cylinder. If the individual cylinders are manifolded to a 
single open-ended vent line, the volumetric flow rate must be reduced 
to less than the sum of the individual cylinders multiplied by the 
applicable required flow rate per cylinder.
    For the EPA's rationale for prescribing a work practice standard 
over a numeric standard, see section XI.I.1 of this preamble.

[[Page 16896]]

c. Routing Emissions From the Rod Packing to a Process or to a Control 
Device That Reduces Emissions by 95 Percent
    Alternatively, an owner or operator may choose to comply with NSPS 
OOOOb by routing emissions from the rod packing via a CVS to a process 
or to a control device achieving 95 percent control. These options 
achieve emissions reductions greater than or equal to the 2 scfm 
performance-based emissions standard per cylinder. An owner or operator 
must ensure that the CVS is designed to capture and route all gases, 
vapors, and fumes to a process (40 CFR 60.5411b(a) and (c)).
    An owner or operator complying with the alternative option to route 
to a process is required to design and operate the CVS with no 
identifiable emissions and would be subject to bypass requirements (as 
applicable). Initial, monthly, and annual inspections (using OGI, EPA 
Method 21, or AVO (for monthly inspections only)) are required to check 
for defects and identifiable emissions.
    An owner or operator complying with the alternative option to route 
to a control device is required to design and operate the CVS with no 
identifiable emissions and would be subject to bypass requirements (as 
applicable). Initial, monthly, and annual inspections (using OGI, EPA 
Method 21, or AVO (for monthly inspections only)) of the CVS are 
required to check for defects and identifiable emissions. Control 
devices are required to meet the conditions specified in 40 CFR 
60.5412b of the final rule.
d. Recordkeeping and Reporting Requirements
    Owners or operators complying with the performance-based emissions 
standard must track and report in their annual report the cumulative 
number of hours of operation of each reciprocating compressor since 
startup, since the previous screening/volumetric flow rate emissions 
measurement, or since the previous reciprocating compressor repair/
replacement of rod packing, as applicable. Their annual report must 
also include a description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable. 
Lastly, owners or operators must maintain records and report each 
measurement that exceeds the 2 scfm performance-based emissions 
standard per cylinder standard during the reporting period, and the 
date and time the reciprocating compressor was repaired or packing 
replaced to meet the 2 scfm performance-based emissions standard. In 
the case of delay of repair due to parts unavailability, operators must 
document the date the reciprocating compressor was added to the delay-
of-repair list, the date the required rod packing or part was ordered, 
the anticipated delivery date, and the actual delivery date; and the 
annual report needs to provide the reason for the needed delay and the 
date of anticipated repair or replacement.
    For a reciprocating compressor affected facility complying by 
routing emissions from the rod packing to a process through a CVS, an 
owner or operator is required to maintain records and report each 
reciprocating compressor that was constructed, modified, or 
reconstructed during the reporting period that is complying by using 
this option. Owners or operators must maintain records and report each 
deviation from the performance-based emissions standard that occurred 
during the reporting period, the date and time the deviation began, 
duration of the deviation and a description of the deviation. 
Additionally, they would be required to report (in the annual report) 
the dates of each cover and CVS inspection, whether emissions are 
identified, and the date of repair or the date of anticipated repair if 
repair is delayed. Where bypass requirements apply, the date and time 
of each bypass alarm or each instance the key is checked out would also 
be included in the annual report.
    For a reciprocating compressor affected facility complying by 
routing emissions from the rod packing to a control device through a 
CVS, an owner or operator is required to maintain records and report 
each reciprocating compressor that was constructed, modified, or 
reconstructed during the reporting period that is complying by using 
this option. In instances where a deviation from the standard has 
occurred during the reporting period, an owner or operator would be 
required to provide information on the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation. Additionally, they would be required to report (in the 
annual report) the dates of each cover and CVS inspection, whether 
emissions are identified, and the date of repair or the date of 
anticipated repair if repair is delayed. Where bypass requirements 
apply, the date and time of each bypass alarm or each instance the key 
is checked out would also be included in the annual report. For the 
reports and records that demonstrate proper design and operation of the 
control device that must be maintained, see sections X.H.1 and X.H.2 of 
this preamble.
2. EG OOOOc
a. Designated Facility
    The reciprocating compressor designated facility is each 
reciprocating compressor, which is a single reciprocating compressor. A 
reciprocating compressor located at a well site is not a reciprocating 
compressor designated facility under this subpart. A reciprocating 
compressor located at a centralized production facility is a 
reciprocating compressor designated facility under this subpart.
b. Final Presumptive Standards
    The presumptive standards for reciprocating compressor designated 
facilities are the same performance-based emissions work practice 
standard, or alternative routing emissions from the rod packing to a 
process or control device options as required in the NSPS OOOOb final 
rule. The final designated facility recordkeeping and reporting 
requirements specified in the final EG OOOOc rule are also the same as 
specified in the NSPS OOOOb final rule.

J. Storage Vessels

1. NSPS OOOOb
a. Affected Facility
    A storage vessel affected facility subject to the final standards 
is defined as a tank battery that has the potential for VOC emissions 
equal to or greater than 6 tpy or methane emissions equal to or greater 
than 20 tpy is. A storage vessel is a tank or other vessel that 
contains an accumulation of crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water, and that is constructed 
primarily of nonearthen materials. A tank battery is a group of all 
storage vessels that are manifolded together for liquid transfer. For 
purposes of this rule, a tank battery may consist of a single storage 
vessel if only one storage vessel is present.
b. Final Standards
    Storage vessel affected facilities must reduce emissions of VOC and 
methane by 95 percent. The standard reflects the degree of emission 
limitation achievable through application of a combustion control 
device or VRU, which we have identified as the BSER for storage vessel 
affected facilities. See rationale for the BSER at section XII.B.1.e of 
the November 2021 Proposal and Chapter 6 of the of the November 2021 
TSD \194\ which is unchanged in this final rule. For storage vessel 
affected facilities not at a well site or centralized production

[[Page 16897]]

site and without potential for flashing emissions, owners and operators 
may choose to comply by using an internal or external floating roof to 
reduce emissions in accordance with 40 CFR part 60, subpart Kb (NSPS 
for Volatile Organic Liquid Storage Vessels). The rule allows removal 
of a control device from a storage vessel affected facility if the 
owner or operator maintains the uncontrolled actual VOC emissions at 
less than 4 tpy and the actual methane emissions at less than 14 tpy as 
determined monthly for 12 consecutive months.
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    \194\ See Document ID No. EPA-HQ-OAR-2021-0317-0166.
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c. Cover and Closed Vent System Requirements--Control Device 
Requirements
    Storage vessel affected facilities which use a control device to 
reduce emissions must equip each storage vessel in the tank battery 
with a cover and must equip the tank battery with one or more closed 
vent systems which route all emissions to a process or one or more 
control devices. Flares and other control devices must conduct 
monitoring, recordkeeping, and reporting to ensure that the control 
device is continuously achieving the required 95 percent reduction. 
More information on the flare and other control device monitoring and 
compliance provisions is provided in section X.H of this preamble and 
information regarding covers and closed vent systems may be found in 
section X.K of this preamble.
d. Modification and Reconstruction
    The EPA finalizes as proposed the definition of modification to 
include specific physical changes that will trigger the modification 
requirements (i.e., adding an additional storage vessel, replacing 
existing storage vessel(s) that result in an increased capacity of the 
tank battery, receiving additional throughput from production well(s)) 
at tank batteries at well sites or centralized production facilities, 
or receiving additional fluids which cumulatively exceed the throughput 
used in the most recent determination of the potential for VOC or 
methane emissions not located at a well site or centralized production 
facility, including each tank battery at compressors stations or 
onshore natural gas processing plants that also result in exceeding the 
applicability threshold for either VOC or methane). The EPA defines 
reconstruction to mean at least half of the storage vessels are 
replaced in the existing tank battery that consists of more than one 
storage vessel, or the provisions of 40 CFR 60.15 are met for the 
existing tank battery and the resulting emissions exceed the 
applicability threshold for either VOC or methane.
e. Legally and Practicably Enforceable (LPE) Limitations
    In this action, the EPA is finalizing the proposed criteria that 
must be met for a permit limit or other requirement to qualify as a 
legally and practicably enforceable limit for purposes of determining 
whether a tank battery is an affected facility or designated facility 
under NSPS OOOOb. A legally and practicably enforceable limit must 
include a quantitative production limit and quantitative operational 
limit(s) for the equipment, or quantitative operational limits for the 
equipment; an averaging time period for the production limit, if a 
production-based limit is used, that is equal to or less than 30 days; 
established parametric limits for the production and/or operational 
limit(s), and where a control device is used to achieve an operational 
limit, an initial compliance demonstration (i.e., performance test) for 
the control device that establishes the parametric limits; ongoing 
monitoring of the parametric limits that demonstrates continuous 
compliance with the production and/or operational limit(s); 
recordkeeping by the owner or operator that demonstrates continuous 
compliance with the limit(s) in; and periodic reporting that 
demonstrates continuous compliance.
f. Recordkeeping and Reporting Requirements
    In each annual report, owners and operators are required to 
identify each storage vessel affected facility that was constructed, 
modified, or reconstructed during the reporting period and must 
document the emission rates of both VOC and methane individually. The 
annual report must include deviations that occurred during the 
reporting period and information for control devices tested by the 
manufacturer or the date and results of the control device performance 
test for control devices not tested by the manufacturer. The report 
also must include the results of inspections of covers and CVS and the 
identification of storage vessel affected facilities (or portion of 
storage vessel affected facility) removed from service or returned to 
service. For storage vessel affected facilities which comply with the 
uncontrolled 4 tpy VOC limit or 14 tpy methane limit, the report must 
include changes which resulted in the source no longer complying with 
those limits and the dates that the source began to comply with the 95 
percent reduction standard. The annual report must also include 
information on control devices used to achieve the 95 percent reduction 
standard. See section X.H of this preamble for more information related 
to reporting and recordkeeping for control devices.
    Required records include documentation of the methane and VOC 
emissions determination and methodology, records of deviations and 
duration, records for the number of consecutive days a skid-mounted or 
permanently mobile-mounted storage vessel is on the site, the latitude 
and longitude coordinates of each storage vessel affected facility, 
dates that each storage vessel affected facility (or portion of storage 
vessel affected facility) is removed from service or returned to 
service, and records associated with control devices. For storage 
vessel affected facilities which comply with the uncontrolled 4 tpy VOC 
or 14 tpy methane limit, owners and operators must keep records of the 
monthly methane and VOC determination and methodology, records of 
changes which resulted in the source no longer complying with those 
limits, and the dates that the source began to comply with the 95 
percent reduction standard. All associated records that demonstrate 
proper design and operation of the CVS, cover and control device also 
must be maintained (see section X.K and X.H of this preamble).
2. EG OOOOc
a. Designated Facility
    A storage vessel is a tank or other vessel that contains an 
accumulation of crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water, and that is constructed primarily of 
nonearthen materials. A tank battery is a group of all storage vessels 
that are manifolded together for liquid transfer. For purposes of EG 
OOOOc, a tank battery may consist of a single storage vessel if only 
one storage vessel is present. Each tank battery that has the potential 
for methane emissions greater than or equal to 20 tpy is a storage 
vessel designated facility.
b. Final Presumptive Standards
    The presumptive methane standards in EG OOOOc for storage vessel 
designated facilities are the same emissions standards as those 
specified for methane for storage vessel affected facilities in the 
NSPS OOOOb final rule. Specifically, the presumptive standard is to 
reduce methane emissions by 95 percent. It reflects the degree of 
emission reduction through application of a combustion control device 
or VRU, which we have identified as the BSER

[[Page 16898]]

for storage vessel designated facilities. See rationale for the BSER at 
section XII.B.2. of the November 2021 Proposal and Chapter 6 of the of 
the November 2021 TSD \195\ which is unchanged in this final rule. For 
storage vessel designated facilities not at a well site or centralized 
production site and without potential for flashing emissions, owners 
and operators could choose to comply by using an internal or external 
floating roof to reduce emissions in accordance with 40 CFR part 60, 
subpart Kb (NSPS for Volatile Organic Liquid Storage Vessels). In 
addition, the presumptive standards would allow removal of a control 
device from a storage vessel affected facility if the owner or operator 
maintains the uncontrolled actual VOC emissions at less than 4 tpy and 
the actual methane emissions at less than 14 tpy as determined monthly 
for 12 consecutive months. The designated facility presumptive 
recordkeeping and reporting requirements in the final EG OOOOc rule are 
also the same as those specified in the NSPS OOOOb final rule. Please 
see a summary of these requirements above in section X.J.1.f.
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    \195\ See Document ID No. EPA-HQ-OAR-2021-0317-0166.
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c. LPE Limitations
    The EPA is finalizing the proposed criteria that must be met a 
permit limit or other requirement to qualify as a legally and 
practicably enforceable limits for purposes of determining whether a 
tank battery is designated facility under EG OOOOc. A legally and 
practicably enforceable limit must include a quantitative production 
limit and quantitative operational limit(s) for the equipment, or 
quantitative operational limits for the equipment; an averaging time 
period for the production limit, if a production-based limit is used, 
that is equal to or less than 30 days; established parametric limits 
for the production and/or operational limit(s), and where a control 
device is used to achieve an operational limit, an initial compliance 
demonstration (i.e., performance test) for the control device that 
establishes the parametric limits; ongoing monitoring of the parametric 
limits that demonstrates continuous compliance with the production and/
or operational limit(s); recordkeeping by the owner or operator that 
demonstrates continuous compliance with the limit(s) in; and periodic 
reporting that demonstrates continuous compliance. These criteria are 
the same as the LPE criteria for purposes of determining tank battery 
affected facility status finalized in NSPS OOOOb as outlined in 
X.J.1.e.

K. Covers and Closed Vent Systems

1. NSPS OOOOb
a. Compliance Assurance Requirements
    This section of the preamble presents a summary of the final 
compliance assurance requirements for CVS and covers. As noted in 
section IV.K of the December 2022 Supplemental Proposal, the EPA 
proposed several changes to the compliance assurance requirements for 
CVS and covers between the November 2021 Proposal and the December 2022 
Supplemental Proposal. First, the EPA proposed to align the design and 
operational requirements for CVS, regardless of which affected or 
designated facility is connected to the CVS and regardless of whether 
the emissions are being routed to a process or a control device. 
Second, the EPA proposed to allow the use of advanced methane detection 
technologies to demonstrate continuous compliance for CVS and covers. 
The use of advanced methane detection technologies to demonstrate 
continuous compliance for CVS and covers is discussed in section X.B of 
this preamble. Lastly the EPA proposed to change the emissions limit 
for covers and CVS from no detectable emissions (NDE) to no 
identifiable emissions (NIE). The EPA clarified that the proposed 
change was not intended to change the stringency of the standard, but 
to reflect the change in monitoring methods used for demonstrating 
compliance with the standard. NDE is a term closely linked with EPA 
Method 21; because the EPA proposed to allow owners and operators to 
demonstrate compliance with the emissions limit for covers and CVS 
using OGI and AVO in addition to EPA Method 21, the EPA proposed to 
change the terminology used in the standard from NDE to NIE. Further 
discussion on the NIE standard is provided below and in section XI.K.1 
of this preamble. The final requirements for covers and CVS summarized 
below reflect the requirements that were proposed in the December 2022 
Supplemental Proposal.\196\
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    \196\ See section IV.K, 87 FR 74804 (December 6, 2022).
---------------------------------------------------------------------------

    As in NSPS OOOO and OOOOa, NSPS OOOOb contains requirements for CVS 
and covers to ensure compliance with the standards for centrifugal 
compressor, reciprocating compressor, and storage vessel affected 
facilities.\197\ CVS route emissions from well (i.e., oil wells when 
routing associated gas to a control device), centrifugal compressor, 
reciprocating compressor, process controllers, pumps, storage vessels 
and process unit affected facilities to a control device or to a 
process. Each CVS must be designed and operated to capture and route 
all gases, vapors, and fumes to a process or to a control device and 
comply with an emissions limit of NIE. Covers must form a continuous 
impermeable barrier over the entire surface area of the liquid in the 
storage vessel, over the centrifugal compressor wet seal fluid 
degassing system, or over the reciprocating compressor rod packing 
emissions collection system. Each cover opening shall be secured in a 
closed, sealed position (e.g., covered by a gasketed lid or cap) 
whenever material is in the unit on which the cover is installed, 
except during those times when it is necessary to use an opening, such 
as to inspect equipment or to remove material from the equipment.
---------------------------------------------------------------------------

    \197\ Also, as in NSPS OOOOa, CVS and covers not are not 
associated with an affected facility are fugitive emissions 
components.
---------------------------------------------------------------------------

    Initial and continuous compliance of the NIE standard would be 
demonstrated through OGI or EPA Method 21 monitoring and AVO 
inspections conducted at the same frequency as the fugitive emissions 
monitoring for the type of site where the cover and CVS are located. 
Alternatively, an owner or operator could demonstrate ongoing 
compliance with the NIE standard for covers and CVS using the periodic 
screening or continuous monitoring requirements for advanced methane 
detection technologies in 40 CFR 60.5398b, as described in section X.B 
of this preamble. Where AVO inspections are required, the CVS and cover 
is determined to operate with NIE if no emissions are detected by AVO 
means. Where OGI monitoring is conducted, the CVS and cover is 
determined to operate with NIE if no emissions are imaged by the OGI 
camera. Where EPA Method 21 monitoring is conducted, the CVS and cover 
is determined to operate with NIE if the readings obtained using EPA 
Method 21 are less than 500 parts per million by volume (ppmv) above 
background. Emissions detected by AVO, OGI, or EPA Method 21 constitute 
a deviation of the NIE standard until a subsequent inspection 
determines that the CVS and cover operates with NIE. Where monitoring 
is conducted using advanced methane detection technologies, covers and 
CVS are determined to operate with NIE if no emissions are detected by 
the periodic screening survey or, where continuous monitoring is 
conducted, the site remains under the action levels. If emissions are 
detected from the site during a periodic screening survey or the site 
exceeds an action level, the

[[Page 16899]]

cover and CVS are still determined to operate with NIE unless a follow-
up inspection with EPA Method 21, OGI, or AVO indicates that the cover 
and CVS do not operate with NIE.
    Each CVS must be inspected to ensure that the CVS operates with NIE 
initially within 30 calendar days after startup of the affected 
facility routing emissions through the CVS and periodically. 
Specifically, for the well sites and centralized production facilities 
where a CVS is present, quarterly OGI or EPA Method 21 and bimonthly 
AVO would be required; for compressor stations, quarterly OGI or EPA 
Method 21 and monthly AVO would be required. For CVS and covers located 
at onshore natural gas processing plants, AVO inspections are required 
annually and instrument monitoring for NIE must be conducted either 
bimonthly with OGI following the procedures in appendix K or quarterly 
in accordance with EPA Method 21. For CVS joints, seams, and 
connections that are permanently or semi-permanently sealed, owners and 
operators are not required to conduct periodic instrument monitoring 
with OGI or EPA Method 21, but the owner or operator must still conduct 
initial instrument monitoring and periodic AVO monitoring. 
Additionally, annual visual inspections must be conducted for all CVS 
to check for defects, such as cracks, holes, or gaps.
    If the CVS is equipped with a bypass, the bypass must include a 
flow monitor and sound an alarm to alert personnel or send a 
notification via remote alarm to the nearest field office that a bypass 
is being diverted to the atmosphere, or it must be equipped with a car-
seal or lock-and-key configuration to ensure the valve remains in a 
non-diverting position. To ensure proper design, an assessment of the 
closed vent system must be conducted and certified by a qualified 
professional engineer or in-house engineer.
    Any emissions or defects detected during an inspection of a cover 
or CVS is subject to repair, with a first attempt at repair within 5 
days after detecting the emissions or defect and final repair within 30 
days after detecting the emissions or defect. While awaiting final 
repair, covers must have a gasket-compatible grease applied to improve 
the seal. Delay of repair is allowed where the repair is infeasible 
without a shutdown, or it is determined that immediate repair would 
result in emissions greater than delaying repair. In all instances, 
repairs must be completed by the end of the next shutdown. Owner and 
operators may designate parts of the CVS as unsafe to inspect and 
difficult to inspect but must have a written plan of the inspection of 
this equipment. Equipment that is unsafe to inspect would expose 
inspecting personnel to an imminent potential danger; this equipment 
must be inspected as frequently as practicable, during safe to inspect 
times. Equipment that is difficult to inspect would require elevating 
inspecting personnel more than 2 meters above a support surface; this 
equipment must be inspected at least once every 5 years.
b. Recordkeeping and Reporting Requirements
    The CVS certification must be submitted in the annual report in the 
reporting year in which the certification is signed. In each annual 
report, the owner or operator must report the date of each cover and 
CVS inspection, all defects or emissions identified during the 
inspections, and the date of repair or anticipated repair if the repair 
is delayed for each defect or emission. Owners and operators must also 
report the date and time of each bypass or alarm or each instance where 
the key is checked out. Records of CVS and cover inspections, CVS 
bypass monitoring, and CVS design and certifications must be 
maintained. The CVS certification must be submitted in the initial 
annual report.
    Records for CVS and covers include records of inspections, CVS 
bypass monitoring, and CVS design and certifications. For each CVS or 
cover inspection, owners and operators must keep records of the date of 
the inspection, the method of inspection (i.e., visual, AVO, OGI, or 
EPA Method 21), and all defects and emissions found. For each defect or 
emission found, the owner or operator must record the location, a 
description of the defect, the maximum concentration reading if EPA 
Method 21 is used, the date of detection, the date of each attempt to 
repair the defect or emission, the corrective action taken to repair 
the defect or emission, and the date of final repair of the defect or 
emission. If a repair is delayed, the owner or operator must record the 
reason for delay and the anticipated date of repair. Owners and 
operators must also keep records of unsafe and difficult to inspect 
portions of the CVS, including the written inspection plan. For each 
CVS bypass, owners and operators must keep records of readings from the 
flow indicator and the date and time of each instance the alarm is 
sounded, inspections of the seal or closure mechanism, and dates and 
times of each instance the key is checked out.
2. EG OOOOc
a. Compliance Assurance Requirements
    The model rule in EG OOOOc includes the same covers and CVS 
requirements as those in NSPS OOOOb to assure that emissions from 
designated facilities, such as wells (i.e., oil wells when routing 
associated gas to a control device), centrifugal compressors, 
reciprocating compressors, process controllers, pumps, and process 
unit, are captured and routed to a control device or process when such 
control device or process are being used to meet the presumptive 
standards for the designated facilities.
b. Recordkeeping and Reporting Requirements
    The recordkeeping and reporting requirements for EG OOOOc are the 
same as those for NSPS OOOOb.

L. Equipment Leaks at Natural Gas Processing Plants

1. NSPS OOOOb
a. Affected Facility
    Each process unit equipment affected facility, which is the group 
of all equipment within a process unit at an onshore natural gas 
processing plant, is an affected facility. Equipment, as used in the 
standards and requirements of this subpart relative to the process unit 
equipment affected facility at onshore natural gas processing plants, 
means each pump, pressure relief device, open-ended valve or line, 
valve, and flange or other connector that has the potential to emit 
methane or VOC and any device or system required by those same 
standards and requirements of this subpart. Process unit means 
components assembled for the extraction of natural gas liquids from 
field gas, the fractionation of the liquids into natural gas products, 
or other operations associated with the processing of natural gas 
products. A process unit can operate independently if supplied with 
sufficient feed or raw materials and sufficient storage facilities for 
the products.
b. Final Standards
    The NSPS OOOOb final standards apply to the ``process unit 
equipment'' affected facility and require that, for each piece of 
equipment that has the PTE methane or VOC, owners and operators conduct 
bimonthly (i.e., once every other month) OGI monitoring in accordance 
with 40 CFR part 60, appendix K \198\ to detect equipment

[[Page 16900]]

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

    \198\ See section XIV of this preamble for information related 
to appendix K.
---------------------------------------------------------------------------

    In addition to the monitoring and repair requirements summarized 
previously, the final rule includes requirements for specific types of 
equipment. Each open-ended valve or line must be equipped with a 
closure device (i.e., cap, blind flange, plug, or a second valve) that 
seals the open end at all times except during operations which require 
process fluid flow through the open-ended valve or line. CVS used to 
comply with the standards for process unit equipment must be monitored 
bimonthly using OGI (or quarterly using EPA Method 21 if this 
alternative is used). Control devices used to comply with the equipment 
leak provisions must comply with the requirements described in section 
X.H of this preamble. Pressure relief devices must be monitored within 
5 days after a pressure release to ensure the device has reseated after 
a pressure release. The final rule allows exceptions to the 5-day post-
pressure release monitoring requirement for pressure relief devices 
that are located in a non-fractionating plant where the non-
fractionating plant is monitored only by non-plant personnel that are 
not onsite.\199\ The exception allows the pressure relief device to be 
monitored after a pressure release the next time non-plant monitoring 
personnel are onsite, but in no event can the monitoring be delayed 
beyond 30 calendar days after a pressure release. Pressure relief 
devices that are routed to a process, fuel gas system, or control 
device are not required to be monitored following a release because the 
emissions from the release are controlled. The rule also provides 
exceptions to the GHG and VOC standards for process unit equipment 
affected facilities for certain types of equipment at a non-
fractionating plant that does not have the design capacity to process 
283,200 standard cubic meters per day (scmd) (10 million scf per day) 
\200\ or more of field gas and for equipment within a process unit at 
the Alaskan North Slope.
---------------------------------------------------------------------------

    \199\ A nonfractionating plant refers to any gas plant that does 
not fractionate mixed natural gas liquids into natural gas products. 
See 40 CFR 60.5430b and 60.5430c.
    \200\ For example, for pumps in light liquid service, pressure 
relief devices in gas/vapor service, valves in gas/vapor and light 
liquid service, and connectors in gas/vapor service and in light 
liquid service that are located at a non-fractionating plant that do 
not have the design capacity to process 283,200 standard cubic 
meters per day (scmd) (10 million scf per day) or more of field gas, 
owners or operators may comply with the following exceptions: (1) 
They may conduct quarterly monitoring instead of bimonthly 
monitoring as required under Sec.  60.5400b(b), and (2) they are 
exempt from the routine monitoring requirements if complying with 
the alternative standards of Sec.  60.5401b.
---------------------------------------------------------------------------

    NSPS OOOOb reporting is required semiannually for process unit 
equipment affected facilities, which differs from the annual reporting 
for other affected facilities in NSPS OOOOb. In the initial semiannual 
report, the owner or operator must identify: each process unit 
associated with the process unit equipment affected facility; the 
number of each type of equipment subject to the monitoring 
requirements; for each month of the reporting period, the number of 
leaking equipment for which leaks were identified, the number of 
leaking equipment for which leaks were not repaired, and the facts that 
explain each delay of repair; and dates of process unit shutdowns. In 
subsequent semiannual reports, owners and operators must report the 
name of each process unit associated with the process unit equipment 
affected facility; any changes to the process unit identification or 
the number or type of equipment subject to the monitoring requirements; 
for each month of the reporting period, the number of leaking equipment 
for which leaks were identified, the number of leaking equipment for 
which leaks were not repaired, and the facts that explain each delay of 
repair; and dates of process unit shutdowns.
    Required records in the final rule include inspection records 
consisting of equipment identification, date and start and end times of 
the monitoring inspection, inspector name, leak determination method, 
monitoring instrument identification, type of equipment monitored, 
process unit identification, appendix K records (where applicable), EPA 
Method 21 instrument readings and calibration results (where 
applicable) and, for visual inspections, the date, name of inspector 
and result of inspection. For each leak detected, the final rule 
requires recording of the instrument and operator identification (or 
record of AVO method, where applicable), the date the leak was 
detected, the date and repair method applied for first attempts at 
repair, indication of whether the leak is still detected, and the date 
of successful repair, which includes results of a resurvey to verify 
repair. For each delay of repair, the final rule requires that the 
equipment is identified as ``repair delayed'' along with the reason for 
the delay, the signature of the certifying official, and the dates of 
process unit shutdowns which occurred while the equipment is 
unrepaired. Additionally, the final rule requires records of equipment 
designated for NDE; the identification of valves, pumps, and connectors 
that are designated as unsafe-to-monitor, an explanation stating why it 
is unsafe-to-monitor, and the plan for monitoring that equipment; a 
list of identification numbers for valves that are designated as 
difficult-to-monitor, an explanation stating why it is difficult-to-
monitor, and the schedule for monitoring each valve; a list of 
identification numbers for equipment that is in vacuum service and a 
list of identification numbers for equipment designated as having the 
PTE methane or VOC less than 300 hr/yr.\201\
---------------------------------------------------------------------------

    \201\ This exemption is similar to that in NSPS OOOOa, which 
exempts owners/operators from monitoring leaks from equipment in VOC 
service less than 300 hr/yr. As in NSPS OOOOa, this exemption 
applies to equipment at onshore natural gas processing plants that 
is used only during emergencies, used as a backup, or that is in 
service only during startup and shutdown. See 85 FR 57408.
---------------------------------------------------------------------------

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

[[Page 16901]]

    With the exception of the requirements for low-E valves, where 
technically feasible, these standards are unchanged from section IV.L.1 
of the December 2022 Supplemental Proposal. For each valve where a leak 
is detected, you must comply by repacking the existing valve with a 
low-E packing, replacing the existing valve with a low-E valve; or 
performing a drill and tap repair with a low-E injectable packing. An 
owner or operator is not required to utilize a low-E valve or low-E 
packing to replace or repack a valve if the owner or operator 
demonstrates that a low-E valve or low-E packing is not technically 
feasible. Low-E valve or low-E packing that is not suitable for its 
intended use is considered to be technically infeasible. Factors that 
may be considered in determining technical infeasibility include: 
retrofit requirements for installation (e.g., re-piping or space 
limitation), commercial unavailability for valve type, or certain 
instrumentation assemblies.
2. EG OOOOc
a. Designated Facility
    Each process unit equipment designated facility, which is the group 
of all equipment within a process unit at an onshore natural gas 
processing plant, is a designated facility. Equipment, as used in the 
standards and requirements of this subpart relative to the process unit 
equipment designated facility at onshore natural gas processing plants, 
means each pump, pressure relief device, open-ended valve or line, 
valve, and flange or other connector that has the potential to emit 
methane and any device or system required by those same standards and 
requirements of this subpart. Process unit means components assembled 
for the extraction of natural gas liquids from field gas, the 
fractionation of the liquids into natural gas products, or other 
operations associated with the processing of natural gas products. A 
process unit can operate independently if supplied with sufficient feed 
or raw materials and sufficient storage facilities for the products.
b. Final Standards
    The EG OOOOc final methane presumptive standards for ``process unit 
equipment'' designated facilities are the same as finalized for NSPS 
OOOOb affected facilities. The Model Rule reporting and recordkeeping 
requirements are also the same as finalized for NSPS OOOOb affected 
facilities.
    With the exception of low-E valves, these presumptive standards are 
unchanged from section IV.L.2 of the December 2022 Supplemental 
Proposal. See rationale for the BSER at section XII.B.2 of the November 
2021 Proposal which is unchanged in this final rule.

M. Sweetening Units

1. Affected Facility
    A sweetening unit refers to a process device that removes 
H<INF>2</INF>S and/or CO<INF>2</INF> from the sour natural gas stream--
i.e., sweetening units convert H<INF>2</INF>S in acid gases (i.e., 
H<INF>2</INF>S and CO<INF>2</INF>) that are separated from natural gas 
by a sweetening process, like amine gas treatment, into elemental 
sulfur in the Claus process. Each sweetening unit that processes 
natural gas produced from either onshore or offshore wells is an 
affected facility as well as each sweetening unit that processes 
natural gas followed by a sulfur recovery unit.
2. Final Standards
    Affected facilities with a sulfur production rate of at least 5 
long tons per day (LT/D) must reduce SO<INF>2</INF> emissions by 99.9 
percent. Compliance with the standard is determined based on an initial 
performance test and daily reduction efficiency measurements. During 
the performance test, the minimum required reduction efficiency of 
SO<INF>2</INF> emissions is determined for the sweetening unit. For 
affected facilities that have a design capacity less than 2 LT/D of 
H<INF>2</INF>S in the acid gas (expressed as sulfur), recordkeeping and 
reporting requirements are required. However, emissions control 
requirements are not required. Facilities that produce acid gas that is 
entirely reinjected into oil/gas-bearing strata or that is otherwise 
not released to the atmosphere are also not subject to emissions 
control requirements.
    For affected facilities that use an oxidation control system, or a 
reduction control system followed by an incineration device, an owner 
or operator must (1) continually operate the oxidation/incineration 
device and (2) install, calibrate, maintain, and operate monitoring 
devices and continuous emission monitors. For affected facilities that 
use a reduction control system not followed by an incineration device, 
an owner or operator must install, calibrate, maintain, and operate a 
continuous monitoring system to measure the emission rate of reduced 
sulfur compounds.
    Owners and operators of a sweetening unit device affected facility 
are required to submit notifications required under the NSPS General 
Provisions, initial and annual reports, and excess emissions reports 
(as applicable). Affected facilities are also required to retain 
records of the following:
    (1) the applicable calculations and measurements,
    (2) an analysis demonstrating that the facility's design capacity 
is less than 2 LT/D of H<INF>2</INF>S expressed as sulfur to document 
exemption from the control requirements (when applicable), and
    (3) a record demonstrating that the facility's design capacity is 
less than 150 LT/D of H<INF>2</INF>S expressed as sulfur (if electing 
to comply with 40 CFR 60.5407b(e)).
    This is unchanged from section IV.M of the December 2022 
Supplemental Proposal.

N. Electronic Reporting

    To increase the ease and efficiency of data submittal and data 
accessibility, the EPA is finalizing, as proposed, a requirement that 
owners and operators submit electronic copies of performance test 
reports, natural gas processing plant semiannual reports, annual 
reports, and notifications of well closure activities through the EPA's 
Central Data Exchange (CDX) using the Compliance and Emissions Data 
Reporting Interface (CEDRI). A description of the electronic data 
submission process is provided in the memorandum, Electronic Reporting 
Requirements for New Source Performance Standards (NSPS) and National 
Emission Standards for Hazardous Air Pollutants (NESHAP) Rules, 
available in the docket for this action. The final rulemaking requires 
that performance test results be submitted in the format generated 
through the use of the ERT or an electronic file consistent with the 
xml schema on the ERT website. For natural gas processing plant 
semiannual reports and annual reports, the final rule requires that 
owners and operators use the appropriate spreadsheet template to submit 
information to CEDRI. The final version of the templates for these 
reports will be located on the CEDRI website.\202\ The final rulemaking 
requires that notifications of well closure activities be submitted as 
a portable document format (PDF) upload in CEDRI. The EPA is also 
finalizing, as proposed, these same requirements in EG OOOOc.
---------------------------------------------------------------------------

    \202\ https://www.epa.gov/electronic-reporting-air-emissions/cedri.
---------------------------------------------------------------------------

    Furthermore, the EPA is finalizing in NSPS OOOOb and EG OOOOc, as 
proposed, provisions that allow owners and operators the ability to 
seek extensions for submitting electronic reports for circumstances 
beyond the control of the facility, i.e., for a possible

[[Page 16902]]

outage in CDX or CEDRI or for a force majeure event, in the time just 
prior to a report's due date, as well as the process to assert such a 
claim.

O. Prevention of Significant Deterioration and Title V Permitting

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

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

    This section of the preamble presents in each subsection a summary 
of any changes since the December 2022 Supplemental Proposal for the 
topic being addressed in that subsection, as well as significant 
comments on that topic and the EPA's response thereto. For final NSPS 
standards and requirements and final EG presumptive standards and 
requirements that have not changed since the December 2022 Supplemental 
Proposal, the supporting rationales for the EPA's BSER determinations 
are not reiterated in this preamble. The rationale for these standards 
and requirements can be found in the preamble to the December 2022 
Supplemental Proposal and in the TSD for the December 2022 Supplemental 
Proposal. The EPA's full response to comments on the November 2021 
Proposal and December 2022 Supplemental Proposal, including any 
comments not discussed in this preamble, can be found in the EPA's RTC 
document for the final rule.\203\
---------------------------------------------------------------------------

    \203\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

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

1. Fugitive emissions at Well Sites and Centralized Production 
Facilities
    In section X.A.1 of this document, the final NSPS OOOOb and EG 
OOOOc requirements for fugitive emissions components at well sites and 
centralized production facilities are summarized. The BSER analysis for 
fugitive emissions components at well sites and centralized production 
facilities is unchanged from what was presented in the December 2022 
Supplemental Proposal (see 87 FR 74729-39, section IV.A.1: Fugitive 
Emissions at Well Sites and Centralized Production Facilities). 
Significant comments were received on the December 2022 Supplemental 
Proposal on the following topics: (1) the definition of fugitive 
emissions component, (2) the EPA's assumption regarding the 
effectiveness of OGI and AVO, (3) the order of evaluating AVO in the 
BSER analysis, (4) subcategorization of well sites, and (5) 
miscellaneous other changes. For each of these topics, a summary of the 
proposed rule (where relevant), the comments, the EPA responses, and 
changes made in the final rule (if applicable), are discussed here. 
These comments and the EPA's responses to these comments generally 
apply to the standards proposed in both the NSPS OOOOb and EG OOOOc. 
The instances where the comment and/or response only applies to the 
NSPS OOOOb or EG OOOOc are noted. The EPA's full response to comments 
on the November 2021 Proposal and December 2022 Supplemental Proposal, 
including any comments not discussed in this preamble, can be found in 
the EPA's RTC document for the final rule.\204\ This section of this 
document presents a summary of significant comments received on 
fugitive emissions components affected or designated facilities located 
at well sites and centralized production facilities and the EPA's 
response to those comments, as well as changes the EPA has made to the 
well site fugitive emissions requirements of NSPS OOOOb and EG OOOOc 
since the December 2022 Supplemental Proposal.
---------------------------------------------------------------------------

    \204\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

a. Fugitive emissions component definition
    Comment: Commenters suggested various revisions to the proposed 
definition of fugitive emissions components. A commenter \205\ asked 
that the EPA exclude yard piping from the definition because this 
inclusion would expand the definition in an unprecedented way. 
According to the commenter, cracks and holes in piping have never been 
considered fugitive components in any other rule for LDAR in any 
industry sector by the Agency. The commenter asserted that the EPA has 
not explained how leak detection should be conducted for yard piping, 
as compared to other fugitive emissions components where there are 
identifiable leak points (such as valve stems or flange interfaces) 
that are the target of monitoring. The commenter also noted that cracks 
and holes represent potential loss of containment and are already 
repaired and corrected per industry practice and code. Another 
commenter \206\ asked that the EPA exclude buried yard piping from the 
definition of fugitive emissions components because buried components 
are difficult or impossible to monitor.
---------------------------------------------------------------------------

    \205\ EPA-HQ-OAR-2021-0317-2428.
    \206\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    Another commenter \207\ supported the EPA's inclusion of yard 
piping in the definition. This same commenter asked that the EPA also 
include certain equipment types like separators in the definition so 
monitoring of separator dump valves and components on all other 
equipment would clearly be required. The commenter noted that separator 
dump valves are a known source of large fugitive emissions events. In 
response to the November 2021 Proposal, the commenter \208\ had made a 
similar case for inclusion of separator dump valves in the definition 
in order to ensure that these components are monitored.
---------------------------------------------------------------------------

    \207\ EPA-HQ-OAR-2021-0317-2433.
    \208\ EPA-HQ-OAR-2021-0317-0844.
---------------------------------------------------------------------------

    Response: In the final NSPS OOOOb and EG OOOOc rules, the EPA has 
retained yard piping \209\ in the definition of fugitive emissions 
components. A definition of yard piping was added for clarity. As 
discussed in the December 2022 Supplemental Proposal, pipes can 
experience cracks or holes, which can lead to fugitive emissions. The 
inclusion of yard piping in the definition of fugitive emissions 
components will help ensure that fugitive emissions from

[[Page 16903]]

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

    \209\ The EPA recognizes that the terms ``yard piping'' and ``in 
yard piping'' were used interchangeably in the December 2022 
Supplemental Proposal. The final rule uses the term ``yard piping'' 
consistently.
---------------------------------------------------------------------------

    Regarding a commenter's request that the definition of fugitive 
emissions components explicitly include separators, the EPA agrees 
that, although the list of components in the definition is not 
exhaustive, it is worthwhile to eliminate any ambiguity as to whether 
separator dump valves are fugitive emissions components. The EPA is 
finalizing a definition of fugitive emissions components in NSPS OOOOb 
and EG OOOOc that specifically includes separator dump valves, thus 
clarifying that the separator dump valve is subject to monitoring by 
OGI, AVO, or other detection methods. In addition, because 
malfunctioning separator dump valves are a known source of large 
emissions (as the commenter noted) and because sometimes there is 
visual evidence of the malfunction, the EPA is requiring in the final 
rule that, during the regular AVO monitoring surveys (either quarterly 
or bimonthly depending on the site), a visual inspection must be 
conducted of all separator dump valves to ensure that they are free of 
debris and not stuck in an open position, and any dump valve not 
operating as designed must be repaired.
b. OGI and AVO Effectiveness
    Comment: Some commenters claimed that the EPA's assumptions for OGI 
and AVO effectiveness in both NSPS OOOOb and EG OOOOc are overstated 
and need to be adjusted. Specifically, these commenters were concerned 
the upper bound assumption of the percentage of leaks that will be 
detected by either method should be adjusted to reflect that these 
methods will not find all leaks during a survey. These commenters 
suggested that not all leaks, even large ones, would be observed during 
the monitoring survey, so not all the leaks would be repaired.
    One commenter \210\ specifically objected to the EPA's reliance on 
emissions information from the 2021 Rutherford, et al., study \211\ 
because the commenter believes the study ``cherry-picks'' data. This 
same commenter believes that the EPA ignores relevant information from 
the U.S. DOE marginal well study \212\ and urged the use of DOE 
emissions data in FEAST modeling to evaluate programs for low 
production and existing sites.
---------------------------------------------------------------------------

    \210\ EPA-HQ-OAR-2021-0317-2446.
    \211\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P., et al. 
``Closing the methane gap in U.S. oil and natural gas production 
emissions inventories.'' Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
    \212\ Bowers, Richard L. ``Quantification of Methane Emissions 
from Marginal (Low Production Rate) Oil and Natural Gas Wells.'' 
https://doi.org/10.2172/1865859.
---------------------------------------------------------------------------

    Conversely, one commenter \213\ asserted that the EPA's assumptions 
about the effectiveness of OGI are supported by recent data and FEAST 
modeling. One commenter \214\ believes that all inputs used by the EPA 
are reasonable, are appropriate, and ensure that advanced technologies 
deliver emissions reductions commensurate with OGI across diverse 
basins.
---------------------------------------------------------------------------

    \213\ EPA-HQ-OAR-2021-0317-2433.
    \214\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Other commenters \215\ expressed overall support of the use of 
FEAST modeling and recommended some adjustments. One commenter \216\ 
noted that intermittency of emissions should be represented in 
modeling. As it specifically relates to AVO, one commenter \217\ 
indicated that there is limited availability of information and studies 
on the effectiveness of AVO inspections for emissions with variable 
rates, intermittent emissions, emissions elevated above ground level, 
[varying] emission point aperture sizes, and emissions occurring in 
varying ambient conditions (e.g., wind, rain, and other ambient 
equipment/process/compressor noise that may obstruct detection). The 
commenter recommended that the EPA perform or seek out studies of AVO 
effectiveness across this range of conditions before incorporating it 
into the FEAST model for calculation of emissions reductions for 
purposes of equivalency demonstration for alternative monitoring 
solutions. Another commenter \218\ noted that leak detection and repair 
data collected in Colorado show both different annual rates for leaks 
requiring repair as well as few leaks requiring repair as detected by 
AVO.\219\
---------------------------------------------------------------------------

    \215\ EPA-HQ-OAR-2021-0317-2286, -2433, -2446.
    \216\ EPA-HQ-OAR-2021-0317-2387.
    \217\ EPA-HQ-OAR-2021-0317-2333.
    \218\ EPA-HQ-OAR-2021-0317-2286.
    \219\ Commenter refers to Colorado's 2021 LDAR Annual Report; 
e.g., in 2021, only 1,546 leaks were detected during 564,427 AVO 
inspections (https://cdphe.colorado.gov/oiland-gas-and-your-health/oil-gas-compliance-and-recordkeeping).
---------------------------------------------------------------------------

    Response: As discussed in the December 2022 Supplemental Proposal 
preamble and noted by the commenters, the revised approach for 
estimating the fugitive emissions under different monitoring scenarios 
at well sites uses a FEAST modeling approach based on the presence of 
specific types of equipment at well sites. The modeling uses built-in 
emissions data from various emissions measurement campaigns which were 
supplemented with additional study data to provide an empirical 
emissions dataset for the model simulations. The EPA used the FEAST 
model to evaluate potential fugitive emissions monitoring and repair 
programs at well sites (87 FR 74725). The effectiveness of fugitive 
emissions monitoring and repair programs are simulated within the FEAST 
model based on the probability of detection (PoD) curves (or surfaces) 
for each monitoring method and frequency, which indicate the 
probability that a leak of a given size will be detected within a given 
survey. Survey times (frequencies) are accounted for as finite time 
periods. The model quantifies emissions occurring at a site over a 
period of time (e.g., we used a 5-year simulation and evaluated the 
emissions in the fifth year of the simulation), accounting for 
simulated leak generation, identification, and repair rates. Emissions 
reductions are calculated by comparing the simulated fugitive emissions 
program against a baseline scenario where no program is implemented.
    The emissions data used in the FEAST model included data from 
direct measurement campaigns. Despite some shortcomings of the data in 
studies analyzed in the Rutherford, et al., study, the study is useful 
because it analyzes and reconciles multiple sources of data and 
multiple methods of estimating emissions to arrive at a more robust and 
validated model of component-level emissions from well sites. The EPA 
chose to use the Rutherford, et al., study and the U.S. DOE marginal 
well study to help inform assumptions necessary to establish a baseline 
emissions scenario

[[Page 16904]]

in the FEAST model because they represent credible compilations of 
relevant emissions data at the well site level. The set-up of the FEAST 
model was further validated by finding that the results generated by 
FEAST regarding the effectiveness of different OGI monitoring 
frequencies align well with other values reported in literature. The 
EPA found that the FEAST results align with the EPA's historical 
assumptions of 40, 60, and 80 percent, for annual, semiannual, and 
quarterly OGI monitoring, respectively,\220\ and these percent 
efficiencies compare well to those discussed in the TSD for the 2020 
Technical Rule.\221\
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    \220\ Specifically, for large well sites at a 0.5 percent leak 
generation rate, FEAST estimates reductions of 47, 67, and 78 
percent, for annual, semiannual, and quarterly monitoring, 
respectively. For multi-wellhead only well sites at a 0.5 percent 
leak generation rate, FEAST estimates reductions of 44, 67, and 78 
percent, for annual, semiannual, and quarterly monitoring, 
respectively. For single wellhead only well sites, FEAST estimates 
reductions of 48, 68, and 77 percent, for annual, semiannual, and 
quarterly monitoring, respectively.
    \221\ See section 2.4.1 of ``Oil and Natural Gas Sector: 
Emission Standards for New, Reconstructed, and Modified Sources 
Background Technical Support Document for the Final Reconsideration 
of the New Source Performance Standards 40 CFR part 60, subpart 
OOOOa.'' August 2020. EPA-HQ-OAR-2017-0483-2290.
---------------------------------------------------------------------------

    For the December 2022 Supplemental Proposal, the FEAST modeling 
conducted generally assumed a 100 percent probability of OGI camera 
operators' seeing all leaks above a certain size threshold. Following 
the December 2022 Supplemental Proposal, the EPA investigated the 
effect of lowering the probability of detection, based on public 
comments received asserting that not all leaks would necessarily be 
detected (and subsequently lower emissions reductions would be 
achieved). The EPA modeled ground-based surveys with maximum 
probability of detection of 70, 90, and 100 percent detection limits. A 
complete discussion of the EPA's assessment of the maximum probability 
of detection is presented in a memorandum \222\ available in the 
rulemaking docket. The results of this additional modeling suggest that 
lowering the maximum probability of detection would not appreciably 
change either the control effectiveness of various fugitive emissions 
monitoring and repair programs or the conclusion regarding the cost-
effective monitoring programs.\223\ Therefore, the EPA maintains that 
the OGI percent reduction efficiencies obtained via the FEAST modeling 
that was conducted for the December 2022 Supplemental Proposal (see 
tables 11-13 of the December 2022 Supplemental Proposal (87 FR 74732-
34), which align with previous assumptions and existing literature, are 
representative.
---------------------------------------------------------------------------

    \222\ Memorandum from Jeff Coburn, RTI International. Summary of 
Additional FEAST Modeling Runs. September 25, 2023.
    \223\ As observed in this analysis, cost-effective monitoring 
frequencies when using a lower maximum probability of detection 
would be at least as frequent when assuming a 100 percent maximum 
probability of detection for large leaks. Id.
---------------------------------------------------------------------------

    With respect to AVO effectiveness, the EPA did use an upper level 
of detection of 90 percent for AVO monitoring. The EPA acknowledges 
that the level of detection for AVO will be more variable than for OGI 
because leaks detected by olfactory methods (smell) will largely rely 
on other constituents present in the natural gas. However, the modeling 
runs when using AVO alone provided reasonable agreement with the 
emissions from oil and gas production sites that rely primarily on AVO 
inspections as reported in the U.S. DOE marginal well study data.\224\ 
Therefore, the EPA concluded that the modeling assumptions regarding 
the effectiveness of AVO monitoring were reasonable.
---------------------------------------------------------------------------

    \224\ Memorandum from Jeff Coburn, RTI International. Summary of 
Additional FEAST Modeling Runs. September 25, 2023.
---------------------------------------------------------------------------

    With respect to the recommendation to include intermittent 
emissions events in the FEAST model, the EPA has not done so for the 
following reasons. First, in order to model intermittent emissions 
events, assumptions would have to be made regarding the fraction of 
fugitive emissions that exhibit intermittent behavior and the typical 
duration of active emissions and of periods of low or zero emissions. 
Because the EPA has limited data from which to make these necessary 
assumptions, to include intermittent emissions events in the model 
would introduce great uncertainty to the model. Second, the EPA notes 
that intermittent emissions events are largely reported with respect to 
``super-emitters,'' which the EPA is addressing through the Super 
Emitter Program established in this final rule.\225\ For the reasons 
stated, the EPA has not included intermittent emissions events in the 
model.
---------------------------------------------------------------------------

    \225\ See sections X.C and X.I for details on the Super Emitter 
Program.
---------------------------------------------------------------------------

c. Order of AVO evaluation in the BSER
    Comment: One commenter \226\ believes that the EPA should have 
developed its regulatory strategy by first evaluating AVO and 
determining its cost effectiveness; then, the EPA should have assessed 
the impact of adding OGI monitoring. The commenter believes that 
evaluating whether additional OGI monitoring is appropriate and at what 
frequency should have come after the evaluation of AVO inspection in 
the EPA's BSER analysis for NSPS OOOOb and EG OOOOc. According to the 
commenter, this is particularly relevant for multi-wellhead only well 
sites (where the proposed requirement was semiannual OGI and quarterly 
AVO) as the EPA acknowledged that large leaks from a wellhead could be 
detected with AVO. Commenters claimed that the EPA did not provide 
adequate justification as to why having two or more wellheads requires 
the use of OGI. Industry commenters believe that the NSPS OOOOb and EG 
OOOOc BSER for multi-wellhead only sites should be quarterly AVO 
inspections only (bimonthly AVO inspections only at most). Another 
commenter \227\ similarly expressed that using AVO inspections to find 
large fugitive emissions at single wellhead only sites is appropriate 
and should also apply to multi-wellhead only well sites. Quarterly AVO 
inspections are appropriate to detect fugitive emissions at multi-
wellhead only well sites, according to the commenter. A commenter \228\ 
stated that wellhead only sites generally have fewer fugitive emissions 
components, and wellheads are constructed with thicker, higher-
pressure-rated iron, causing flanges to be larger such that AVO 
inspections are able to reliably detect any leaks that may occur. The 
commenter believed quarterly AVO inspection of wellhead only sites 
would be an effective and economic means to monitor for leaks at 
wellhead only sites. Another commenter \229\ expressed support for AVO 
for these sites but did not support OGI, due to its cost and because 
the incremental benefit of using OGI on top of AVO would not 
meaningfully reduce emissions.
---------------------------------------------------------------------------

    \226\ EPA-HQ-OAR-2021-0317-2446.
    \227\ EPA-HQ-OAR-2021-0317-2428.
    \228\ EPA-HQ-OAR-2021-0317-2326.
    \229\ EPA-HQ-OAR-2021-0317-2202.
---------------------------------------------------------------------------

    Response: The EPA disagrees with the comment that it should have 
first evaluated AVO and determined its cost effectiveness and then 
assessed whether to add OGI monitoring for multi-wellhead only well 
sites and well sites with major production and processing 
equipment.\230\ While OGI's superiority

[[Page 16905]]

over AVO is clear, the EPA nevertheless offered a detailed explanation 
in the December 2022 Supplemental Proposal (87 FR 74727). As the EPA 
explained, AVO is a simple sensory method that can detect large 
releases such as emissions from open thief hatches; however, not all 
fugitive emissions components have large releases and, therefore, their 
emissions cannot always be detected by AVO. AVO's reliability also 
depends on other factors, including whether the background noise is 
sufficiently low to allow a person to hear leaks such as the hissing 
sound from a high-pressure leak, whether the gas is of a mixture that 
would allow detection by smell, or whether the leaks result in dripping 
or puddles that can be detected visually. In contrast, OGI can reliably 
detect fugitive emissions that AVO cannot. Therefore, in the November 
2021 Proposal, the EPA proposed monitoring fugitive emissions using OGI 
at well sites with baseline emissions at or greater than 3 tpy and no 
monitoring for those with baseline emissions below that level; the EPA 
solicited comment on ``simple AVO checks that could be performed in 
conjunction with the periodic OGI monitoring surveys to help identify 
potential large emission events'' (86 FR 63197). In the December 2022 
Supplemental Proposal, the EPA proposed four subcategories of well 
sites and monitoring regime for each subcategory based on numbers and 
types of equipment. For example, single wellhead only well sites have 
few pieces of simple equipment and therefore few fugitive emissions 
components,\231\ but they have been found to have large emissions that 
result from fugitive emissions components, such as an open valve on a 
well case casing; because the number of components is small and the 
large releases could be detected with AVO, OGI monitoring does not seem 
necessary at a single wellhead only well site.\232\ That is not the 
case with multi-wellhead only well sites, which are the focus of the 
comments summarized above. As the number of wellheads increases, so 
does the number of fugitive emissions components, including those 
associated with smaller emissions that are difficult to detect with 
AVO; however, OGI can detect fugitive emissions from those components 
in addition to the large releases. Accordingly, in the December 2022 
Supplemental Proposal, the EPA proposed adding AVO monitoring to 
routine OGI monitoring requirements in order to identify large 
emissions that could occur in between scheduled OGI surveys at multi-
wellhead only well sites and well sites with major production and 
processing equipment (see 87 FR 74722).
---------------------------------------------------------------------------

    \230\ As explained in the December 2022 Supplemental Proposal 
and reiterated later in this response, the EPA did not propose OGI 
monitoring for single wellhead only well sites based on information 
showing that these emissions are large releases that can be detected 
using AVO (87 FR 74729). Similarly, the EPA did not propose OGI 
monitoring for a small wellsite; the EPA utilized the same model 
results as provided for a single wellhead only well site (87 FR 
74731). As defined, a small well site can only include one piece of 
certain major production and processing equipment, which cannot be a 
controlled storage vessel, a control device, or a natural gas-driven 
process controller or pump (Ibid). As such, the equipment and 
associated fugitive emissions components at a small site are more 
comparable to a single wellhead only well site than to the other two 
subcategories of well sites (see Id. at 74726, table 7).
    \231\ See Id. at 74726, table 7.
    \232\ Id. at 74727.
---------------------------------------------------------------------------

    As discussed in the December 2022 Supplemental Proposal, multi-
wellhead only well sites feature both large emission sources that can 
be identified with AVO as well as additional, generally smaller sources 
of emissions that are more challenging to identify using AVO. In order 
to capture both large and small emissions from multi-wellhead only well 
sites, the EPA proposed semiannual OGI monitoring and quarterly AVO 
surveys for NSPS OOOOb and EG OOOOc. The EPA agrees with commenters 
that periodic AVO surveys are less costly than OGI surveys. However, 
cost is not the only factor in determining the BSER, and other 
considerations, such as effectiveness at reducing emissions from both 
large and small releases, must be considered. As part of its BSER 
analysis for reducing fugitive emissions at well sites, the EPA 
analyzed the costs and emission reductions associated with various 
combinations of OGI and AVO monitoring options for the four categories 
of well sites. The EPA summarized its analysis for multi-wellhead only 
well sites in table 12 and explained how it evaluated the various 
options (see 87 FR 74733, table 12). The EPA found semiannual OGI and 
quarterly AVO to be cost-effective and therefore to be the BSER for 
multi-wellhead only well sites.
d. Subcategorization of Well Sites
    Comment: Several commenters requested that the EPA consider 
maintaining an exemption for low production wells as it pertains to the 
NSPS OOOOb and EG OOOOc. These commenters noted that industry has 
consistently advocated for such an exemption in previous rulemakings. 
Commenters also asserted that exempting low production wells would 
provide meaningful reductions in compliance burden and cost for small 
businesses, with minimal potential impact. Commenters \233\ argued that 
the proposed monitoring requirements and schedule are excessive for 
these sites, provide little environmental benefit, and are prohibitive 
for small owners and operators and will result in the end of their 
operations. One commenter \234\ noted that the U.S. DOE marginal well 
study provides data showing that marginal well sites overwhelmingly 
have methane emissions below 3 tpy. One commenter \235\ urged the EPA 
to modify the rule to include a production rate threshold that would 
exempt wells making less than 6 boe per day. One commenter \236\ 
recommended that the EPA create an intermediate well site category that 
combines production throughput and components, opining that this would 
be a simpler approach that avoids inappropriate results. According to 
the commenter, under the current proposal, some low-producing sites 
would be classified as large sites and be subject to quarterly OGI 
monitoring with bimonthly AVO inspections. The commenter asserted that 
the data from the U.S. DOE marginal well study shows that this category 
of sites has lower total emissions than sites with larger production 
volumes and therefore should not be subject to monitoring requirements 
as stringent as those for larger-producing sites. The commenter 
proposed that intermediate well sites historically considered to be 
``low production'' be permitted to utilize industry practices to 
identify leaks. The commenter asserted that the EPA's proposal places 
an economic burden on owners/operators of low production wells that is 
not justified or supported.
---------------------------------------------------------------------------

    \233\ EPA-HQ-OAR-2021-0317-2179, -2248, -2310, -2713.
    \234\ EPA-HQ-OAR-2021-0317-2403.
    \235\ EPA-HQ-OAR-2021-0317-2179.
    \236\ EPA-HQ-OAR-2021-0317-2446.
---------------------------------------------------------------------------

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

[[Page 16906]]

well study data agrees well with the emissions data included in FEAST 
as modeled for the December 2022 Supplemental Proposal when comparing 
the different equipment component leak data used. The EPA also ran 
several individual monitoring options using the equipment component 
data from the December 2022 Supplemental Proposal, using the component 
data from the December 2022 Supplemental Proposal augmented with U.S. 
DOE marginal well study data, and also using only the U.S. DOE marginal 
well study data. The FEAST model was run using these three sets of 
equipment component leak input data for multi-wellhead only well sites. 
The results demonstrated that varying the specific equipment component 
leak input data had minimal impact on the model results, and the FEAST 
model simulation results did not vary significantly when U.S. DOE 
marginal well study data was included. The full results of the 
additional FEAST modeling the EPA performed following the December 2022 
Supplemental Proposal are presented in a memorandum \237\ available in 
the rulemaking docket. In conclusion, the addition of U.S. DOE marginal 
well study data did not show results that are significantly different 
than what the EPA presented in the December 2022 Supplemental Proposal.
---------------------------------------------------------------------------

    \237\ Memorandum from Jeff Coburn, RTI International. Summary of 
Additional FEAST Modeling Runs. September 25, 2023.
---------------------------------------------------------------------------

    Moreover, the U.S. DOE marginal well study concludes that the 
frequency and magnitude of emissions from well sites are more strongly 
correlated with equipment counts than with production rates. See the 
EPA's response in section XII.A for additional details and data.
    The EPA therefore does not have compelling information that 
suggests low production levels at well sites should provide the basis 
for adding a new subcategory to the fugitive emissions requirements.
    Many factors can affect the profitability of marginal wells and the 
decision to shut in and plug a well, making it difficult to determine 
the full impact of regulation on the financial status of marginal well 
owners, as discussed in chapter 6 of the final rule TSD. While the EPA 
does not have data on the distribution of ownership based on firm size, 
there are small owners and operators who own marginal oil and natural 
gas wells. The EPA remains mindful of how the fugitive emissions 
monitoring requirements will affect small entities and describes steps 
taken to include regulatory flexibility and streamline recordkeeping 
requirements in section 4.4 of the RIA. While developing the fugitive 
emissions monitoring program, the EPA limited monitoring, 
recordkeeping, and reporting requirements to include only what is 
necessary to meet BSER and demonstrate compliance. These streamlined 
requirements benefit owners and operators of well sites (including 
small entities).
e. Delay of Repair Due to Parts Unavailability
    Comment: A commenter \238\ noted that NSPS OOOO and OOOOa allow for 
delay of repair beyond a unit shutdown if ``valve assembly supplies 
have been depleted, and valve assembly supplies had been sufficiently 
stocked before the supplies were depleted.'' The commenter notes that 
in the November 2021 Proposal (86 FR 63174), the EPA recognized that 
operators of older equipment may experience delays in obtaining 
replacement parts. Given current supply chain issues and the larger 
number of well sites, centralized production facilities, and compressor 
stations, the EPA should expand the current delay-of-repair 
requirements to include delays because of parts unavailability.
---------------------------------------------------------------------------

    \238\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: Based on this comment and those summarized later in 
section XI.A.2.b on compressor stations, the EPA is allowing delay of 
repair of fugitive emissions components due to unavailability of 
replacement components (or parts thereof) in certain circumstances at 
well sites, centralized production facilities, and compressor stations. 
Specifically, delay of repair is allowed if replacement is required but 
cannot be acquired and installed within the repair timeline due to 
either of the following conditions: (1) replacement valve supplies have 
been sufficiently stocked but are depleted at the time of repair; or 
(2) a replacement fugitive emissions component or a part thereof 
requires custom fabrication. See section XI.A.2.b for our reasons for 
allowing delay of repair under these specified conditions, our response 
to the major comments on this issue, and additional details on this 
provision.
f. Other Changes
    The EPA has made certain corrections to the regulatory text of NSPS 
OOOOb and EG OOOOc since the December 2022 Supplemental Proposal.
    The EPA is correcting the definition of ``major production and 
processing equipment'' to add certain equipment that were inadvertently 
excluded in the December 2022 Supplemental Proposal. In the preamble to 
the December 2022 Supplemental Proposal, the EPA specifically proposed 
to identify natural gas-driven pneumatic controllers, natural gas-
driven pneumatic pumps, and control devices as ``major production and 
processing equipment'' in the context of defining well site 
subcategories for the fugitive emissions monitoring and repair program 
of NSPS OOOOb and EG OOOOc and justifying requiring quarterly OGI 
monitoring where this equipment is present (87 FR 74723 and 74735). 
Following the publication of the December 2022 Supplemental Proposal, 
the EPA noticed that the draft regulatory text for NSPS OOOOb and EG 
OOOOc accompanying the proposal would have inadvertently adopted, 
without change, the definition of ``major production and processing 
equipment'' in NSPS OOOOa, which has a different fugitive emissions 
monitoring program for well sites than that of NSPS OOOOb and EG OOOOc; 
as a result, natural gas-driven pneumatic controllers, natural gas-
driven pneumatic pumps, and control devices were inadvertently excluded 
from the definition of ``major production and processing equipment'' in 
the proposed NSPS OOOOb and EG OOOOc. The following edits were made to 
align the regulatory text with the EPA's intent as stated in the 
Supplemental Proposal:
    <bullet> Added ``natural gas-driven pumps'' to the list of major 
equipment that puts a well site into the third subcategory (well sites 
with major production and processing equipment or centralized 
production facilities) at 40 CFR 60.5397b(g)(1)(iv)(C) and 40 CFR 
60.5397c(g)(1)(iii)(C);
    <bullet> Added ``natural gas-driven pumps'' to the list of major 
equipment that cannot be present at a small well site at 40 CFR 
60.5430b and 40 CFR 60.5430c; and
    <bullet> Added ``control devices, natural gas-driven process 
controllers, natural gas-driven pumps'' and ``tank batteries'' to the 
definition of major production and processing equipment at 40 CFR 
60.5430b and 40 CFR 60.5430c.
    Similarly, in the December 2022 Supplemental Proposal, the EPA 
proposed as part of the fugitive emissions standards and presumptive 
standards an equipment standard such that thief hatches and other 
openings on a storage vessel that are fugitive emissions components 
must remain closed and sealed at all times except during sampling, 
adding process material, or attended maintenance operations (87 FR 
74731). However, this proposal was not reflected in the

[[Page 16907]]

regulatory text accompanying the December 2022 Supplemental Proposal. 
The EPA is finalizing this requirement, which has been added to the 
regulatory text (see 40 CFR 60.5397b(g)(1)(ii) and (iv) and 40 CFR 
60.5397c(g)(1)(i) and (iii)).
    Lastly, the EPA added to the final rules definitions of single 
wellhead only well sites and multi-wellhead only well sites at 40 CFR 
60.5430b and 40 CFR 60.5430c to avoid confusion.
2. Fugitive Emissions at Compressor Stations
    In section X.A.2 of this document, the final NSPS OOOOb and EG 
OOOOc requirements for fugitive emissions components at compressor 
stations are summarized. The BSER analysis for fugitive emissions 
components at compressor stations is unchanged from what was presented 
in the December 2022 Supplemental Proposal (see 87 FR 74739-40, section 
IV.A.2: OGI Monitoring at Compressor Stations). In the December 2022 
Supplemental Proposal, the EPA proposed the BSER as monthly AVO 
combined with quarterly OGI (or EPA Method 21) monitoring requirements 
for fugitive emissions components affected facilities located at 
compressor stations, which would take the form of a work practice 
standard. However, significant comments were received on the December 
2022 Supplemental Proposal on the following topics: (1) the monthly AVO 
monitoring requirement and (2) delay of repair for parts 
unavailability. Comments on these topics and the EPA's responses are 
discussed here. These comments and the EPA's responses to these 
comments generally apply to the standards proposed in both the NSPS 
OOOOb and EG OOOOc. The EPA's full response to comments on the November 
2021 Proposal and December 2022 Supplemental Proposal, including any 
comments not discussed in this preamble, can be found in the EPA's RTC 
document for the final rule.\239\
---------------------------------------------------------------------------

    \239\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

a. Monthly AVO Monitoring
    Comment: Some commenters claim that the monthly AVO requirement for 
compressor stations is unnecessary. One commenter \240\ indicated that 
to require monthly AVO and quarterly OGI or EPA Method 21 monitoring 
and recordkeeping is overly burdensome and unnecessary for compressor 
stations. This commenter believes that existing equipment and 
monitoring methods have proven effective and have minimized emissions, 
and believes a baseline threshold for low-volume compressor stations 
and periodic AVO inspections and documentation would effectively 
achieve the goals of the proposed requirements. Another commenter \241\ 
argued that, compared to state-of-the-art continuous monitoring 
systems, the proposed requirement for monthly AVO inspections and 
quarterly OGI inspections provides neither the greatest emissions 
reduction nor the most economical solution. This commenter encouraged 
the EPA to also allow continuous monitoring technology solutions as the 
BSER for compressor stations. On the other hand, a commenter \242\ 
recommended that monthly AVO inspections in addition to quarterly 
instrument-based leak detection and repair inspections should be 
required at gathering and boosting and transmission stations.
---------------------------------------------------------------------------

    \240\ EPA-HQ-OAR-2021-0317-2211.
    \241\ EPA-HQ-OAR-2021-0317-2440.
    \242\ EPA-HQ-OAR-2021-0317-2180.
---------------------------------------------------------------------------

    Response: For the reasons explained here, the EPA found 
unpersuasive those comments suggesting that the proposed fugitive 
emissions monitoring requirements at compressor stations, in particular 
monthly AVO inspections, are unnecessary or burdensome. As explained in 
the December 2022 Supplemental Proposal (87 FR 74739), regular AVO 
inspections at compressor stations can be conducted by any staff at the 
site without the need for any special expertise. In fact, AVO 
inspection was added in the December 2022 Supplemental Proposal in 
response to recommendations by some commenters <SUP>243 244</SUP> on 
the November 2021 Proposal recommending AVO as a low-cost method that 
is effective at identifying emissions, even for small-company 
compressor stations. The commenters specifically noted that even though 
small-company compressor stations are not manned 24 hours per day, they 
are visited weekly, if not daily. The EPA found the comments persuasive 
and did not see a need to confirm the commenters' assertions by 
conducting its own cost analysis for conducting monthly AVO inspections 
for compressor stations. The EPA notes that no commenter disputed or 
otherwise questioned the comments described above regarding the low 
cost of AVO monitoring, which the EPA relied upon in its December 2022 
Supplemental Proposal. With regard to the comment suggesting that OGI 
monitoring is unnecessary because AVO surveys during these frequent 
visits would effectively achieve the EPA's emission reduction goals, 
the EPA disagrees that AVO surveys alone (i.e., without quarterly OGI 
monitoring) qualify as the BSER because OGI is needed to detect 
fugitive emissions that are not detectable by AVO. In addition, the EPA 
received no information that caused it to change its assessment that 
quarterly OGI monitoring at compressor stations is not cost-effective. 
Accordingly, the EPA is finalizing its determination that monthly AVO 
monitoring and quarterly OGI monitoring, in combination with repair 
requirements, represents the BSER for fugitive emissions components at 
both new and existing compressor stations.
---------------------------------------------------------------------------

    \243\ EPA-HQ-OAR-2021-0317-0585.
    \244\ EPA-HQ-OAR-2021-0317-0814.
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    The EPA supports the use of continuous monitoring systems to detect 
fugitive emissions at compressor stations. Although at this point the 
EPA does not have sufficient information to include this new but 
rapidly advancing technology in its BSER analysis, the EPA is 
finalizing a pathway for owners and operators to utilize continuous 
monitoring technologies at well sites, centralized production 
facilities, and compressor stations as part of the advanced methane 
detection technology provisions of the rule.
b. Delay of Repair Due to Parts Unavailability
    Comment: Several commenters requested that a delay of repair be 
allowed when parts are unavailable to do the required repairs and note 
that the EPA requested feedback in the November 2021 Proposal (86 FR 
63174) on whether to allow delay of repair due to parts unavailability. 
One commenter \245\ noted that delay of repair due to unavailability of 
valve assembly replacement supplies was included for onshore natural 
gas processing plants in the December 2022 Supplemental Proposal, but 
questions why it was not included for other natural gas industry 
segments that include similar arrays of high-pressure gas valves and 
rely on the same types of replacement supplies. Another commenter \246\ 
notes the same difference and adds that the array of large valves that 
require special service for parts or replacement for compressor 
stations may be more complicated than at some natural gas processing 
plants. Additionally, the same commenter says that supply chain delays 
have lengthened delivery times for

[[Page 16908]]

replacement parts and that operators can ensure that replacement parts 
are ordered in a timely manner but cannot control how quickly the parts 
will arrive. Both commenters discuss the timelines for delivery of 
replacement valves, which ranged between 16 and 40 weeks, depending on 
size, at the time of the comments.
---------------------------------------------------------------------------

    \245\ EPA-HQ-OAR-2021-0317-2366.
    \246\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------

    A commenter \247\ also asserted that larger, older compressor 
stations were expanded over time with different compressor sizes, 
types, and vintages, resulting in a large array of unique valves at 
compressor stations. The commenter continued, saying that parts are not 
interchangeable between different manufacturers, models, or even 
different vintages of the same equipment and that if a part breaks on 
an older piece of equipment, the comparable part that is used for new 
compressors may not be the right size or configuration for the older 
equipment. In such cases, the appropriate parts for that equipment will 
need to be custom fabricated; manufacturers do not maintain an 
inventory of expensive parts, unique parts, or parts for older 
equipment. The commenter estimated that the timeline for custom 
fabrication of station valves can require 4 to more than 12 months, 
depending on the size and uniqueness of the part. Another commenter 
\248\ explained that in their experience, the parts most likely to be 
in short supply are large, unique valves used for compressor isolation 
or isolating sections of a facility or pipeline; these valves are not 
standard items, and they come in many configurations. The commenter 
explained that, given the size and unique specifications of each valve, 
it is not practical or economical to maintain a significant inventory 
of such items. They added that such items may require special 
fabrication with lead times of many months. As an example, the 
commenter described a recently identified leak on a 16-inch valve. Upon 
investigation, they determined that repair (e.g., replacing 
subcomponents of the large valve) was not possible and an exact 
replacement valve could not be ordered because the valve was obsolete. 
Investigation into a new replacement indicated a lead time on the order 
of at least 18 weeks.
---------------------------------------------------------------------------

    \247\ Id.
    \248\ EPA-HQ-OAR-2021-0317-0782.
---------------------------------------------------------------------------

    Commenters also recommended that delay of repair due to parts 
unavailability should extend to parts other than valves. One commenter 
\249\ stated that compression includes an array of parts associated 
with the compression driver, the compressor, and associated valving, 
piping, and other processing equipment. A valve is one example of a 
part type that may not be available for repair or replacement, but 
other large, unique legacy parts associated with other legacy process 
equipment may need to be machined or more major components may need to 
be constructed.
---------------------------------------------------------------------------

    \249\ EPA-HQ-OAR-2021-0317-2366.
---------------------------------------------------------------------------

    Conversely, another commenter \250\ contended that the availability 
of parts is not a valid concern because replacement parts could be 
easily procured, and operators could stockpile fugitive emission 
components and parts thereof prior to this rule's requirements coming 
into effect.
---------------------------------------------------------------------------

    \250\ EPA-HQ-OAR-2021-0317-0844.
---------------------------------------------------------------------------

    Commenters also responded to the EPA's solicitation of input on the 
timeline for repair upon receipt of the part and any associated 
documentation. One commenter \251\ suggested that repairs must be 
completed within 30 days following the receipt of the replacement part, 
provided that conducting the repair would not require a unit or 
wellhead shutdown and that, if shutdown was required, the repair should 
occur during the next scheduled maintenance shutdown. Similarly, 
another commenter \252\ requested that the EPA provide in the 
regulatory text that, where no shutdown or blowdown is needed, the 
operator should repair the leak within 30 days after receiving the 
parts. The commenter requested that where a repair requires a shutdown 
or blowdown, the regulatory text allow the repair to be performed 
during the next scheduled shutdown for maintenance after receipt of the 
requisite parts, not to exceed 2 years. The commenter stated that this 
will avoid unnecessary blowdown emissions. One commenter \253\ 
recommended that the required recordkeeping follow current NSPS OOOOa 
criteria, where the operator documents the delay basis and repair 
schedule. Another commenter suggested that the operator be required to 
support the necessity of delay of repair due to parts unavailability 
through rigorous documentation, including but not limited to: a 
reasonable explanation of why the operator did not have a spare part on 
hand; a justification of why the equipment failure was not foreseeable 
at any point from the date of the proposed regulations until the date 
of failure; proof that such failures are not common at similar 
compressor stations of similar age; maintenance and inspection records 
supporting the non-foreseeability of the failure; proof and date that 
the replacement part was ordered immediately upon detection; and proof 
that the part was installed as quickly as possible upon receipt.
---------------------------------------------------------------------------

    \251\ EPA-HQ-OAR-2021-0317-1289.
    \252\ EPA-HQ-OAR-2021-0317-0815.
    \253\ EPA-HQ-OAR-2021-0317-0782.
---------------------------------------------------------------------------

    Response: In response to these comments, the EPA is allowing delay 
of repair that requires replacement where the replacement cannot be 
acquired and installed within the repair timeline due to either of the 
following conditions: (1) Replacement valve supplies have been 
sufficiently stocked but are depleted at the time of repair; or (2) a 
replacement fugitive emissions component or a part thereof requires 
custom fabrication. In either situation, the required replacement must 
be ordered within 10 calendar days after the first attempt at repair. 
The repair must be completed within 30 calendar days after receipt of 
the replacement or during the next scheduled shutdown for maintenance 
after the replacement is received (if the repair requires a shutdown). 
Operators must document the date the leak was added to the delay-of-
repair list, the date the replacement fugitive emissions component or 
part thereof was ordered, the anticipated delivery date, and the actual 
delivery date as part of their fugitive emission survey records.
    The EPA acknowledges that during the 2016 rulemaking promulgating 
NSPS OOOOa and the 2021 amendments, the EPA received comments 
requesting that the EPA allow delay of repair due to parts 
unavailability. The EPA declined to do so in 2016, explaining that 
``[t]he EPA does not agree that unavailability of supplies or custom 
parts is a justification for delaying repair (i.e., beyond the 30 days 
for repair provided in this final rule) since the operator can plan for 
repair of fugitive emission components by having stock readily 
accessible or obtaining the parts within 30 days after finding the 
fugitive emissions.'' 81 FR 35824, 35858. In 2021, the EPA similarly 
expressed that it ``does not agree a lack of parts is a sufficient 
justification to delay.'' \254\
---------------------------------------------------------------------------

    \254\ Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources Reconsideration 40 CFR part 60, 
subpart OOOOa, Response to Public Comments on Proposed Rule (83 FR 
52056, October 15, 2018), at 8-199.
---------------------------------------------------------------------------

    However, regarding the comment noting that the standards (and 
presumptive standards) for onshore natural gas processing plants in the 
proposed NSPS OOOOb and EG OOOOc would have allowed delay of valve 
repair due to depletion of valve supplies and requesting that the EPA 
allow the same in the fugitive emissions standards

[[Page 16909]]

for well sites and compressor stations, the EPA concludes that well 
sites and compressor stations face some of the same valve assembly 
supply constraints as onshore natural gas processing plants and that 
operators can ensure timely ordering of replacement fugitive components 
or parts thereof but cannot control replacement delivery timelines. 
Thus, the EPA is including similar delay-of-repair provisions for valve 
assembly supplies that had been sufficiently stocked but are depleted 
at the time of the required repair for wellsite and compressor station 
fugitives as for onshore natural gas processing plants in this rule. 
The final fugitive emissions standards for well sites and compressor 
stations under NSPS OOOOb (and presumptive standards under EG OOOOc) 
allow delay of repair due to depletion of supplies for valves only. 
This is consistent with the standards for onshore natural gas 
processing plants, which have provided such allowance for valves only 
since the standards were first promulgated in 1985, and the EPA has not 
received information showing difficulty of repair due to well-stocked 
supplies of other fugitive emissions components or parts thereof that 
were depleted before repair could be completed.
    In addition to allowing delay of repair of valves due to depletion 
of supplies as described above, the final rule allows delay of repair 
where repair requires replacement of a custom-made fugitive emissions 
component or a part thereof. The comments on the November 2021 Proposal 
and December 2022 Supplemental Proposal also include supporting 
information on exceptional, infrequent circumstances where a 
replacement part requires custom fabrication. Specifically, the 
information includes insight into the quantity and variety of vintage 
equipment at compressor stations, the unlikelihood of manufacturers' 
stocking replacement parts for vintage equipment and thus the need for 
custom fabrication of replacement supplies, and the timeline for 
fabrication and delivery of custom supplies. Recent examples of 
extensive supply chain delays have highlighted that a delay of repair 
may be needed for circumstances beyond an owner or operator's 
control.\255\ In light of the information on the challenges and the 
time needed to acquire parts that require custom fabrication and the 
current supply chain issue, we are including in the final NSPS OOOOb 
and the model rule in EG OOOOc provisions for delay of repair where 
replacement is required and the replacement fugitive emissions 
component or a part thereof requires custom fabrication. As described 
above, for delay of repair under either of the two specified 
conditions, the final rule prescribes specific timeframes for ordering 
and installing the parts to ensure that repair is completed in a timely 
manner, as well as the specific records that must be kept to 
demonstrate compliance with these requirements.
---------------------------------------------------------------------------

    \255\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------

B. Advanced Methane Detection Technology Work Practices

    In the December 2022 Supplemental Proposal, the EPA proposed a 
revised alternative fugitive emissions monitoring and repair program 
for new, modified, or reconstructed fugitive emissions sources (i.e., 
collection of fugitive emissions components located at well sites, 
centralized production facilities, and compressor stations). This 
program was intended to provide owners and operators with the 
flexibility to use advanced methane detection technologies in lieu of 
the ground-based OGI and AVO surveys that the EPA had proposed for 
fugitive emissions sources. Among other things, the December 2022 
Supplemental Proposal included a proposed ``matrix'' that would specify 
different screening frequencies corresponding to a range of minimum 
detection thresholds, in contrast to the single screening frequency and 
detection level proposed in the November 2021 Proposal. In addition, 
the EPA proposed to allow owners and operators the option of using 
continuous monitoring technologies as another alternative to ground-
based OGI and AVO surveys and proposed long- and short-term emission 
rate thresholds that would trigger corrective action. The EPA also 
proposed monitoring plan requirements for owners and operators that 
chose to implement the alternative fugitive emissions monitoring 
approach and proposed a clear and streamlined pathway for technology 
developers and other entities to seek the EPA's approval for the use of 
advanced methane detection technologies under this alternative option.
    This section of this document presents a summary of significant 
comments received on advanced methane detection technologies and the 
EPA's response to those comments, as well as certain changes in the 
final standards for using advanced methane detection technologies for 
monitoring fugitive emissions components at new and existing facilities 
and for conducting continuous inspection and monitoring for covers and 
closed vent systems. For other comments on the proposed program and the 
EPA's response thereto, see chapter 5 of the RTC document, Advanced 
Methane Detection Technologies.\256\ For final standards and 
requirements that have not changed since the December 2022 Supplemental 
Proposal, the supporting rationales are not reiterated in this 
preamble. The rationale for those standards and requirements can be 
found in section IV of the preamble for the December 2022 Supplemental 
Proposal (87 FR 74702 at 74722-810, December 6, 2022).
---------------------------------------------------------------------------

    \256\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

1. Periodic Screening
a. Matrix Table and Screening Frequency
    Comment: The EPA received considerable support for the flexibility 
to use advanced methane detection technologies in lieu of using OGI, 
EPA Method 21, or AVO to monitor fugitive emissions components in 
response to the December 2022 Supplemental Proposal. One commenter 
\257\ supported the proposed frequencies in the matrix, noting that 
their independent equivalency modeling matched the results of the EPA's 
FEAST modeling across a variety of scenarios, and supported the EPA's 
choices of model inputs that made assumptions based on nationally 
applicable factors and considerations, as these inputs apply across the 
country to sources in different oil and gas producing regions and 
basins. Other commenters <SUP>258 259</SUP> raised concerns that the 
EPA's FEAST modeling overestimates the effectiveness of AVO and OGI, 
resulting in matrix frequencies that are overly stringent. Another 
commenter \260\ discussed the potential use of an alternative emission 
rate distribution in the model, from a study that included a larger 
range of emission rates than was used in the EPA's modeling.
---------------------------------------------------------------------------

    \257\ EPA-HQ-OAR-2021-0317-2433.
    \258\ EPA-HQ-OAR-2021-0317-2387.
    \259\ EPA-HQ-OAR-2021-0317-2428.
    \260\ EPA-HQ-OAR-2021-0317-2405.
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    A commenter \261\ considered the minimum detection thresholds and 
monitoring frequencies in the proposed matrix to be insufficiently 
differentiated between the tiers with respect to detection levels. 
Several

[[Page 16910]]

commenters <SUP>262 263</SUP> raised concern that the 30 kg/hr periodic 
screening tier provides a less stringent work practice for emissions 
reduction and urged the EPA to remove the 30 kg/hr detection tier.
---------------------------------------------------------------------------

    \261\ EPA-HQ-OAR-2021-0317-1686, -2345.
    \262\ EPA-HQ-OAR-2021-0317-2405.
    \263\ EPA-HQ-OAR-2021-0317-2430.
---------------------------------------------------------------------------

    Another commenter \264\ stated that advanced methane detection 
technologies are evolving rapidly and are a key component of the 
commenter's strategy for broader emission reductions. The commenter 
believed that these technologies have the potential to be more 
effective at finding leaks on a broader scale, allowing for faster 
detection and mitigation, leading to a greater reduction in methane 
emissions. This commenter was concerned that there may be inadvertent 
disincentives that are contrary to the intent of the EPA, which is to 
encourage innovation resulting in meaningful emissions reductions. The 
commenter was concerned that disincentives may encourage operators to 
simply continue their existing OGI survey programs as the default 
option, which could hinder broad development and adoption of advanced 
methane detection technologies.
---------------------------------------------------------------------------

    \264\ EPA-HQ-OAR-2021-0314-2360.
---------------------------------------------------------------------------

    Response: Regarding the modeling conducted to develop the periodic 
screening matrices in the December 2022 Supplemental Proposal, while 
the EPA acknowledges there are alternative inputs available for the 
models, we incorporated the best available information from recent 
studies to characterize a distribution for both common leaks and super-
emitters. The results of our fugitive emissions modeling fell within 
the ranges observed in other literature assessments. As mentioned 
above, we received supportive comments for our modeling. The commenters 
who expressed otherwise provided limited additional peer-reviewed data 
with which we could revise our model assumptions; much of the data 
focused on studies collected using a singular technology (e.g., aerial 
survey), and the emission distribution appeared to be weighted toward 
emissions this specific methane detection technology could identify. 
While the EPA's emission distribution in our model also was developed 
using studies conducted with aerial surveys, we augmented that 
distribution with ground-level studies to get a more complete emission 
distribution, including the lower-level emissions. Therefore, we 
believe the results from the modeling conducted for the December 2022 
Supplemental Proposal are well-supported.
    With the continued development and deployment of advanced methane 
detection technology, we expect further study on the distribution of 
methane emissions from this sector, in particular after promulgation of 
this rule providing a pathway for the use of advanced technologies. As 
additional studies are conducted on emission distributions across this 
sector, it is possible that the underlying emissions rate distribution 
in our modeling could potentially be updated in the future. However, 
the inputs in the modeling conducted for the December 2022 Supplemental 
Proposal were based on the best information available to the EPA during 
this rulemaking. Therefore, we continue to believe that the modeling 
results are well-supported and appropriate for the development of the 
periodic screening matrices.
    In this final rulemaking, the EPA finalized the proposed matrices 
tables (tables 3 and 4 in NSPS OOOOb and EG OOOOc) with some 
adjustments in response to comments. Several commenters questioned 
whether an annual OGI survey is necessary in order for the use of 
certain periodic screening technologies to be equivalent to the 
fugitive emissions monitoring requirements discussed in section XI.A of 
this document. Based on the comments we received, the EPA reviewed the 
modeling results, reexamined the effectiveness of an annual OGI survey 
on the matrix tiers, and evaluated the uncertainty in the modeling 
results. We found that for the lower tiers of the matrix tables 
(corresponding to the most sensitive advanced methane detection 
technologies), the effectiveness of the annual OGI survey in reducing 
methane emissions in the FEAST model was minimal. Further, we found 
that at the highest tiers of the matrix (corresponding to the least 
sensitive advanced methane detection technologies), the annual OGI 
survey accounted for the bulk of the modeled emission reductions, and 
the periodic screening itself yielded relatively small reductions in 
emissions. Based on this additional review, we are revising the 
periodic screening matrices tables in the final rule by removing the 
proposed highest tier corresponding to the least sensitive technologies 
(<=30 kg/hr) and by removing the proposed requirement to conduct an 
annual OGI survey at the lowest detection threshold tier (i.e., 1 kg/
hr) in table 1 (which applies to well sites, centralized production 
facilities, and compressor stations subject to AVO inspections with 
quarterly OGI monitoring surveys). We have also made a small adjustment 
in the monthly survey.
    The EPA is finalizing the proposed matrices (with some adjustments 
as described above), which the EPA believes reflect at least the same 
levels of emission reductions as those from complying with the required 
fugitive emissions work practice standards for well sites, centralized 
production facilities, and compressor stations. In addition, in 
response to comments on the importance of incentivizing the use of 
advanced methane detection technologies, the EPA is including in the 
final rule an interim matrix in lieu of table 1 that will apply for the 
next 2 years. The EPA agrees with the comments that advanced methane 
detection technologies have the potential to be more effective at 
finding leaks more quickly than traditional ground-based fugitive 
emission surveys; therefore, it is important to develop a framework 
that encourages innovation and the continued development of advanced 
methane detection technologies. The EPA acknowledges that these 
technologies will only continue to develop if owners and operators have 
a desire to implement them. Based on our current understanding of the 
state of advanced methane detection technologies, while there are some 
technologies that can measure at the lowest detection threshold levels 
in the periodic screening matrices under certain conditions, we 
currently do not have available data on any technologies that can 
achieve these minimum detection thresholds at all sites and in all 
conditions. Because these technology developers have had less than a 
year (since publication of the December 2022 Supplemental Proposal) to 
understand and test the proposed target detection thresholds the 
technologies need to meet, there has not been adequate time to develop 
data that push the detection thresholds down to the lowest levels of 
the proposed periodic screening matrix (at 1 to 2 kg/hr). For the 
reason explained above, it is understandable that there may be some 
reluctance at this time to use such technologies to comply with NSPS 
OOOOb at these very low detection thresholds until more data is 
generated to confirm their detection capabilities. We believe that, if 
given opportunities to use the advanced technologies, over time users 
will show that these technologies can meet the minimum detection 
thresholds in these lowest levels of the periodic screening matrix in 
table 1. We therefore agree with the commenter that it is

[[Page 16911]]

critically important to incentivize the early adoption of these 
alternative technologies. To that end, as part of the final rule, we 
have developed an interim periodic screening that will apply in lieu of 
the matrix table for well sites, centralized production facilities, and 
compressor stations subject to AVO inspections with quarterly OGI 
monitoring surveys (table 1 in NSPS OOOOb) for the next 2 years (i.e., 
until March 9, 2026). Under this interim periodic screening matrix, the 
lowest detection threshold is <=3 kg/hr, and it requires quarterly 
screening frequency. While we are increasing the minimum detection 
threshold to <=3 kg/hr in this interim 2-year period to incentivize the 
use of advanced technologies, the EPA expects that these technologies 
will be able to achieve much better (i.e., lower) detection thresholds 
in many use cases, which will be reflected in the records once a 
technology has been approved by the EPA as an alternative and deployed 
for purposes of NSPS OOOOb. At the end of the interim 2-year period, 
the periodic screening matrix in table 1 of NSPS OOOOb, which sets 
survey frequencies for lower detection thresholds (<=1 kg/hr and <=2 
kg/hr), will apply. The EPA has chosen not to provide an interim 
periodic screening in lieu of the matrix table for well sites, 
centralized production facilities, and compressor stations subject to 
AVO inspections with semiannual OGI monitoring surveys (table 2 in NSPS 
OOOOb). The periodic screening matrix for these sources already allows 
using an advanced methane detection technology with a detection 
threshold of <5 kg/hr level. Because we anticipate owners and operators 
will conduct the screenings of all their sites (those subject to table 
1 and those subject to table 2) on the same schedule and table 2 
already accommodates the interim periodic screening level for table 1, 
EPA has determined that it is unnecessary to create an interim periodic 
screening for sites subject to table 2.
    Comment: Several commenters <SUP>265 266</SUP> asked that the EPA 
allow NSPS OOOOa sources to comply with the advanced methane detection 
technology provisions in NSPS OOOOb. One of these commenters requested 
that the EPA consider mechanisms to enable sources subject to NSPS 
OOOOa to demonstrate compliance with the fugitive emission requirements 
in NSPS OOOOa using any advanced methane detection technologies 
approved in NSPS OOOOb prior to the effective date of state or Tribal 
plans approved under EG OOOOc. Another commenter raised concerns that 
the time needed to seek approval to use these advanced methane 
detection technologies for existing sources through the AMEL process 
and EG OOOOc state plan implementation could take years.
---------------------------------------------------------------------------

    \265\ EPA-HQ-OAR-2021-0317-2430.
    \266\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA agrees with the suggestion to allow a mechanism 
outside of the AMEL process to allow existing facilities subject to 
NSPS OOOOa to use advanced methane detection technologies. We agree 
that a comprehensive periodic screening program that uses an advanced 
methane detection technology approved by the EPA under NSPS OOOOb in 
which all the emissions detected are repaired in accordance with NSPS 
OOOOb will result in emission reductions similar to or better than the 
reductions under the existing fugitive emissions work practice at well 
sites and compressor stations in NSPS OOOOa. However, the periodic 
screening matrices in NSPS OOOOb and in EG OOOOc reflect the overall 
fugitive emissions reductions equivalent to the reductions that would 
be achieved for that site in the standard fugitive emissions work 
practice using OGI and AVO under NSPS OOOOb (and presumptive standards 
under EG OOOOc), which includes equipment not included in the 
definition of ``fugitive emissions component'' in NSPS OOOOa. The EPA 
can only determine that the same or better emission reductions are 
achieved if an owner or operator complies with the advanced methane 
detection technology work practices in NSPS OOOOb by repairing all 
fugitive emissions, including emissions from equipment not included in 
the definition of ``fugitive emissions component'' in NSPS OOOOa, such 
as uncontrolled tanks, and performing required investigative analyses. 
Therefore, as discussed in section IX.C of this preamble, we are 
amending the regulatory text in NSPS OOOOa to include a provision that 
compliance with the advanced methane detection technology work 
practices approved under NSPS OOOOb will be deemed compliance with the 
applicable fugitive emissions standards for the same facility in NSPS 
OOOOa.
b. Technology Flexibility
    Comment: Commenters <SUP>267 268</SUP> encouraged the EPA to 
incorporate a pathway into the final rule to allow for the use of a 
combination of technologies, both traditional and advanced, to achieve 
equivalent emissions reductions. The EPA received several comments 
requesting additional flexibility in the matrix, including the 
allowance to use multiple technologies at a single site in a layered or 
tiered fashion. Commenters \269\ were concerned that by not conducting 
equivalency modeling for a combination of alternative technologies, the 
proposed matrix would fail to provide sufficient flexibility for owners 
and operators that find it necessary to apply multiple advanced 
technologies due to equipment limitations, operating conditions, or 
economic factors. Several commenters <SUP>270 271</SUP> discussed that 
the matrix should account for the occasional need to deploy different 
monitoring technologies due to seasonal environmental conditions, 
noting that inclement weather, including wind, rain, and ground snow 
cover, can adversely affect methane detection performance. A commenter 
recommended allowing OGI surveys during the months when advanced 
detection technologies cannot be deployed.
---------------------------------------------------------------------------

    \267\ EPA-HQ-OAR-2021-0317-2360.
    \268\ EPA-HQ-OAR-2021-0317-2388.
    \269\ EPA-HQ-OAR-2021-0317-2391.
    \270\ EPA-HQ-OAR-2021-0317-2405.
    \271\ EPA-HQ-OAR-2021-0317-2235.
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    Some commenters \272\ suggested that continuous monitoring 
technologies may fit within the periodic screening framework and urged 
the EPA to consider such technologies within that context. Another 
commenter recommended that continuous monitoring be incorporated with 
periodic screening to create a single framework for alternative methane 
detection technology.
---------------------------------------------------------------------------

    \272\ EPA-HQ-OAR-2021-0317-2448.
---------------------------------------------------------------------------

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

[[Page 16912]]

conditions can adversely affect some methane detection technologies. In 
the final rule we allow the owner or operator to conduct an OGI survey 
in place of a periodic screening event at any time. The planned use of 
multiple technologies, including OGI, must be incorporated into the 
site-specific monitoring plan.
    The EPA also agrees that continuous monitoring technologies can fit 
within the periodic screening framework, especially those technologies 
that may not be able to comply with the requirements in the continuous 
monitoring framework. While it was not explicitly stated in the 
December 2022 Supplemental Proposal, we intended for continuous 
monitoring technology to be considered as a candidate for the periodic 
screening approach. The EPA continues to consider the periodic 
screening approach a valid pathway for continuous methane detection 
technology.
c. Spatial Resolution
    Comment: Several commenters <SUP>273 274</SUP> discussed that some 
measurement technologies have tighter spatial resolution which may 
enable the detection of equipment-specific emissions, and as such, use 
of these technologies may not require a follow-up OGI survey of the 
entire site. One commenter mentioned that one may be able to 
conclusively identify the fugitive emissions component with certain 
measurement technologies. Another commenter \275\ urged the EPA to 
require follow-up OGI surveys only within the general area of detection 
from a periodic screening event.
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    \273\ EPA-HQ-OAR-2021-0317-2406.
    \274\ EPA-HQ-OAR-2021-0317-2366.
    \275\ EPA-HQ-OAR-2021-0317-2432.
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    Response: The EPA finds these comments compelling and in the final 
rule is incorporating the concept of spatial resolution of measurement 
technology into the follow-up actions an owner or operator must take 
when a periodic screening event results in a confirmed detection. We 
have included three classifications for spatial resolution in the final 
rule: (i) facility-level spatial resolution, meaning an alternative 
test method with the ability to identify emissions within the boundary 
of a well site, centralized production facility, or compressor station; 
(ii) area-level spatial resolution, meaning a technology with the 
ability to identify emissions within a radius of 2 meters of the 
emissions source; and (iii) component-level spatial resolution, meaning 
a technology with the ability to identify emissions within a radius of 
0.5 meters of the emissions source. Entities requesting an alternative 
test method for advanced methane measurement technology would identify 
and verify the spatial resolution of the measurement technology as part 
of the request.
    In the final rule, for periodic screening events conducted with 
technologies that have facility-level spatial resolution, we have 
maintained the follow-up actions an owner or operator must take in 
response to a confirmed detection that were outlined in the December 
2022 Supplemental Proposal. However, for periodic screening events 
conducted with technologies that have area-level or component-level 
spatial resolution, we have targeted the follow-up actions the owner or 
operator must take. The follow-up monitoring that must be conducted for 
a confirmed detection during a periodic screening event using a 
technology with area-level spatial resolution includes a monitoring 
survey of all the fugitive emissions components located within a 4-
meter radius of the location of the confirmed detection and, if the 
confirmed detection occurred in a portion of a site with a storage 
vessel or closed vent system, inspection of all covers and closed vent 
systems that are connected to all storage vessels and closed vent 
systems that are within a 2-meter radius of the location. The follow-up 
monitoring that must be conducted for a confirmed detection during a 
periodic screening event using a technology with component-level 
spatial resolution includes a monitoring survey of all the fugitive 
emissions components located within a 1-meter radius of the location of 
the confirmed detection and, if the confirmed detection occurred in a 
portion of a site with a storage vessel or closed vent system, 
inspection of all covers and closed vent systems that are connected to 
all storage vessels and closed vent systems that are within a 0.5-meter 
radius of the location. The EPA is requiring inspection of the entire 
closed vent system in order to identify a potential cause of the 
failure. The EPA has also incorporated the requirement to verify the 
spatial resolution of a measurement technology as part of the 
alternative test method provisions.
d. Root Cause Analysis
    Comment: Several commenters <SUP>276 277</SUP> supported the 
requirement that an owner or operator investigate the source and 
cause(s) of significant emissions found through periodic screening 
events. However, many commenters took exception to the proposed use of 
``root cause analysis'' for investigating potential causes of 
emissions. One commenter \278\ noted that the concept of ``root cause 
analysis'' is embedded in numerous other regulatory and non-regulatory 
programs and has varied meaning and purpose in each application. 
Another commenter \279\ asserted that the phrase ``root cause 
analysis'' has connotations that lead to a much more involved process 
than the EPA appears to envision in this rule. Many of these commenters 
suggested that ``root cause analysis'' be replaced by ``investigative 
analysis,'' broadly meaning the owner or operator must determine what 
caused the emissions event to occur and take steps to ensure that it 
will not happen again.
---------------------------------------------------------------------------

    \276\ EPA-HQ-OAR-2021-0317-2428.
    \277\ EPA-HQ-OAR-2021-0317-2363.
    \278\ EPA-HQ-OAR-2021-0317-2402.
    \279\ EPA-HQ-OAR-2021-0317-2298.
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    Response: The EPA agrees with the concern raised by commenters and 
in the final rule requires an investigative analysis as opposed to a 
root cause analysis. For the purpose of this final rule, an 
investigative analysis is the determination of the underlying primary 
and other contributing cause(s) of the emissions event. For a control 
device, the investigative analysis must include a determination that 
the control device is operating in compliance with the applicable 
requirements, and if not, what actions are necessary to bring the 
control device into compliance and prevent future failures of the 
control device from the same underlying cause(s). For a cover or closed 
vent system, the investigative analysis must include a determination of 
whether the system was operated outside of the engineering design 
analysis and whether updates are necessary for the cover or closed vent 
system to prevent future emissions from the cover or closed vent 
system.
2. Continuous Monitoring
a. Continuous Monitoring System Criteria
    Comment: Several commenters <SUP>280 281</SUP> requested that the 
framework for continuous monitoring set action levels based on the 
concentration of emissions as an alternative to the action levels based 
on the mass rate of emissions in order to allow owners and operators to 
use a broader range of continuous monitoring systems. One commenter 
\282\ supported the EPA's inclusion of health checks for devices within 
the continuous monitoring system but

[[Page 16913]]

suggested that the health checks rely on functionality instead of 
connectivity. Several commenters \283\ requested more flexibility as to 
how often these systems must transmit data. Other commenters \284\ 
contended that flexibility in the downtime requirement is necessary, as 
typical downtime can be 4 or more days per month for remote locations.
---------------------------------------------------------------------------

    \280\ EPA-HQ-OAR-2021-0317-2340.
    \281\ EPA-HQ-OAR-2021-0317-2235.
    \282\ EPA-HQ-OAR-2021-0317-2363.
    \283\ EPA-HQ-OAR-2021-0317-2248.
    \284\ EPA-HQ-OAR-2021-0317-2409.
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    Response: The EPA agrees that it is important to facilitate the use 
of a broad range of continuous monitoring systems in the advanced 
methane detection technology provisions of this rule, because they 
allow more rapid detection of leaks and thus an enhanced ability to 
promptly respond and prevent emissions. As such, we have expanded the 
definition of a continuous monitoring system to allow systems beyond 
those that determine mass emission rate only by noting these systems 
must determine the ``mass emission rate or equivalent.'' The EPA also 
agrees with the commenter that the health checks of the system can be 
based on function rather than connectivity and that more flexibility in 
the transmission of data is appropriate. In the final rule we require 
data to be transmitted at least once every 24 hours.
    The EPA does not agree that additional flexibility in the downtime 
requirements is appropriate, even for remote locations. In order to 
demonstrate that a continuous monitoring system is equivalent to the 
required OGI/AVO monitoring for fugitive emissions component affected/
designated facilities, it is important for these systems to collect and 
analyze data with a limited amount of downtime. If the downtime is too 
great, we cannot ensure that the emissions reductions achieved by the 
alternative continuous monitoring method are equivalent to those from 
the work practice that has been determined to be BSER. If a continuous 
monitoring system cannot meet the operational downtime in the final 
rule and an owner or operator does not want to conduct surveys with OGI 
or EPA Method 21, the owner or operator may choose to use a continuous 
monitoring system that does meet the downtime requirement in the rule 
or may choose to use the alternative periodic screening option.
b. Detection Threshold
    Comment: Several commenters <SUP>285 286</SUP> did not agree with 
the requirement in the December 2022 Supplemental Proposal that 
continuous monitoring systems be capable of measuring emissions at an 
``order of magnitude'' lower than (i.e., 1/10 of) the proposed action 
levels. One commenter \287\ mentioned that this requirement is overly 
prescriptive and appears to be technology-specific rather than outcome-
based and technology-agnostic.
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    \285\ EPA-HQ-OAR-2021-0317-2235.
    \286\ EPA-HQ-OAR-2021-0317-2333.
    \287\ EPA-HQ-OAR-2021-0317-2336.
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    Response: The EPA agrees with the commenters and in the final rule 
requires a detection threshold of 0.40 kg/hr (0.88 lb/hr) above a 
baseline, which is based on one-third the action level. The 
requirements in the December 2022 Supplemental Proposal were based on 
the method detection limit requirements for alternative test methods in 
the fenceline monitoring program in the refinery rule.\288\ Requiring 
alternative measurement technologies used in the refinery fenceline 
monitoring program to measure an order of magnitude below the action 
level is appropriate because in that program, the difference between 
the high and low sample results during a measurement period are used to 
calculate the site's benzene concentration difference; therefore it is 
important to be able to differentiate the low-concentration 
measurements for benzene we expected around some refineries. In this 
final rule, the requirement for technology to be able to detect methane 
an order of magnitude below the action level is unnecessarily 
restrictive for real-time systems measuring methane mass emission 
rates, which may use concentration, meteorology, and modeling to 
calculate these rates, all of which have uncertainty built into the 
detection limit. Because these systems will be measuring a mass 
emission rate and not a concentration difference, it is less important 
to differentiate between the measurements across the site. It is only 
important that the technology be able to measure methane at background 
levels in order to be able to develop a site-specific baseline for 
methane, and methane is ubiquitous in the atmosphere at levels that 
should not present a concern for detection. For these reasons, we are 
requiring continuous monitoring alternative methane detection 
technologies to have a sensitivity of one-third of the lowest action 
level, 0.4 kg/hr (0.88 lb/hr). We note this requirement is also 
consistent with the EPA's approach for setting emission limits that are 
at least three times the representative detection limit. Such an 
approach ensures that the standard is at a level that addresses 
measurement variability and is in a range that can be measured with 
reasonable precision. Requiring the detection limit of continuous 
monitoring technologies to be at least one-third of the action level 
will ensure that measurements made near the action level are of 
reasonable precision.
---------------------------------------------------------------------------

    \288\ 40 CFR 63.658(k)(3).
---------------------------------------------------------------------------

c. Site-Specific Emissions Baseline
    Comment: Several commenters \289\ raised concerns over the long-
term 1.2 or 1.6 kg/hr action levels, because these emission rates are 
well below the baseline emissions for many sites. Other commenters 
<SUP>290 291</SUP> believed it critical that the follow-up response 
actions are tied not to detection limits but to action levels and that 
those action levels be levels that account for the site's baseline 
emission rates. One commenter \292\ noted that other regulated sources 
can contribute to substantial temporal variability in the baseline 
emission rate and provided the example of methane slip from gas-fired 
compressors, which can vary depending on compressor operating setpoints 
and maintenance. An additional commenter \293\ suggested that the 
concept of a baseline be used to establish an emissions profile and 
action levels be incremental to that baseline. The commenter further 
suggested that since the baseline is meant to capture normal emissions 
from the facility, while responses to the long-term and short-term 
action levels are meant to reduce fugitive emissions, the baseline 
period should be 90 days.
---------------------------------------------------------------------------

    \289\ EPA-HQ-OAR-2021-0317-2433.
    \290\ EPA-HQ-OAR-2021-0317-2346.
    \291\ EPA-HQ-OAR-2021-0317-2433.
    \292\ EPA-HQ-OAR-2021-0317-2333.
    \293\ EPA-HQ-OAR-2021-0317-2307.
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    Response: The EPA agrees that the action level should be 
incremental to the site-specific baseline emissions. In the final rule, 
we are revising the action level to be a mass emission rate that is 
above the site-specific baseline emissions. Based on the 
recommendations of the commenters, we are also establishing 
requirements for how and when the determination of the site-specific 
baseline is performed. The baseline emissions must be established after 
the initial installation of a continuous monitoring system or when 
there is a major change in the processing equipment at the site. The 
owner or operator must inspect and repair all fugitive components, 
covers, and closed vent systems and verify that control devices are in 
compliance with applicable requirements prior to starting the baseline 
determination period.
    The EPA disagrees with the suggested 90-day baseline period. We 
consider 30

[[Page 16914]]

days sufficient time to measure the variability of a site. Therefore, 
the baseline emissions are determined as the mean emission rate for 30 
operating days, minus any time periods where maintenance events are 
conducted. This site-specific baseline emission rate must be no more 
than 10 times the site's applicable 90-day action level (i.e., 16 kg/hr 
for well sites with major production and processing equipment 
(including small well sites), centralized production facilities, and 
compressor stations, or 12 kg/hr for wellhead only well sites).
d. Mass Emission Rate Reduction Plan
    Comment: One commenter \294\ mentioned that the December 2022 
Supplemental Proposal was not clear on how operators would deal with 
subsequent increases to the rolling average if corrective action had 
already been taken for the initial event.
---------------------------------------------------------------------------

    \294\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    Response: The EPA agrees with the commenter that the December 2022 
Supplemental Proposal was not clear on how to handle this situation. In 
the final rulemaking, owners and operators who conduct continuous 
monitoring with advanced methane detection technologies will initially 
(prior to conducting continuous monitoring) develop a site-specific 
baseline that accounts for normal process fluctuations. This site-
specific baseline will be subtracted from the monitored emissions when 
determining whether there is an exceedance of an action level. As such, 
the EPA anticipates that there should not be instances where the 
rolling average emissions continue to increase once the primary and 
underlying causes of the original exceedance of the action level is 
addressed.
3. Alternative Test Method
a. Administrator Delegation
    Comment: Several commenters \295\ expressed that the alternative 
test method approval process should enable expeditious and thorough 
review of advanced technologies. An additional commenter \296\ 
supported the EPA's proposal to allow operators to utilize the matrix 
to comply with CAA section 111(h)(l) and to approve alternative test 
methods under 40 CFR 60.8(b)(3), as this process enables operators to 
deploy technologies meeting the specifications of the matrix and 
encourages greater use of alternative technologies that can better 
detect emissions, resulting in greater emission reductions.
---------------------------------------------------------------------------

    \295\ EPA-HQ-OAR-2021-0317-2355.
    \296\ EPA-HQ-OAR-2021-0317-2342.
---------------------------------------------------------------------------

    Response: The EPA agrees that the alternative test method review 
process should be expeditious without sacrificing thoroughness. To that 
end, the EPA proposed a process for approving alternative test methods 
in 40 CFR 60.5398b(d), which is similar to the process in 40 CFR 
60.8(b)(3) but specifically tailored towards the types of advanced 
technologies that are in use or under development in the oil and 
natural gas sector.
b. Super-Emitter Technology
    Comment: The EPA received several comments <SUP>297 298</SUP> on 
the December 2022 Supplemental Proposal regarding the lack of criteria 
for remote sensing technologies used in the Super Emitter Program. One 
of these commenters believed these criteria should be based on the same 
proposed tenets as those for the advanced methane detection 
technologies, including detection limits based on a probability of 
detection curve and quantification accuracy. Another commenter stated 
that the EPA should use the alternative test method approval process to 
approve technologies for use in the Super Emitter Program. Another 
commenter \299\ maintained that third parties who are certified under 
the Super Emitter Program should not face a higher barrier to 
monitoring than operators themselves.
---------------------------------------------------------------------------

    \297\ EPA-HQ-OAR-2021-0317-2366.
    \298\ EPA-HQ-OAR-2021-0317-2483.
    \299\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA agrees with these comments. In this final rule, 
the EPA has included provisions to approve technologies used in the 
Super Emitter Program in 40 CFR 60.5398b(d), which are the same 
provisions that will be used to approve alternative methane detection 
technologies used by owners and operators. The EPA pre-approving the 
remote sensing technologies used by third parties under the Super 
Emitter Program will provide additional confidence in the data being 
provided by the third parties to the EPA, which will allow for 
expedited review of the data and help to ensure the data provided to 
the owner or operator is accurate and actionable.
c. Request for Alternative Test Methods
    Comment: One commenter \300\ requested we remove the requirement 
that an alternative test method, such as a continuous monitoring 
system, must be ``commercially available'' to be approved for use under 
the rule, as this unintendedly prevent in-house technology developed by 
an owner or operator from being used. Several commenters 
<SUP>301 302</SUP> requested that the EPA clarify the information 
companies must include in a request for an alternative test method. One 
commenter added that this clarification is necessary to support the 
EPA's ability to efficiently review and approve complete applications 
that demonstrate equivalent or better methane detection and reductions. 
Another commenter \303\ suggested that technology vendors include proof 
of results in their applications, including an accredited third party's 
validation, as they relate to detecting methane leak events, including 
field-proven evidence and technology validation accurately capturing 
events for a given range of detection and quantification thresholds. 
Several commenters requested that the EPA clarify what is meant by 
commercial availability of alternative leak detection technologies.
---------------------------------------------------------------------------

    \300\ EPA-HQ-OAR-2021-0317-2409.
    \301\ EPA-HQ-OAR-2021-0317-2348.
    \302\ EPA-HQ-OAR-2021-0317-2226.
    \303\ EPA-HQ-OAR-2021-0317-2340.
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    Response: Based on the comments received, in the final rule the EPA 
has changed the term describing the alternative technology from 
``commercially available'' to ``readily available.'' We have also 
provided clarification that readily available technology includes 
equipment or technology developed by an owner or operator for internal 
use and/or use by external partners. The EPA has also clarified the 
information that must be included in a request for an alternative test 
method for advanced methane detection technology. In the final rule, 
the request for an alternative test method must include contact 
information, description of the measurement technology, scientific 
theory of the measurement, potential limitations, how the measurement 
is translated to a mass emission rate, detailed workflow, information 
on any models used, a-priori methods, how all data are collected and 
transformed from measurement to end user, supporting information 
verifying that the technology meets the claimed detection threshold(s) 
as applied in the field, including published reports produced by the 
candidate or outside entity, standard operating procedures, formal 
alternative test method procedures, and information on the spatial 
resolution of the measurement technology. Requests for an alternative 
test method for advanced methane detection technology must be submitted 
to the EPA through the alternative methane detection

[[Page 16915]]

technology portal at https://www.epa.gov/emc/oil-and-gas-alternative-test-methods.

C. Super Emitter Program

    In the December 2022 Supplemental Proposal we proposed the Super 
Emitter Program to establish a pathway by which an EPA-certified entity 
(i.e., third-party notifier) may provide credible, well-documented 
identification of a super-emitter emissions event using one of several 
permitted remote-sensing technologies and approaches to the responsible 
owner or operator. Once notified of the event at a site they own or 
operate, owners and operators would be required to perform a root cause 
analysis to identify the source of the super-emitter event and take 
corrective actions to address the emissions source. As described in 
this section, the EPA received comments on the following aspects of the 
Super Emitter Program: (1) Statutory authority for the program, (2) 
remote sensing methane detection technology, (3) certification of third 
parties, (4) notifications by third parties, and (5) requirements for 
owners and operators. In response to these comments, the EPA has made 
targeted changes to the Super Emitter Program, which are described in 
detail in section X.C of this document.
    Provided in this section are some of the significant comments on 
the proposed program and the EPA's response thereto. For other comments 
on the proposed program and the EPA's response thereto, see chapter 14 
of the RTC document, Super Emitter Program.\304\
---------------------------------------------------------------------------

    \304\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

1. Statutory Authority
    In the December 2022 Supplemental Proposal, the EPA had proposed 
for comment two legal frameworks in support of the Super Emitter 
Program (87 FR 74752). Under the first legal framework, the EPA would 
treat a super-emitter event as a separate and distinct affected 
facility under NSPS OOOOb (or a designated facility under EG OOOOc), 
and the proposed BSER for this affected facility/designated facility 
was the requirement that an owner or operator, upon receiving a notice 
of a super-emitter event from an EPA-certified third party, must take 
action to identify and address the source of the super-emitter event. 
Under the second legal framework, the Super Emitter Program functioned 
as an additional compliance assurance measure for affected facilities/
designated facilities subject to numeric performance standards. Under 
that second framework, for fugitive emissions component affected 
facilities/designated facilities, the Super Emitter Program was 
proposed as part of the BSER for the fugitive emissions standard at 
well sites and compressor stations, which would include a requirement 
to repair components that have been identified as the source of a 
super-emitter event. As discussed below, in response to the comments on 
both legal frameworks, the EPA has revised the Super Emitter Program 
since the December 2022 Supplemental Proposal. The final Super Emitter 
Program, which the EPA is establishing pursuant to the authorities 
provided by CAA sections 111 and 114(a), is based on the second legal 
framework; however, as revised, it will be the EPA, not a third party, 
that will notify owners and operators of super-emitter events, and such 
notification will be based on data submitted by EPA-certified third 
parties using EPA-approved detection technology, and will be issued 
only after the EPA has reviewed the data and deemed it to be complete 
and accurate. In addition to the responses to comments below, please 
also see section X.C of the preamble for a more detailed discussion of 
the legal frame for the final Super Emitter Program.
    Comment: A number of commenters question the legality of the first 
proposed legal framework, which defines a super-emitter event as an 
affected facility/designated facility. One commenter \305\ notes that 
the EPA may only regulate two types of sources under CAA section 111(b) 
and (d): new sources (including modified sources) and existing sources; 
however, a super-emitter source is created by an event, not 
construction or modification, and therefore is neither a new nor 
existing source under CAA section 111. Another commenter \306\ 
similarly questions the legality of a super-emitter affected facility/
designated facility, noting that it is created by a third-party 
notification and could not be said to exist prior to such notification.
---------------------------------------------------------------------------

    \305\ EPA-HQ-OAR-2021-0317-2398.
    \306\ EPA-HQ-OAR-2021-0317-2202.
---------------------------------------------------------------------------

    Response: Because the EPA is finalizing the program based on the 
second legal framework, the legal concerns raised by these commenters 
regarding the creation of a new super-emitter affected/designated 
facility under the first legal frame are now moot.
    Comment: One commenter \307\ states that the EPA's focus on 
compliance assurance fits particularly well with the goals of the 
program and with the problem of super-emitters. Emissions events 
exceeding 100 kg/hr indicate major problems at the site resulting from 
either noncompliance or serious operational issues. The commenter 
stated that the EPA has broad authority under CAA section 114 to accept 
and use third-party monitoring data for purposes related to CAA section 
111, including ensuring compliance. The commenter asserted that the 
Super Emitter Program does not and should not replace obligations on 
the part of owners and operators to reduce methane emissions from 
affected and designated facilities under the rules. Rather, the 
commenter views the Super Emitter Program as an additional backstop to 
ensure that the unique problems posed by super-emitters are timely 
addressed.
---------------------------------------------------------------------------

    \307\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Another commenter,\308\ however, states that the proposed Super 
Emitter Program is not lawful. According to the commenter, Congress did 
not under the CAA to convey to the EPA the authority to delegate the 
monitoring of regulated facilities to third[hyphen]party members of the 
public for use by the EPA for compliance, supervision and enforcement. 
The commenter claims that, in effect, the EPA would be delegating to 
groups with unverified qualifications and technical expertise, 
according to the commenter an unprecedented action. The commenter 
claims that this provision of the proposed rules is also a violation of 
the separation of powers of the U.S. Constitution where the EPA is 
seeking to legislate and grant legal authority to itself to delegate 
regulatory authority to third[hyphen]party members of the public to 
monitor and report on regulated facilities, a legislative act that 
resides solely with Congress.
---------------------------------------------------------------------------

    \308\ EPA-HQ-OAR-2021-0317-2227.
---------------------------------------------------------------------------

    Other commenters \309\ similarly observe that the program as 
proposed would be the first time that the EPA has asserted authority 
under the CAA to create regulatory obligations for affected facilities 
based on monitoring conducted by unaffiliated third parties and without 
playing any role at all in verifying the information before imposing 
legal obligations on other private parties. In support of this unusual 
delegation of regulatory authority, these commenters asserted, the EPA 
characterizes the program as

[[Page 16916]]

simply a BSER requiring monitoring and correction of unintentional 
releases, akin to LDAR,\310\ but evades the central concern that it is 
private parties--not the EPA, states, or regulated entities--who would 
be monitoring, notifying, and triggering the associated regulatory 
obligations.
---------------------------------------------------------------------------

    \309\ EPA-HQ-OAR-2021-0317-2301, -2483.
    \310\ Id. at 74752 (``[T]he 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.'').
---------------------------------------------------------------------------

    Another commenter \311\ agrees with the EPA on the importance of 
identifying and addressing large emissions events. The commenter 
acknowledges that emissions from such events have the potential to be 
much greater than those from normal operations at a given facility and 
shares the EPA's interest in seeking to reduce the incidence of such 
large emissions events. However, like other commenters mentioned above, 
this commenter similarly observed that the proposed program was unique 
in that it would be the first time under the CAA that the EPA asserts 
authority to create regulatory obligations for affected facilities 
based on monitoring conducted by unaffiliated third parties. Claiming 
that the EPA did not explain the legal basis for establishing such a 
requirement, the commenter states that an explanation from the EPA is 
essential to understanding whether such a novel provision is legally 
viable.
---------------------------------------------------------------------------

    \311\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: In light of the comments above and discussed elsewhere in 
this section regarding other aspects of the proposed Super Emitter 
Program, the EPA has made targeted revisions to the Super Emitter 
Program since the December 2022 Supplemental Proposal. The final Super 
Emitter Program, which the EPA is establishing pursuant to CAA sections 
111 and 114(a), is based on the second proposed legal framework.\312\ 
First, as one commenter observes, the EPA has broad authority under CAA 
section 114(a) to accept and use third-party monitoring data for 
purposes related to CAA section 111, including better understanding the 
sources of large emitting events and assuring compliance with its 
regulations. CAA 111(a) authorizes the EPA to obtain any information 
necessary for the implementation of the CAA from any person ``the EPA 
believes may have information necessary for the purposes of 
[implementing the CAA].'' While the Super Emitter Program does not 
specifically require or request any third party to provide information 
on super-emitter events to the EPA, anyone can voluntarily provide such 
information to the EPA. It is the EPA's long-standing position that 
``information will be considered to have been provided . . . under 
section 114 of the Act . . . if its submission could have been required 
under section 114. . . .'' 40 CFR 2.301(b)(2). Also, as discussed in 
detail in section X.C and further below, CAA 114(a) authorizes the EPA 
to require the owners and operators of the source of the super-emitter 
event to investigate and report the conclusions of that investigation 
to the EPA. As explained below, the final Super Emitter Program 
requires such actions from owners and operators upon their receipt of 
an EPA notice of a super-emitter event based on data submitted by EPA-
certified third parties using EPA-approved technology. The EPA will 
send such notices only after having reviewed and deemed the data to be 
complete and accurate.
---------------------------------------------------------------------------

    \312\ Please see X.C of the preamble for a detailed discussion 
on this legal framework.
---------------------------------------------------------------------------

    Second, for super-emitter events caused by regulated sources, the 
EPA has separate authority under CAA section 111 to ensure compliance 
with its regulations where a notification and subsequent investigation 
reveal noncompliance with those regulations. Much of the equipment 
likely to cause a super-emitter event is or will be subject to 
regulation under CAA section 111 (i.e., NSPS OOOO, OOOOa, OOOOb, or 
state/Federal plans pursuant to EG OOOOc). For example, a super-emitter 
event might be caused by a regulated thief hatch that is open despite 
the EPA's requirement that thief hatches remain closed. In these cases, 
the Super Emitter Program serves an additional compliance assurance 
measure for the regulated equipment by notifying owners and operators 
of data demonstrating super-emitter events and requiring that they 
investigate and identify the source of the super-emitter event. 
Specifically, the Super Emitter Program serves as additional monitoring 
to inform and aid owners and operators in complying with the relevant 
NSPS or standards in state and Federal plans. Further, the EPA proposed 
and is finalizing the requirement under its fugitive emissions 
standards that where the source of the super-emitter event was a 
fugitive emissions component under NSPS OOOOb or a state or Federal 
Plan implementing EG OOOOc, the owner and operator must follow the 
repair requirements in the fugitive emissions work practice standards 
in NSPS OOOOb or the applicable state or Federal plan. As explained in 
the December 2022 Supplemental Proposal, the EPA considered this as 
part of the BSER for fugitive emissions at well sites and compressor 
stations.
    In response to comments questioning the legality of allowing third 
party monitoring and notifications to directly trigger regulatory 
obligations, the EPA has revised the proposed program such that the EPA 
will play an essential oversight role in the final Super Emitter 
Program. Specifically, it will be the EPA, not third parties, that will 
notify owners and operators of super-emitter events after reviewing 
third-party notifications. Further, the EPA will only accept data 
submitted by EPA-certified third parties and collected using EPA-
approved technologies. Upon receiving data submitted by a certified 
third party, the EPA will review the data for completeness and 
accuracy; the EPA will post such data and notify the identified owner 
or operator only after it has reviewed and deemed the information to be 
complete and accurate. Accordingly, the EPA plays a central role at 
every step: certifying (and de-certifying) the third parties who will 
be able to submit notifications under this program, approving the 
technology such parties may use, reviewing the notifications to ensure 
the information therein is accurate and complete, notifying owners and 
operators of such information, receiving and reviewing responses from 
owners and operators, and determining when to post information and 
responses publicly.
    The final Super Emitter Program sets forth criteria that a third 
party must meet in order to be certified to submit data on super-
emitter events to the EPA. These criteria ensure that the data 
submitted to the EPA are collected by a qualified third party with 
access to an EPA-approved technology and the technical expertise and 
capability to use such technology to detect and collect data on super-
emitter events. The final rule also lists circumstances under which a 
third-party certification will be revoked, such as repeated submissions 
of data with significant errors, or engagement in an unlawful action 
(e.g., trespass) when monitoring for super-emitter events.
    Upon receiving data submitted by a certified third-party, the EPA 
will review the data for completeness and accuracy; the EPA will post 
such data and notify the identified owner or operator only after it has 
reviewed and deemed the information to be complete and accurate.
    As finalized, the Super Emitter Program does not ``delegate'' any 
regulatory or enforcement role to third

[[Page 16917]]

parties. Rather, the Super Emitter Program merely serves as a mechanism 
for the EPA to receive reliable data on super-emitter events from 
qualified third parties with access to and expertise in using EPA-
approved advanced technology to detect super-emitter events. The Super 
Emitter Program also provides a structured process for the EPA to use 
that data to notify the owner or operator of a regulated facility of 
the existence of a super-emitter event that may indicate a lapse in 
compliance at the facility, or a source of fugitive emissions that this 
rule requires to be promptly repaired. There is no sense in which this 
framework ``delegates'' governmental authority of any kind to any third 
party. No action is required of an owner or operator solely on the 
basis of an action of a third party. In addition, the process by which 
the EPA receives data and issues notifications under the Super Emitter 
Program is separate from and unrelated to the EPA's enforcement 
functions.
    This structure, where the EPA reviews and determines the 
reliability of reported data on super-emitter events, is similar to 
other, longstanding programs where citizens and other entities can 
report concerns about regulatory compliance to the Agency. For example, 
the EPA's Office of Enforcement and Compliance Assurance administers a 
program where citizens and other entities can report suspected 
environmental violations. See https://echo.epa.gov/report-
environmental-violations#:~:text=Stop-,Stop,%2D800%2D424%2D8802. The 
Super Emitter program likewise functions to allow third parties to 
share with the EPA monitoring data, and then allows the EPA to 
determine the reliability of the data, and engage with the relevant, 
regulated party to determine if there is a need for further action to 
ensure compliance with the EPA's regulations. The third parties 
reporting super-emitter events do not have an independent enforcement 
role as a function of the Super Emitter Program. Instead, the EPA 
retains its traditional enforcement authority.
    As explained in the December 2022 Supplemental Proposal (87 FR 
74752) and noted by one commenter,\313\ the Super Emitter Program 
serves as a backstop to addressing emissions from super-emitter events 
that were not prevented from other requirements in the rule. However, 
the EPA did not propose and does not require in the final program any 
specific investigation to be conducted to identify the source of the 
super-emitter event. Because the relevant investigations for 
identifying the source(s) of the super-emitter event may vary depending 
on what the third-party data reveals, the final rule defers to the 
owner and operator in deciding the appropriate investigation(s). 
However, where there are NSPS affected facilities (or designated 
facilities subject to a state or Federal plan implementing EG OOOOc) or 
associated equipment onsite, the owner and operator may conclude that 
they are unable to identify the source of the super-emitter event only 
after having conducted the applicable investigation listed in the final 
rule for such regulated source.
---------------------------------------------------------------------------

    \313\ EPA-HQ-OAR-2021-0317-2433.
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    The EPA further notes that the obligation to investigate and report 
the source of super-emitter events (separate and apart from the 
obligation to take steps to address the super-emitting event) is not 
limited to NSPS affected facilities (or designated facilities subject 
to a state or Federal plan implementing EG OOOOc) and associated 
equipment; it also extends to other equipment onsite that an owner and 
operator suspects could be the source of a super-emitter event. As one 
commenter observes, the EPA has broad authority to require emissions 
reporting under CAA section 114(a). Among other things, CAA section 
114(a) authorizes the EPA to require ``any person who owns or operates 
any emission source'' (except mobile sources) \314\ to provide 
information necessary for purposes of carrying out the CAA. In this 
case, section 114(a) authorizes the EPA to require the reporting of 
information on super-emitter events, so that the EPA may evaluate 
whether such large emissions can be adequately addressed under the EPA 
regulations to date or whether more needs to be done in the future 
(e.g., during the next periodic review of the NSPS under CAA section 
111). Therefore, the EPA expects the owner and operator to investigate 
all equipment onsite that they suspect could be the source of a super-
emitter event, whether or not such equipment is subject to NSPS 
regulation or a state or Federal Plan implementing EG OOOOc. Where the 
super-emitter event was caused by equipment not subject to NSPS OOOO, 
OOOOa, or OOOOb, or a state or Federal plan implementing EG OOOOc, the 
owner and operator must report such finding. However, there is no 
requirement for the owner or operator to take action to eliminate or 
mitigate the emissions from the super-emitter event caused by sources 
not subject to an NSPS or a state or Federal plan implementing EG 
OOOOc.
---------------------------------------------------------------------------

    \314\ The EPA has similar information collection authority with 
respect to mobile sources under CAA section 208.
---------------------------------------------------------------------------

    While there are comments expressing concerns with the proposed 
program as described above, the EPA received comments expressing strong 
support for the program from several states,<SUP>315 316</SUP> 
environmental groups \317\ and industry.<SUP>318 319</SUP> One industry 
commenter concurs with the EPA on the importance of identifying and 
addressing large emissions events and shares the EPA's interest in 
seeking to reduce the incidence of such large emissions events. The 
commenter also agrees with the EPA that data transparency is valuable 
and shares the EPA's goal of disseminating information to mitigate 
emissions events. The EPA believes that the final Super Emitter 
Program, which has been significantly revised in response to comments, 
will serve its goal of reducing emissions from super-emitter events 
that were not prevented by other requirements in the rule.
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    \315\ EPA-HQ-OAR-2021-0317-2296.
    \316\ EPA-HQ-OAR-2021-0317-2422.
    \317\ EPA-HQ-OAR-2021-0317-2433.
    \318\ EPA-HQ-OAR-2021-0317-2428.
    \319\ EPA-HQ-OAR-2021-0317-2499.
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2. Certification of Third Party
    This section of this document presents a summary of significant 
comments received on certification of third-party notifiers as part of 
the Super Emitter Program and the EPA's response to those comments, as 
well as changes the EPA has made to the requirements since the December 
2022 Supplemental Proposal.
    The EPA received many comments regarding how advanced methane 
detection technology has been incorporated into our proposed standards, 
including the lack of clarity on which remote sensing technology would 
be considered for the program, how the remote sensing technology could 
be considered for the program, what an approval process could look 
like, and how best to make this program transparent.
    Comment: Several commenters <SUP>320 321</SUP> expressed concern 
with the lack of standard methods for the example technologies that the 
EPA identified in the proposed rule as compared to test method 
requirements (i.e., validated test methods) that underpin compliance 
determinations for NSPS or national emissions standards for hazardous 
air pollutants (NESHAP) standards. One of these commenters suggested 
that the proposed programmatic requirements (i.e., alternative test 
methods) be

[[Page 16918]]

applied to the Super Emitter Program. Another of these commenters 
recommended that the EPA develop guidance on test and monitoring 
methods to use to define super-emitter emissions events.
---------------------------------------------------------------------------

    \320\ EPA-HQ-OAR-2021-0317-2366.
    \321\ EPA-HQ-OAR-2021-0317-2483.
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    Several commenters <SUP>322 323</SUP> urged the EPA to not overly 
restrict the technologies that may qualify and suggested that the EPA 
should use the alternative test method approval process already under 
development to approve advanced methane detection technologies for 
monitoring fugitive components, covers, and closed vent systems in this 
rule for use in the Super Emitter Program. One of these commenters 
provided that such an approach could allow for additional technologies 
that could operate within the requirements of this program. Another 
commenter urged the EPA to use the already proposed alternative test 
method to remove any potential barriers on the third party to evaluate 
technology and to bring the measurement to the same level as that of 
the owner or operators while improving objectivity.
---------------------------------------------------------------------------

    \322\ EPA-HQ-OAR-2021-0317-2410.
    \323\ EPA-HQ-OAR-2021-0317-2394.
---------------------------------------------------------------------------

    Some commenters <SUP>324 325</SUP> raised safety concerns regarding 
individuals engaged in third-party monitoring. One of these commenters 
raised concerns that certain monitoring technologies used by third 
parties to identify super-emitter emissions events that need to be 
operated in the close vicinity of a site, and that individuals 
conducting that monitoring may not be aware of important safety 
concerns regarding that site. Another one of these commenters provided 
examples of such safety concerns associated with members of the public 
accessing sites without proper notice. For example, some sites can 
contain hydrogen sulfide (H<INF>2</INF>S), a gas that could result in 
serious health impacts for members of the public entering a site 
without proper protection. The commenters raised concerns that 
individuals may not be aware of such hazards or have the appropriate 
personal protection equipment (PPE) and training to mitigate them.
---------------------------------------------------------------------------

    \324\ EPA-HQ-OAR-2021-0317-2326.
    \325\ EPA-HQ-OAR-2021-0317-2360.
---------------------------------------------------------------------------

    Response: Regarding the comments on the use of remote sensing 
technology and the lack of approved or validated methods for use in the 
Super Emitter Program, we agree with the commenters that the remote-
measurement approaches used for this program should be evaluated in the 
same manner as any compliance measurement used in this rule. The EPA 
also agrees with the commenters' recommendations that we use the 
alternative test method approval process already under development to 
approve advanced methane detection technologies for monitoring fugitive 
components, covers, and closed vent systems in this rule. Therefore, in 
the final rule we are requiring that third parties participating in the 
Super Emitter Program use an alternative test method that has been 
approved under 40 CFR 60.5398b(d) of the final rule and we have revised 
the scope of the alternative test method program to now include the 
approvals for the Super Emitter Program.
    Comment: Several commenters <SUP>326 327</SUP> ask that the EPA 
clarify its intent as to which advanced methane detection technologies 
can be utilized for the Super Emitter Program. Several commenters 
<SUP>328 329</SUP> maintained that the EPA must provide a clear pathway 
for communities and third parties to participate and engage in the 
Super Emitter Program. They also said that the EPA must ensure that 
data from approved monitoring technologies are accessible to all, 
including by allowing the use of OGI cameras in this program. These 
commenters urged the EPA to expand what they characterized as the 
overly restrictive technology standards proposed for the Super Emitter 
Program, which would currently work to limit the participation of NGOs 
and communities that lack access to remote detection technologies.
---------------------------------------------------------------------------

    \326\ EPA-HQ-OAR-2021-0317-2249.
    \327\ EPA-HQ-OAR-2021-0317-2410.
    \328\ EPA-HQ-OAR-2021-0317-2394.
    \329\ EPA-HQ-OAR-2021-0317-2410.
---------------------------------------------------------------------------

    Response: In the December 2022 Supplemental Proposal, the EPA 
identified satellites, aircraft, and other mobile monitoring 
measurement systems that can quantify an emission rate of 100 kg/hr of 
methane or greater. These examples were intended to make clear that 
third parties would only use technology that could be used at a 
reasonably safe distance, well away from a well site, central tank 
battery, or compression station, to ensure the integrity of these sites 
and the safety of the individuals or organizations collecting the 
measurements. Nothing in this rule should be construed as authorizing 
third parties to enter well sites or any other affected facility or 
designated facility to take measurements. Also, we recognize that 
mobile monitoring platforms could be interpreted broadly; this language 
is the EPA's effort to account for the continuing advancement of 
methane detection technology, and the qualification to meet the mobile 
monitoring platform is that we would allow any un-fixed measurement 
technology operating offsite from a well site, central tank battery, or 
compression station that can quantify an emission rate of 100 kg/hr of 
methane or greater. For the final rule, the EPA is maintaining the 
proposed criteria regarding which measurement technologies can be used 
in the Super Emitter Program. While the minimum threshold remains 100 
kg/hr, the EPA would consider the use of remote technologies with 
higher detection thresholds in this program. However, those 
technologies would be limited to reporting emissions events above their 
detection threshold.
    Lastly, we acknowledge the desire of certain third-party groups to 
use OGI as part of this program. However, the current generation of 
this technology does not have the quantification ability required as 
part of this rule. More importantly, this technology cannot be operated 
at a distance and creates more potential for users getting too close to 
the site and creating risks to themselves or to the site. We recognize 
that a number of the technology vendors focusing on OGI are developing 
systems capable of quantification, and as these systems come online, 
this determination may change if there is a mechanism to ensure that 
the monitoring is only done at a reasonable and safe distance away from 
an applicable well site, central tank battery, or compression station.
    The EPA further notes that direct monitoring is not the only way 
that communities can participate in or benefit from the Super Emitter 
Program. The EPA anticipates that a broad range of entities, including 
community organizations that are not themselves certified, might 
partner with a certified third party to identify locations of 
particular concern for monitoring attention. The EPA will also be 
posting the super-emitter event data shortly after it is received, 
which provides communities with information that could be relevant to 
local health and air quality, and could also be useful to communities 
seeking to advocate on their own behalf.
    Comment: Several commenters <SUP>330 331</SUP> raised concerns that 
the December 2022 Supplemental Proposal offered little clarity about 
the necessary demonstrated expertise for third parties. Many of these 
commenters also stated that the EPA should develop detailed criteria 
for the certification of these third-party notifiers. Furthermore,

[[Page 16919]]

according to another commenter,\332\ the Agency should make transparent 
and publicly disclose what other qualified parties have been certified. 
Some commenters raised a concern that some third-party notifiers may be 
inadequately trained to detect methane leaks; these same commenters 
recommended that third-party notifiers be required to have appropriate 
training/certification to validate emissions events. Another commenter 
stated that a third party must complete an approval certification 
process by the EPA for inclusion in the Super Emitter Program; also 
this commenter suggested that third parties notify the EPA of planned 
monitoring, including submittal of a monitoring plan.
---------------------------------------------------------------------------

    \330\ EPA-HQ-OAR-2021-0317-2399.
    \331\ EPA-HQ-OAR-2021-0317-2403.
    \332\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    One commenter \333\ questioned how effectively a third party would 
be able to identify an owner or operator of a site or be able to 
contact the right people if the facility is covered by NSPS OOOOb. The 
same commenter mentioned the importance for notifications to be sent to 
the correct person at the operating company. Another commenter \334\ 
agreed that the qualifications of third-party reporters are important 
and that approved third-party reporters should show proficiency and 
accuracy in identifying super-emitter leaks.
---------------------------------------------------------------------------

    \333\ EPA-HQ-OAR-2021-0317-2406.
    \334\ EPA-HQ-OAR-2021-0317-2216.
---------------------------------------------------------------------------

    Several commenters <SUP>335 336</SUP> provided recommendations on 
how to improve the process for revoking certifications for third 
parties. A few of these commenters argue that the three-time threshold 
for inaccurate event notifications from a third party is too high and 
should not be limited to multiple notifications at the same facility 
owned by the same operator. Another commenter \337\ recommended that 
the criteria for revocation explicitly state that revocation would 
occur upon a third party's third submission of verifiably false data 
from any combination of operators or sites, or upon trespass or 
otherwise unlawful or unauthorized entry to a facility.
---------------------------------------------------------------------------

    \335\ EPA-HQ-OAR-2021-0317-2428.
    \336\ EPA-HQ-OAR-2021-0317-2168.
    \337\ EPA-HQ-OAR-2021-0317-2446.
---------------------------------------------------------------------------

    Response: The EPA agrees with the commenters that the final rule 
should more completely define the certification process and criteria 
these third parties must meet. Therefore, in the final rule we have 
amended the regulatory text to include the procedures an entity must 
follow when seeking certification, what information they must submit to 
the EPA as part of this certification process, and a set of standards 
an approved third-party notifier must continue to follow.
    The final rule now provides direction for any entity requesting 
certification to be a third-party notifier to submit the required 
information to the Leader, Measurement Technology Group, Mail Drop: 
E143-02, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle 
Park, NC 27711. The required submission information includes general 
information on the organization requesting the certification, 
qualifications for the certifying official, which measurement 
technologies will be used, standard operating procedures for data 
review, records management processes, and a Quality Management plan. 
The required information is not intended to be onerous, however these 
basic requirements are consistent with the EPA's internal data review 
process and are in place to ensure that notifications being provided to 
the EPA are actionable and accurate. We are also requiring third-party 
notifiers to maintain the relevant records from surveys conducted or 
sponsored by the third party, including data used to evaluate the 
validity of a super-emitter event but which is not required to be 
submitted as part of the notification.
    In addition, the final rule defines the Administrator's authority 
to approve or disapprove certifications as a third-party notifier, 
clarifies when third parties must be certified, and provides greater 
detail on the process to revoke certifications. The EPA agrees with 
commenters' points that the program should be run transparently, and 
the identification of all certified third-party notifiers shall be 
posted on the EPA website at https://www.epa.gov/emc-third-party-approvals with a corresponding third-party notifier ID. The EPA 
disagrees with the comment that third parties must be recertified at a 
specific frequency; instead, the final rule requires third parties to 
amend their certification (i.e., recertification) to account for any 
significant changes in their technology or other elements of their 
certification. The EPA considers it important to require third parties 
to amend their certification to account for the advancement in the 
methane detection technology and will structure the program to quickly 
evaluate these amendments.
    Finally, the EPA agrees with the commenters that the Agency should 
expand the circumstances in which a third party can be removed from the 
list of approved notifiers. With the EPA's central role in handling 
super-emitter notifications, we have expanded the circumstances to 
include removal of a third party that has made material changes to 
their process without amending their certification, if a certified 
third-party notifier has repeatedly submitted data with significant 
errors, or if the third-party notifier engages in an illegal activity 
during the assessment of a super-emitter event (e.g., trespassing). We 
are also finalizing the proposed provision that the Administrator 
revoke a certification upon receiving a petition from an owner or 
operator documenting that it has received three or more notices with 
materially erroneous information on a super-emitter event at the same 
well site, centralized production facility, or compressor station, 
submitted to the EPA by the same third-party notifier. Since the 2022 
Supplemental Proposal, the EPA has improved the robustness of the Super 
Emitter Program by establishing specific and detailed criteria to 
ensure the qualifications of third parties who can be certified and the 
quality and accuracy of the data that the EPA will accept from the 
certified third parties; further, the EPA will review the submitted 
data for completeness and accuracy before issuing any notice of a 
super-emitter event to an identified owner or operator. The EPA 
believes that these safeguards will minimize, if not eliminate, 
issuance of clearly erroneous notices; however, there may be errors in 
the submitted information that cannot be readily discerned by the 
third-party notifier or the EPA, at least not without more time, which 
would undermine the Program's objective to provide owners and operators 
timely information to identify and address super-emitter events. In 
light of the above, the EPA believes that revoking a third-party's 
certification after three times of submitting data with material errors 
on the same facility is an appropriate balance between providing owners 
and operators timely notifications of super-emitter events at their 
facilities and minimizing the likelihood and therefore burden of owners 
and operators having to respond to notices with material erroneous 
information.
3. Notifications by the Third Party and Requirements
    We received several comments on ways to improve the notification 
process in the Super Emitter Program. This section of this document 
presents a summary of significant comments received on the handling of 
notifications and the EPA's response to those comments, as well as 
changes the EPA has made to account for those comments, including a 
central role for the EPA in collecting and reviewing

[[Page 16920]]

third-party reports of super-emitter events and providing 
notifications.
    Comment: Several commenters <SUP>338 339</SUP> expressed that 
super-emitter data should be published by the EPA and that the EPA 
should manage all data that is to be public and establish a protocol 
for when and what types of specific details of a potential super-
emitter emissions event are published. Another commenter suggested that 
the EPA should maintain a public database of all super-emitter 
notifications by certified third-party reporters. Still another 
commenter strongly disagreed that the EPA should promptly make such 
reports available to the public online and recommended that the EPA 
should provide time to verify or authenticate the information from 
third parties and allow owners or operators to review and respond to 
the information.
---------------------------------------------------------------------------

    \338\ EPA-HQ-OAR-2021-0317-2409.
    \339\ EPA-HQ-OAR-2021-0317-2399.
---------------------------------------------------------------------------

    Several commenters \340\ stated that notifiers should be required 
to provide proof of the event such as time, date, location, and visual 
evidence of leak origin. One commenter \341\ said that the EPA should 
show discretion in accepting information provided by third parties as 
proof that a super-emitter exists, including quantification of the 
super-emitter. Still other commenters \342\ were concerned that the 
notifications are based on a snapshot in time, which they asserted was 
not sufficient, and that the EPA should establish criteria for the 
third party to demonstrate that excessive rates of methane are 
occurring for an extended period of time.
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    \340\ EPA-HQ-OAR-2021-0317-2453.
    \341\ EPA-HQ-OAR-2021-0317-2399.
    \342\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------

    Several commenters <SUP>343 344 345</SUP> expressed concern that 
the December 2022 Supplemental Proposal did not state the amount of 
time required for notifications following the detection of a super-
emitter. Many of these commenters discussed how the time required may 
be dependent on the type of remote sensing technology, the ability to 
identify the relevant operator, and the capabilities of the third-party 
notifier. In these individuals' comments, the commenters provided a 
range of potential suggested requirements for providing notifications, 
from 1 day to a few weeks. Some of these commenters identified that 
timely notification would lead to earlier mitigation, but more 
importantly that some of these super-emitter events are intermittent 
and investigation into their cause is more effectively performed closer 
to the event and would aid in prevention. An additional commenter \346\ 
raised concern that information received several months after a 
detection will likely be challenging for operators to utilize 
effectively.
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    \343\ EPA-HQ-OAR-2021-0317-2202.
    \344\ EPA-HQ-OAR-2021-0317-2301.
    \345\ EPA-HQ-OAR-2021-0317-2409.
    \346\ EPA-HQ-OAR-2021-0317-2221.
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    Finally, one commenter \347\ suggested that third parties should 
attest that the notifier is an EPA-approved entity for providing the 
notification and that the information was collected and interpreted as 
described in the notification. The commenter went on to explain that a 
signed certification provides fidelity to the requirement that the 
information is coming from a verified source. The commenter believes 
that this can be in the form of a weblink that traces back to the EPA's 
website hosting the list of third-party notifiers.
---------------------------------------------------------------------------

    \347\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA agrees that the program will be more effective 
with the EPA in a centralized role to accept and review third-party 
submittals and make the notifications to an owner or operator in a 
timely manner, and so we are revising the final rule to include a 
substantial oversight role for the EPA. The EPA also agrees with those 
commenters who assert that it is important that these data should be 
public, and to address these comments, the EPA is developing a Super 
Emitter Program Portal to be found at the following URL, https://www.epa.gov/super-emitter. The Portal will serve to manage the data 
associated with the Super Emitter Program, including data coming into 
the system from EPA-certified third parties, providing notifications 
from the EPA to affected owners or operators, responses back from the 
owner or operators, and display of the super-emitter data. This portal 
and the underlying data management system from which it is built will 
allow the EPA to quickly review incoming data for accuracy and 
completeness, allowing for timely notification of verified data to 
owner or operators.
    The EPA does not agree with the commenters that verified data 
should not be public until such time that an owner or operator has a 
chance to review and respond to the information, and the EPA believes 
it is important that this program is operated transparently. However, 
the EPA is conscious of these commenters' concerns that many of the oil 
and gas basins are dense with sites and that uncertainty in the spatial 
resolution of some of the remote sensing platforms may make correct 
identification of the owner or operator challenging. Therefore, the EPA 
will not identify the attribution of the super-emitter source until the 
notified owner or operator of a site has the opportunity to respond; 
this will be further discussed later in this section.
    The EPA agrees with those commenters that the third-party notifiers 
must be able to provide proof of a super-emitter event and therefore 
the final rule has defined the information that must be submitted by 
the third party into the Super Emitter Program Portal. Only those 
individuals and organizations that have been certified will be able to 
access the notification portion of the portal. The required information 
that must be supplied with the notification are the: third-party 
notifier ID; date of detection of the super-emitter event; location in 
latitude and longitude; owner, or operator of a well site within 50 
meters of the identified latitude and longitude, if available; 
detection technology used; documentation (e.g., imagery) of the super-
emitter event and from which it is detected; quantified emission rate; 
and associated uncertainties. The EPA also agrees with those commenters 
that the EPA super-emitter data must be supplied in a timely manner and 
therefore in this final rule we are requiring that notifications must 
be supplied to the EPA within 15 days after the detection event; we 
believe this is a reasonable amount of time within which to acquire the 
data, verify the data, and identify an owner or operator, consistent 
with the importance of quick notification. In the final rule, to ensure 
that the EPA is providing actionable information to the owners or 
operators, the EPA will not review and/or provide any notifications to 
an owner or operator unless the third-party notification is received 
within 15 days after detection of the super-emitter event. Furthermore, 
the EPA agrees that a third party must attest to the accuracy of their 
notification and in the final rule we now include an attestation 
statement to be signed by the certifying official.
    Information that is received within 15 days after detection and is 
attested, complete, and found to be accurate to a reasonable degree of 
certainty will be assigned a unique notification number, provided to 
the identified owner or operator as quickly as possible, and the 
notification will be made public at https://www.epa.gov/super-emitter 
at the same time. However, the initial public notification will not 
include the identity of the owner or operator, so that the notified 
owner or operator has an opportunity to respond before attribution is 
posted.

[[Page 16921]]

4. Requirements for Owners and Operators
    We received several comments on the December 2022 Supplemental 
Proposal on the required actions when owners or operators receive 
notification of a super-emitter event as part of the Super Emitter 
Program. This section of this document presents a summary of 
significant comments received regarding the follow-up investigations, 
requirements for any necessary repairs, and reporting the results of 
those investigations to the EPA, and the EPA's response to those 
comments. This section also details changes the EPA has made in the 
final rule to account for those comments, changes in the final rule 
concerning the EPA's central role in handling responses from the owner 
or operator, and changes in the final rule reflective of this program 
as a compliance assurance program.
    We received several comments <SUP>348 349 350</SUP> supporting the 
requirement that owners or operators investigate the source and 
cause(s) of significant emissions events that are brought to an 
operator's or owner's attention. More than a few of these commenters 
took issue with our proposed use of ``root cause analysis'' for 
investigating potential causes of super-emitter events. Specifically, 
one comment argued that the concept of ``root cause analysis'' is 
embedded in numerous other regulatory and non-regulatory programs and 
has varied meaning and purpose in each application, and another 
commenter asserted that the phrase ``root cause analysis'' has 
connotations that lead to a much more involved process than the EPA 
appears to have envisioned in the December 2022 Supplemental Proposal. 
Many of these commenters suggest that ``root cause analysis'' be 
replaced by ``investigative analysis,'' broadly meaning the owner or 
operator must determine whether an emissions event has occurred and 
take steps to ensure that it will not happen again.
---------------------------------------------------------------------------

    \348\ EPA-HQ-OAR-2021-0317-2627.
    \349\ EPA-HQ-OAR-2021-0317-2483.
    \350\ EPA-HQ-OAR-2021-0317-2326.
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    We received several comments discussing the suitability of the 
timelines provided in the December 2022 Supplemental Proposal. Several 
commenters <SUP>351 352</SUP> indicated the proposed 5 days to initiate 
root cause and 10 days to complete corrective action are inadequate, as 
some locations are remote in nature or, in some instances, may require 
longer timeframes to obtain equipment or schedule service companies to 
complete the corrective action. Some of these commenters recommended 
that the EPA provide owners or operators with 14 business days to 
conduct an analysis of the incident and provide the EPA with 
recommended actions to avoid future occurrences; one commenter also 
suggested that if analysis cannot be conducted within 14 business days, 
the owner or operator should notify the EPA and let the Agency know 
when the analysis will be available, which in no event may exceed 90 
days.
---------------------------------------------------------------------------

    \351\ EPA-HQ-OAR-2021-0317-2305.
    \352\ EPA-HQ-OAR-2021-0317-2409.
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    The EPA also received several comments regarding the potential 
causes for super-emitters and what the appropriate steps should be for 
investigating super-emitter events. One commenter \353\ reasoned that 
many of the super-emitter events of this magnitude are caused by unlit 
flares and tank malfunctions and that in those cases owners and 
operators should be able to fix the underlying issue quickly. Another 
commenter \354\ identified that super-emitter emissions may be caused 
by an anticipated, short-duration event such as operations and 
maintenance activity at the site. Several commenters <SUP>355 356</SUP> 
raised that for sites with validated continuous monitoring systems, 
these systems will very likely already have noted and mitigated super-
emitter events before even receiving a notification.
---------------------------------------------------------------------------

    \353\ EPA-HQ-OAR-2021-0317-2433.
    \354\ EPA-HQ-OAR-2021-0317-2326.
    \355\ EPA-HQ-OAR-2021-0317-2284.
    \356\ EPA-HQ-OAR-2021-0317-2333.
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    Regarding whom is subject to the Super Emitter Program, the EPA 
received some comments that no investigative analysis should be 
required if the emissions are not associated with an affected facility 
under NSPS OOOOb. Another commenter \357\ contends that the EPA has 
broad authority under CAA section 114 to accept and use third-party 
monitoring data for purposes related to CAA section 111, including 
ensuring compliance.
---------------------------------------------------------------------------

    \357\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    The EPA received several comments on how best to manage super-
emitter event reporting after receipt of a super-emitter notification. 
A commenter \358\ explores the possibility that an owner or operator 
should only be reporting to the EPA when the facility owner or operator 
confirms the super-emitter event; this commenter also discussed the 
EPA's developing a document repository for the notices to operators it 
receives as well as the reports sent by the owners and operators in 
response. A few commenters <SUP>359 360</SUP> representing state and 
Tribal authorities request that all subsequent reports and submittals 
should also be copied to the state, to aid states' compliance efforts 
under the Super Emitter Program and to provide information that states 
can use in their own compliance and enforcement efforts. Several 
commenters raised concerns regarding either the misidentification of an 
operator's facility or inaccurate quantification of super-emitter 
emissions. Another commenter requested that we maintain the language 
referenced in the December 2022 Supplemental Proposal preamble to allow 
that owners and operators would have the opportunity to rebut any 
information in a notification provided by the qualified third parties 
in their written report to the EPA, by explaining where appropriate 
that: there was a demonstrable error in the third-party notification; 
the emissions event did not occur at a regulated facility; or the 
emissions event was not the result of malfunctions or abnormal 
operation that could be mitigated.
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    \358\ EPA-HQ-OAR-2021-0317-2193.
    \359\ EPA-HQ-OAR-2021-0317-2241.
    \360\ EPA-HQ-OAR-2021-0317-2177.
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    The EPA is finalizing the Super Emitter Program as primarily a 
compliance assurance program and is not maintaining the root cause 
analysis and corrective action requirements from the December 2022 
Supplemental Proposal. The EPA acknowledges the commenters' concern 
with the use of the ambiguous root cause and corrective action language 
for this sector and is in the final rule defining a set of 
investigations that an owner or operator must perform when provided 
with a super-emitter notification. The EPA is maintaining the 
requirement from the supplemental proposal that the owner or operator 
of a well site, centralized production facility, or compressor station 
must initiate an investigation within 5 calendar days after a 
notification, and based on comment we are extending the period to 
conduct the investigation to 15 calendar days. These time periods are 
appropriate given the very large emissions associated with super-
emitter events; it is important that owners and operators respond 
quickly to these very large emissions events and take immediate action 
to stop them. Many operators have noted to the EPA that prompt notice 
of super-emitter events is important to them exactly for this reason.
    The EPA has defined a series of required investigations in the 
final rule, designed to target these very large emissions events as 
part of a compliance assurance program. In response to

[[Page 16922]]

comments, the investigations are designed to minimize the time and 
resources associated with conducting these investigations. Upon 
receiving a super-emitter notification by the EPA, a recipient is first 
required to determine if it is the owner or operator a well site, 
centralized production facility, or compressor station within a radius 
of 50 meters from the latitude and longitude provided in the 
notification, and if not, the recipient's investigation is complete. If 
the recipient does own a well site, centralized production facility, or 
compressor station within a 50-meter radius, it must determine the 
applicability of any equipment under 40 CFR part 60, subpart OOOO, 
OOOOa, or OOOOb, and/or a state or Federal Plan implementing subpart 
OOOOc, and is required to perform the investigations as defined in that 
applicable subpart. However, for ease of use, the investigations in 
each of these subparts are identical. We agree with the commenters that 
the largest potential for super-emitters is from maintenance events and 
failure of controls and, as such, have incorporated elements into the 
investigations under the requirements for maintenance and controls to 
identify potential causes. Specifically, the investigation incorporates 
the review of any maintenance events (e.g., liquid unloading) conducted 
from the date of detection until the start date of the investigations; 
and the review of process monitoring data (e.g., SCADA systems) from 
control devices to identify any potential causes of a super-emitter 
event. We also agree with the commenters that methane monitoring 
surveys and/or continuous emissions monitoring conducted from the date 
of detection until the start date of the investigations would have 
identified the presence or absence of a super-emitter event and when an 
event is identified the owner or operator could quickly identify the 
cause(s). All these investigations are designed to leverage actions 
potentially being performed or recorded as part of daily operation of a 
site and are effective tools for identifying large emissions events. 
The EPA also recognizes that all sites will not have continuous 
monitoring systems and that the owner or operator is likely not to have 
conducted fugitive monitoring between the date of detection and the 
notification; in those events we are requiring the owner or operator to 
conduct screening for a super-emitter event using either OGI, EPA 
Method 21, or an approved alternative test method(s) approved per 40 
CFR 60.5398(d).
    The EPA has restructured the reporting requirements for owners and 
operators in the final rule to be consistent with the change in the 
program to focus on compliance assurance and to account for the revised 
investigation requirements in the rule. While some commenters suggested 
that only confirmed super-emitter events should require reports, it is 
important for an owner or operator to report the results of their 
investigation in any case, as the absence of a super-emitter event is 
equally as important as the confirmation for the EPA, the state, local, 
or Tribal authority, and the general public. As such, we are requiring 
any owner or operator who receives a notification to report the finding 
of their investigation. The EPA agrees with these comments requesting 
that these owner or operator super-emitter reports be readily 
accessible, so the EPA is requiring that these reports be submitted 
through the Super Emitter Program Portal to aid in the public display 
of data. The EPA also agrees with those state and Tribal authorities 
that super-emitter reports should be available to the states at the 
time of reporting, and the Super Emitter Program Portal will include a 
function to notify a state, local, or Tribal authority when 
notifications and/or reports from their jurisdiction are received. The 
EPA is requiring that owners or operators report the findings within 15 
days after receiving a notification of a super-emitter event; this 
marks the final day of the investigation period and is a timeline that 
is consistent with criteria in the December 2022 Supplemental Proposal 
for reporting initial corrective action. We acknowledge that we 
received comment from industry requesting longer timelines for 
corrective actions. Due to the large size of these emission events, the 
EPA considers the 15 days requirements a reasonable timeframe within 
which to conduct and report the required investigations to determine if 
the emission event is ongoing is consistent with the objective of this 
program to provide actionable information to owners or operators of 
facilities experiencing large emissions events, so they can investigate 
and perform repair if needed. The super-emitter program does not place 
any additional requirements or timeline to repair (i.e., corrective 
actions) the source of these large emission events that are not already 
included in the rule, however the final rule does include reporting 
requirements if the emission events are ongoing at the time of the 
initial report submittal.
    The level of reporting required by the owner or operator is 
dependent on the results of the investigation and the super-emitter 
event. The owner or operator of a site within 50 meters from the 
latitude and longitude in the notification is required to provide the 
super-emitter event notification ID, general identification of the 
facility, whether the equipment on the site is subject to regulation 
under the applicable subpart, and whether you were able to identify the 
super-emitter event. If the owner or operator is able to identify a 
super-emitter event, the owner or operator would also report if the 
equipment was subject to an applicable regulation (including the 
applicable subpart), whether or not the super-emitter event is ongoing 
at the time of reporting, and, if the super-emitter event is not 
ongoing at the time of reporting, the actual or estimated date and time 
when the event ended. If the super-emitter event is ongoing at the time 
of reporting, the owner or operator would provide a short narrative of 
the plan to end the super-emitter event, including an expected end date 
of the event, and the owner or operator would be required to update the 
initial report within 5 days after the actual end date of the super-
emitter event.
    Finally, we acknowledge the commenters' concerns that a third party 
may either misidentify a site's owner or operator or provide inaccurate 
data, and we agree with the commenters that owners and operators should 
have the opportunity to refute the information provided by the third 
party. The revised program in this final rule will give the owner or 
operator the opportunity to respond before the emissions event is 
attributed to a particular owner or operator, through posting of the 
report that the owner or operator submits to the EPA though the Super 
Emitter Portal.
5. Recordkeeping and Reporting Requirements for Process Controllers Not 
Included in the Affected Source
    Comment: Commenters pointed out that 40 CFR 60.5420b(b)(7) requires 
owners and operators to submit an identification of all process 
controllers that are not powered by natural gas in the initial annual 
report, and such controllers are not covered by the definition of the 
affected facility for process controllers for NSPS OOOOb. The 
commenters recommended that owners or operators only be required to 
maintain records and submit information sufficient to determine 
compliance with the regulations. The commenters contend that having 
requirements for equipment that is not

[[Page 16923]]

part of an affected facility exceeds the EPA's authority granted under 
CAA section 111 and add that there is no environmental benefit to 
keeping or submitting information for equipment that cannot have 
emissions. The commenters recommended that the EPA delete any reporting 
or recordkeeping requirements for these controllers from the final 
regulations.
    Response: After considering this comment, we have determined that 
it is appropriate in this instance to require identification of the 
equipment that is included in the affected facility, rather than the 
equipment that is not part of the affected facility. The process 
controllers included in the affected facility are those that are 
subject to the emissions standards, whereas process controllers not 
included in the affected facility are not subject to the emissions 
standards in the final rule and also mostly have no potential to emit 
methane or VOCs. Therefore, we have revised the recordkeeping 
requirements to require identification only of controllers that meet 
the finalized definition of an affected facility, which are those 
process controllers that are driven by natural gas and that are not 
ESDs.

D. Process Controllers

    Process controllers are among the largest sources of methane and 
VOC emissions in the source category. In the December 2022 Supplemental 
Proposal, the EPA proposed for both the NSPS OOOOb and EG OOOOc to 
define the process controller affected facility, and designated 
facility, as the collection of all natural gas-driven process 
controllers at a site. The December 2022 Supplemental Proposal, like 
the November 2021 Proposal, proposed two different standards for 
process controllers. For affected facilities that are not located in 
Alaska, the EPA proposed a zero-emissions standard and explained that 
it could be achieved with any one of several available technology 
options that many owners and operators are already deploying to varying 
degrees, including the use of electric controllers or compressed air 
systems (powered by the grid or by an onsite generator), solar-powered 
controllers, and natural gas-driven controllers that are self-contained 
or that are routed to a process. For affected facilities that are 
located in Alaska and do not have access to grid power, the EPA 
proposed a low-bleed emissions standard for continuous vent process 
controllers and a requirement that intermittent process controllers be 
periodically monitored for leaks and malfunctions using OGI.
    A number of comments were received on aspects of the proposed NSPS 
OOOOb and EG OOOOc zero-emissions standard. This included comments on 
the costs and emissions estimates that supported the BSER analysis. 
These comments and the EPA responses are provided in section XI.D.1 of 
this document. The EPA received other comments related to the zero-
emissions standard, including comments regarding access to reliable 
electricity and the technical feasibility of solar-powered controllers, 
routing emissions from natural-gas driven controllers to a control 
device, the potential impacts on small businesses, and the secondary 
emissions from the use of onsite generators. These comments and the 
EPA's responses are provided in section XI.D.2 of this document. 
Section XI.D.3 summarizes the refreshed BSER analysis and conclusions 
for the final rule. Comments were received regarding the compliance 
dates for both the NSPS and the EG. These comments and the EPA's 
responses are provided in section XI.D.4 of this document. The EPA also 
received comments regarding proposed recordkeeping and reporting 
requirements for process controllers not included in the affected 
facility and the criteria that would determine whether a process 
controller was modified or reconstructed. These comments, along with 
the EPA responses and the resulting rule changes, are provided in 
sections XI.D.5 and D.6 of this document. The EPA's full response to 
comments on the November 2021 Proposal and December 2022 Supplemental 
Proposal, including any comments not discussed in this preamble, can be 
found in the EPA's RTC document for the final rule.\361\
---------------------------------------------------------------------------

    \361\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

    In addition to the changes made to the final NSPS and EG to address 
these comments, one other change in terminology was made to address 
confusion in comments related to the types of equipment that may be 
used to perform the functions of process controllers. That change is 
discussed in section XI.D.7 of this document.
1. BSER Cost Analysis
    As described in the December 2022 Supplemental Proposal,\362\ the 
EPA reviewed a range of technologies (control options) for limiting or 
avoiding GHG (methane) and VOC emissions from process controllers. The 
EPA concluded that adequately demonstrated zero-emissions pneumatic 
controller systems were available throughout the production and the 
transmission and storage segments. To evaluate the costs of these 
systems, the BSER analysis for the December 2022 Supplemental Proposal 
was performed for three model plant sizes in both the production and 
the transmission and storage segments. These model plant sizes were 
based on the number of natural gas-driven pneumatic controllers at a 
site: 4 controllers for the ``small'' model plant, 8 controllers for 
the ``medium model plant,'' and 20 controllers for the ``large'' model 
plant. For new sources, these controllers were broken down by low-bleed 
and intermittent vent. For existing sources, there was also one high-
bleed controller for each model plant size. The zero-emissions options 
analyzed for each model plant were: electric controllers powered by the 
grid, electric controllers powered by solar energy, compressed air 
systems powered by the grid, and compressed air systems powered by an 
onsite generator. As a result, the EPA's cost analysis considered sites 
both with and without electrical service (grid power). Based on this 
analysis, the EPA concluded that there was at least one option for each 
model plant size with a cost effectiveness value that is within the 
range the EPA considers to be reasonable for the purposes of this 
rulemaking.\363\
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    \362\ 87 FR 74764 and 74765, December 6, 2022.
    \363\ 87 FR 78768, December 6, 2022.
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    The EPA received and considered comments that resulted in updates 
to its cost analysis. These updates focused on model plants as well as 
the capital recovery periods for several options, and the option of 
using a generator to power electric controllers at sites without grid 
electricity was added. Each of these issues is discussed in more detail 
below.
    Comment: One commenter \364\ recommended that the EPA gather 
additional information to create a representative gathering and 
boosting compressor station model plant. They indicated that gathering 
and boosting compressor stations typically have many more than 20 
controllers and require air compressors larger than 20 horsepower, as 
the EPA assumed in the ``Large Model Plant'' for production sites. 
Another commenter \365\ indicated that some multi-well sites, central 
production facilities, and compressor

[[Page 16924]]

stations may contain 100-200 controllers.
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    \364\ EPA-HQ-OAR-2021-0317-2399.
    \365\ EPA-HQ-OAR-2021-0317-0808.
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    One commenter \366\ indicated that the EPA's small, medium, and 
large model plants do not reflect the actual average size of 
transmission and storage facilities based on the average size reported 
in EPA's GHGI, and that the EPA should increase the size of its model 
plants to accurately reflect average plant sizes.
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    \366\ EPA-HQ-OAR-2021-0317-2433.
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    A commenter \367\ noted that intermittent controllers represent 
most of the pneumatic devices in operation within the petroleum and 
natural gas system segments today.
---------------------------------------------------------------------------

    \367\ EPA-HQ-OAR-2021-0317-2446.
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    Response: In response to these comments, the EPA made the following 
updates to the controller model plants.
    <bullet> Two new ``midstream'' model plants were added to represent 
gathering and boosting stations. The small midstream model plant 
contains 20 pneumatic controllers, and the large midstream model plant 
contains 100 pneumatic controllers.
    <bullet> The three transmission and storage model plants used in 
the supplemental analysis were replaced by a small transmission and 
storage model plant (30 pneumatic controllers) and a large transmission 
and storage model plant (50 pneumatic controllers).
    <bullet> The breakdown of controllers at the new small production 
model plants was updated to reflect a higher percentage of intermittent 
vent controllers. For new sources, the supplemental analysis assumed 
two low bleed and two intermittent vent controllers. This was updated 
to one low bleed and three intermittent vent controllers.
    Comment: One commenter \368\ pointed out that for electric-powered 
compressed air systems, the EPA applied an annualization period of 15 
years as opposed to the 6-year period in the 2021 Carbon Limits study.
---------------------------------------------------------------------------

    \368\ EPA-HQ-OAR-2021-0317-2428.
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    Response: The EPA agrees with the commenter that, while the EPA 
correctly applied the cost estimates from the 2021 Carbon Limits study, 
the EPA incorrectly applied an annualization period of 15 years instead 
of the 6-year period in the Carbon Limits cost estimates. This 
realization caused the EPA to review all the capital recovery 
annualization periods for the zero-emissions options. This led to the 
following updates for the capital recovery annualization periods in the 
analysis.
    <bullet> For electric controllers powered by the grid, from 15 
years to 6 years.
    <bullet> For solar-powered electric controllers, from 15 years to 
10 years.
    <bullet> For instrument air systems powered either by the grid or 
from generator from 15 to 6 years.
    Comment: Commenters submitted information to support the EPA's 
understanding that zero-emitting options for process controllers are 
technologically and economically reasonable. As a result of comments 
submitted in response to the December 2022 Supplemental Proposal, the 
EPA engaged in a clarification discussion with EQT regarding its 
process controller replacement program.\369\ The EPA learned that EQT 
Corporation, one of the largest producers of natural gas in the U.S., 
successfully implemented a program to replace over 8,000 natural gas-
driven controllers at their sites.\370\ EQT announced the replacement 
initiative in June 2021, and has completed the project. While EQT 
explored a variety of zero-emitting options, the option they found most 
effective was the use of generators to power electric controllers.
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    \369\ See June 7, 2023, meeting memorandum in EPA-HQ-OAR-2021-
0317.
    \370\ https://www.eqt.com/responsibility/pneumatic-device-replacement/.
---------------------------------------------------------------------------

    Response: Although the EPA evaluated the use of generators to power 
compressed air systems for process controllers at sites without grid 
electricity, the EPA did not consider the use of generators to power 
electric controllers at sites without grid electricity in the December 
2022 Supplemental Proposal. Using available information, the EPA 
estimated costs for systems using electric controllers powered by a 
generator. The EPA estimates the capital costs for these types of 
systems to range from just under $29,000 for the smallest production 
model plant to over $350,000 for the largest midstream model plant and 
the annual costs to range from around $8,500 for the smallest 
production model plant to over $55,000 for the largest midstream model 
plant. For summary information on the cost effectiveness of the 
analyzed available control options, see tables 18 and 19. For more 
complete information on the cost analyses conducted for process 
controllers, see the TSD for the final rule.
2. Zero-Emissions Standard
    Comment: Several commenters remarked that it would be difficult for 
some sites to comply with the zero-emissions standard for process 
controllers due to a lack of access to electrical power at rural 
locations. Several commenters noted that sites are sometimes miles away 
from the existing electrical grid, and others mentioned that there can 
be challenges to connecting to a nearby grid, such as with right-of-way 
issues for placement of power lines.
    Response: The commenters appear to suggest that the zero-emissions 
standard is only feasible if electrical grid power is available to 
sites. The EPA disagrees that grid power is necessary to comply with 
the zero-emissions standard for process controllers. The zero-emissions 
standard is technology-neutral and does not require that energy from 
the electrical grid be used to power controllers. There are many other 
technologically feasible and cost-effective options that are available 
to owners or operators to achieve zero emissions from process 
controllers, including self-contained controllers, solar-powered 
controllers, controllers powered by electric generators, and 
controllers that have their emissions routed to a process. As noted 
here, these options that are not powered by electricity from the 
commercial power grid are cost-reasonable. These options are discussed 
further in the December 2022 Supplemental Proposal (87 FR 74763).
    Comment: The December 2022 Supplemental Proposal included 
discussion of the technical viability of solar-powered process 
controllers.\371\ While many commenters on the November 2021 Proposal 
expressed the opinion that solar-powered process controllers were not a 
viable option due to perceived technical limitations, one commenter 
cited a study by Carbon Limits \372\ that demonstrated solar-powered 
controls installed at well sites in remote and cold locations such as 
Northern Alberta and British Colombia have been proven to operate 
properly without major reliability issues. Several commenters on the 
December 2022 Supplemental proposal continued to state that solar-
powered process controllers would not be feasible in some situations 
and specifically addressed the EPA's reliance on the Carbon Limits 
report. For example, one commenter indicated that the Carbon Limits 
report focuses on the reliability of solar power systems in colder 
climates, not areas with limited sun exposure. As a result, the 
commenter points out, the Carbon Limits study does not address the 
reliability of solar-powered systems in areas with limited sun 
exposure, such as West Virginia, or in canyons and mountain valleys.

[[Page 16925]]

Commenters also noted that other factors limit the feasibility of 
including solar-powered systems at sites that have significant numbers 
of foggy or cloudy days, or high amounts of ice or snowfall, and in 
cold locations where battery storage could be negatively impacted. The 
commenters state that reliance on solar power leaves sites subject to 
the weather and possibly effectively shut down for days. One commenter 
noted that solar power may not be feasible for gathering and boosting 
operations, which have larger footprints and substantially greater 
power needs than other types of operations.
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    \371\ 87 FR 74764, December 6, 2022.
    \372\ EPA-HQ-OAR-2021-0317-1451.
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    Response: Some commenters contend that solar power is not a 
feasible option to use for controllers at some sites because of 
perceived technical limitations. Considering that the electrical power 
needed by each controller is relatively low,\373\ the EPA reasonably 
expects that a solar power system can be sized with the appropriate 
number of panels and batteries to power process controllers at most, if 
not all, sites. The EPA does not agree with commenters' claim that 
powering process controllers with solar power is technically 
infeasible. The EPA has examined these claims from commenters and finds 
that solar technology has advanced such that it has overcome previous 
technical limitations and is now a technically viable control option. 
Further, the use of solar power is not required by this rule. Another 
control option determined to be cost-effective at all sites, based on 
the EPA's BSER analysis, is the use of a generator to power electric 
process controllers, and the use of a generator to power a compressed 
air system was cost-effective at larger sites. Other options available 
to meet the zero-emissions standard at sites without grid power and 
without using solar power include self-contained process controllers, 
or routing emissions from controllers to a process, although costs were 
not evaluated for these two options.
---------------------------------------------------------------------------

    \373\ Estimate of 0.08 amps/controller in Carbon Limits. (2016) 
Zero emission technologies for pneumatic controllers in the USA--
Applicability and cost effectiveness.
---------------------------------------------------------------------------

    Regarding the suggestion that compliance with the zero-emissions 
standard is infeasible at sites requiring a large electricity demand 
because solar power would not adequately supply this amount of power, 
we note that most gathering and boosting stations and transmission and 
storage sites already have electrical grid power at the site. However, 
as evidenced by the tables below in this section that summarize the 
cost analyses, sites that are not connected to the grid have one or 
more cost-effective alternatives other than using solar power (using a 
generator to power electric controllers or a compressed air system), 
and the owner/operator is able to choose their preferred compliance 
option for each site.
    Comment: Several commenters requested that the EPA allow owners or 
operators to route emissions from process controllers to a control 
device that achieves 95 percent control. The commenters report that 
this would be a cost-effective emissions reduction method for the many 
sites that have control devices onsite already. Other commenters remark 
that they are already routing emissions from process controllers to 
control devices and that requiring a zero-emissions standard for units 
already controlled by 95 percent or more requires the same capital and 
annual investment, but with little additional emission reduction over 
the baseline.
    Response: We evaluated the use of control devices achieving 95 
percent pollution control in our analyses for the December 2022 
Supplemental Proposal.\374\ This control option was determined not to 
be the BSER for new or existing sources and was not used to develop the 
process controller standards for the NSPS or the presumptive standards 
in the EG. Zero emissions from new and existing process controllers was 
shown in our analyses to be technically achievable through several 
available options, including the use of self-contained controllers, 
electrical controllers powered by electricity from the grid or solar 
power systems, or controllers powered by compressed air using 
electricity from the grid or from electric generators, and by routing 
emissions to a process. The EPA has also shown that at least some of 
these available options are cost-effective for different types of 
facilities (model plants). Since these options achieve a rate of zero 
GHG (methane) and VOC emissions, compared to an emission rate of up to 
5 percent of the baseline emissions through the use of a control 
device, we have not changed our determination that a zero-emissions 
option is the BSER. The baseline that the EPA used for the BSER 
analysis did not assume that emissions from the collection of process 
controllers was already being controlled at a 95 percent reduction 
because EPA does not have information indicating that any sizable 
portion of the industry is already being controlled at that level. 
While the EPA acknowledges that some process controllers may be subject 
to state-level regulations that result in such controls (95 percent 
reduction compared to uncontrolled emissions), the EPA does not have 
information indicating how prevalent such controls are for existing 
sources and therefore could not reasonably assume that such level of 
control reflected an accurate representation of a typical industry 
source, or even a typical source in a particular state or geographic 
region. While some state regulations may include a provision that could 
require certain process controllers to reduce emissions by 95 percent 
or more, those same regulations also include various exemptions, 
variances, and applicability thresholds that make it unclear which 
sources are actually achieving the 95 percent reductions. The EPA did 
not have sufficient information on this issue to alter the BSER 
analysis. The Agency was not presented with data or any empirical 
evidence to show how many, or which, sources are currently being 
controlled to this extent. The Agency was not compelled to alter the 
BSER analysis because of the anecdotal accounts provided by commenters. 
However, when developing state plans for the implementation of the EG 
for existing sources, states have the ability through RULOF to apply a 
less stringent standard with an appropriate demonstration in accordance 
with the requirements of 40 CFR part 60, subpart Ba.
---------------------------------------------------------------------------

    \374\ 87 FR 76765. December 6, 2022.
---------------------------------------------------------------------------

    Comment: Several commenters request that the EPA consider allowing 
the use of low-bleed or intermittent-bleed pneumatic controllers at low 
production/small sites. The commenters noted that some older facilities 
currently have very little throughput, and therefore low emissions from 
pneumatics due to infrequent activation. They also noted that low-
producing wells could be close to the end of their production cycle 
life and may only contain a limited number of controllers. The 
commenters add that the complete retrofit of a low-producing facility 
is likely cost-prohibitive based on well economics and could result in 
many low production wells or stripper well sites shutting in 
production.
    Response: As demonstrated in analyses conducted for the December 
2022 Supplemental Proposal and the refreshed analysis conducted for the 
final rule (see section XI.D.3 below), we found zero-emissions options 
to be cost-effective even at small sites (i.e., four process 
controllers at the site in our smallest model plant scenario). The 
emission factors used in the analyses are average emission factors, 
which are based on emissions from many sites

[[Page 16926]]

with varying actuation frequencies. There is considerable evidence that 
malfunctioning natural gas-driven intermittent vent controllers are a 
significant source of emissions and the emissions from an intermittent 
controller that is malfunctioning and venting continuously are not 
related to the actuation frequency. While sites with controllers that 
actuate infrequently may have lower than the average emissions, the 
cost effectiveness values for at least some zero-emissions control 
options (i.e., electric controllers powered by the grid, by solar 
power, and by power created by an onsite generator) are comfortably 
within the range that the EPA considers to be acceptable (see 87 FR 
74762), such that even if emissions were less than one-quarter of the 
average (which the EPA can reasonably expect to be rare), the EPA would 
still consider the costs acceptable given the emissions reductions that 
would be achieved.
    Further, while the emissions from natural gas-driven pneumatic 
controllers at a small site may be low in comparison to those from a 
central production facility or gathering and boosting station, the 
sheer number of small sites means that the cumulative methane emissions 
from these sites are significant. The EPA estimates that 47 percent of 
the total nationwide emissions from pneumatic controllers occurs from 
sites with less than four controllers. In a study funded by DOE's 
National Energy Technology Laboratory (DOE-NETL), GSI Environmental 
Inc. (2022) estimates that marginal natural gas and oil wells account 
for 59 percent and 37 percent of cumulative methane emissions from oil 
and natural gas production, respectively, and roughly half of 
cumulative methane emissions from combined oil and natural gas 
production. Similarly, Omara, et al. (2022), estimate that low 
production well sites account for roughly half (37-75 percent) of all 
oil and natural gas well site methane emissions. When considering the 
costs of the various control options in conjunction with the associated 
emission reduction of those same control options, the EPA found even 
for sites with relatively few process controllers, it was cost-
effective to achieve a zero-emissions standard. For additional 
discussion of marginal wells, see chapter 6 of the Final Rule TSD. 
Lastly, when developing state plans for the implementation of the EG 
for existing sources, states have the ability through RULOF to apply a 
less stringent standard with an appropriate demonstration in accordance 
with the requirements of 40 CFR part 60, subpart Ba.
    Comment: Several commenters are concerned about the secondary 
emissions that will be created if natural gas-fired generators are used 
to power process controllers. The commenters are concerned that the 
operation of generators could result in increased cumulative nitrogen 
oxide (NO<INF>X</INF>) and VOC emissions as well as criteria pollutants 
and hazardous air pollutants (HAP). The commenters indicated that these 
emissions could potentially offset the emissions reductions from the 
methane and VOC, and these emissions from sites in ozone non-attainment 
areas could prevent those areas from gaining ozone attainment status.
    Response: The EPA recognizes that if owners and operators elect to 
comply by installing and operating a generator, there will be secondary 
emissions generated from the fuel combustion; however, we have 
estimated the emissions that would be created by generators and found 
that they are far outweighed by the VOC and GHG (methane) emissions 
reduction that would be achieved by using process controllers that are 
not driven by natural gas. For the December 2022 Supplemental Proposal, 
while we did recognize that a commenter had provided estimates of these 
emissions, we did not separately analyze the secondary emissions that 
would be created if a generator was used to power this equipment.
    We have now conducted that analysis and estimate that for a natural 
gas-fired generator to power this equipment, the secondary criteria 
pollutant emissions would be 43 pounds per year (lb/yr) CO, 306 lb/yr 
NO<INF>2</INF>, 6 lb/yr PM, and 3 lb/yr PM<INF>2.5</INF> for a 5 HP 
compressor and 172 lb/yr CO, 1,222 lb/yr NO<INF>2</INF>, 26 lb/yr PM, 
and 13 lb/yr PM<INF>2.5</INF>, for a 20 HP compressor. The secondary 
GHG emissions generated as a result of this electricity generation are 
estimated to be 11,654 lb/yr CO<INF>2</INF>, 0.2 lb/yr methane, and 
0.02 lb/yr N<INF>2</INF>O for a 5 HP compressor and 46,618 lb/yr 
CO<INF>2</INF>, 0.9 lb/yr methane, and 0.09 lb/yr N<INF>2</INF>O for a 
20 HP compressor. Considering the global warming potential of these 
GHGs, the total CO<INF>2</INF> Eq. emissions would be 11,667 lb/yr 
CO<INF>2</INF> Eq. from a 5 HP compressor and 46,666 lb/yr 
CO<INF>2</INF> Eq. from a 20 HP compressor. With the total 
CO<INF>2</INF> Eq. emissions from process controllers at a small site 
estimated to be 303,000 lb/yr and 7.5 million lb/yr for a large site, 
the total CO<INF>2</INF> Eq. reduction from the use of zero-emissions 
process controllers powered by a generator running a compressed air 
system would be more than 95 percent when compared to the uncontrolled 
methane emissions from natural gas-driven controllers. No other 
secondary impacts are expected. Considering this information regarding 
secondary emissions, we continue to find that the BSER for reducing 
methane and VOC emissions from natural gas-driven controllers in the 
production and the transmission and storage segments of the industry to 
be the use of controllers that have methane and VOC emission rates of 
zero.
3. Final BSER Conclusions
    Based on the updates discussed above in section XI.D.2, the EPA 
refreshed the BSER cost analysis for new sources. This analysis 
estimates the cost and emission reductions for the following zero-
emissions options. For sites with access to electricity, the zero-
emissions options include electric controllers and pneumatic 
controllers powered by compressed air systems. For sites without access 
to electricity, the zero-emissions options include solar-powered 
electric controllers, electric controllers powered by a generator, and 
pneumatic controllers driven by a compressed air system powered by an 
onsite generator. The results of these updated analyses are shown in 
table 18. For more detailed information on these cost estimates, see 
the TSD for the final rule.

[[Page 16927]]



  Table 18--Summary of Process Controller Systems Not Driven by Natural Gas Cost Effectiveness Analysis for New
                                                     Sources
----------------------------------------------------------------------------------------------------------------
                                                                  Cost effectiveness  ($/ton) \a\
                                                 ---------------------------------------------------------------
  Location type  model plant  controller system          Single pollutant                 Multipollutant
                                                 ---------------------------------------------------------------
                                                      Methane           VOC           Methane           VOC
----------------------------------------------------------------------------------------------------------------
                                             Sites With Electricity
----------------------------------------------------------------------------------------------------------------
Small Production:
    Electric controllers........................            $378          $1,360            $189            $680
    Compressed air..............................           2,316           8,330           1,158           4,165
Medium Production:
    Electric controllers........................             289           1,039             144             520
    Compressed air..............................           1,270           4,569             635           2,285
Large Production:
    Electric controllers........................             235             847             118             423
    Compressed air..............................             865           3,112             433           1,556
Small Midstream:
    Electric controllers........................             235             847             118             423
    Compressed air..............................             865           3,112             433           1,556
Large Midstream:
    Electric controllers........................             210             754             105             377
    Compressed air..............................             485           1,745             243             872
Small T&S:
    Electric controllers........................             566           2,036             283           1,018
    Compressed air..............................           2,007           7,219           1,003           3,609
Large T&S:
    Electric controllers........................             533           1,917             266             959
    Compressed air..............................           1,951           7,018             975           3,509
----------------------------------------------------------------------------------------------------------------
                                            Sites Without Electricity
----------------------------------------------------------------------------------------------------------------
Small Production:
    Electric controllers--Solar.................             276             991             138             496
    Electric controllers--Generator.............           1,393           5,012             697           2,506
    Compressed air--Generator...................           4,199          15,106           2,100           7,553
Medium Production:
    Electric controllers--Solar.................             215             774             108             387
    Electric controllers--Generator.............             795           2,860             398           1,430
    Compressed air--Generator...................           2,085           7,500           1,042           3,750
Large Production:
    Electric controllers--Solar.................             179             643              89             322
    Electric controllers--Generator.............             665           2,394             333           1,197
    Compressed air--Generator...................           1,396           5,020             698           2,510
Small Midstream:
    Electric controllers--Solar.................             179             643              89             322
    Electric controllers--Generator.............             665           2,394             333           1,197
    Compressed air--Generator...................           1,396           5,020             698           2,510
Large Midstream:
    Electric controllers--Solar.................             162             581              81             291
    Electric controllers--Generator.............             370           1,333             185             666
    Compressed air--Generator...................             511           1,837             255             919
Small T&S:
    Electric controllers--Solar.................             435           1,566             218             783
    Electric controllers--Generator.............           1,327           4,775             664           2,388
    Compressed air--Generator...................           2,725           9,804           1,363           4,902
Large T&S:
    Electric controllers--Solar.................             411           1,478             205             739
    Electric controllers--Generator.............           1,330           4,786             665           2,393
    Compressed air--Generator...................           2,585           9,298           1,292           4,649
----------------------------------------------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the savings for the natural gas that is not
  emitted and not lost. The cost effectiveness values shown in this summary table do not consider these savings.
  If the EPA were to consider these savings, then the cost effectiveness figures in the table ($/ton methane
  reduced) would reduce, which would mean the options assessed would be even more cost reasonable than already
  shown in this table.

    For new sources, the EPA finds that all the options identified in 
table 18 are adequately demonstrated options for use of process 
controllers that are not driven by natural gas, thus resulting in zero 
GHG and VOC emissions. For overall cost effectiveness to be considered 
reasonable for new sources, either the cost effectiveness of GHG 
(methane) or VOC on a single-pollutant basis must be within the ranges 
considered reasonable by the EPA or the cost effectiveness of both 
methane and VOC on a multipollutant basis must be within the ranges 
considered reasonable by the

[[Page 16928]]

EPA. As shown in table 18, for every model plant in all sectors, there 
are two or more options for new sources for which the cost 
effectiveness is considered reasonable by the EPA. This is true for 
sites with electricity from the grid, as well as sites without this 
electrical service. For example, for a medium sized model plant in the 
transmission and storage segment at sites without access to grid 
electricity, the single-pollutant cost effectiveness values for solar-
powered electric controllers are $435 per ton of methane and $1,566 per 
ton of VOC, and the single-pollutant cost effectiveness values for 
electric controllers powered by a generator are $1,327 per ton of 
methane and $4,775 per ton of VOC. All of these values are within the 
range that the EPA considers to be reasonable. For a compressed air 
system powered by a generator for this model plant, the single 
pollutant values are $2,725 per ton of methane and $9,804 per ton of 
VOC. While these values exceed the levels typically considered 
reasonable by the EPA, the multipollutant cost effectiveness values of 
$1,363 per ton of methane and $4,902 per ton of VOC are within the 
ranges considered reasonable by the EPA. Therefore, the EPA considers 
the costs of all three zero-emissions options for this model plant to 
be reasonable given the associated 100 percent emission reduction 
achieved.
    As discussed above in section XI.D.2, some commenters contend that 
solar-powered controller systems are not a technically feasible 
emission control option. The EPA disagrees with this comment, as the 
successful use of solar-powered controllers has been demonstrated. The 
EPA accepts that there may be certain situations where site-specific 
conditions may not be favorable to the use of solar-powered controller 
systems. However, this analysis shows that there are other demonstrated 
options available for all model plant sizes at sites without 
electricity with costs that are considered reasonable given the 
resulting methane and VOC emission reductions. In addition, while 
information was not available to fully analyze the costs, the option of 
collecting the emissions from natural gas-driven pneumatic controllers 
and routing them to a process and the option of self-contained natural 
gas-driven pneumatic controllers also achieve 100 percent emission 
reductions. Therefore, they are considered equivalent to the use of 
controllers not driven by natural gas.
    The options evaluated for sites without grid electricity include 
the use of a generator to power either electric controllers or an 
instrument air (compressed air) system. As pointed out by some 
commenters, the use of these generators will create secondary air 
pollution. As discussed in more detail above in section XI.D.2, on an 
individual site basis the EPA concludes that the emissions that would 
be created by generators are far outweighed by the methane and VOC 
emissions reduction that would be achieved by using process controllers 
that are not driven by natural gas.
    In conclusion, based on comments received, the EPA refreshed the 
BSER analysis with respect to costs and the associated emissions 
reductions. The EPA also considered other comments on the BSER analysis 
and the proposed zero-emissions standard for process controllers. After 
this consideration, the EPA continued to conclude that BSER for new 
process controllers is the use of zero-emissions process controllers 
that do not emit GHG (methane) or VOC to the atmosphere. Therefore, the 
final rule maintains the proposed zero-emissions standard.
    The EPA also refreshed the BSER analysis for existing sources. For 
each zero-emissions option, the foundation for the cost estimates for 
existing sources was the same as for new sources. However, adjustments 
were made to account for differences in the costs that would be 
incurred for existing sources. For example, the installation costs were 
assumed to be twice as high for existing sources as compared to new 
sources. Another difference between the new and existing source 
analysis is related to the types of controllers assumed to be onsite 
for purposes of the model plants utilized in the analysis. The new 
source model plants did not include any high-bleed controllers. For 
existing sources, it was assumed that there was one high-bleed 
controller at every model plant. Thus, the baseline emissions, and the 
resulting emission reductions, were greater for existing sources as 
compared to new sources. The same zero-emissions options were evaluated 
for existing sources as for new sources, and, as for new sources, the 
EPA finds that all the options identified are adequately demonstrated 
options for use of process controllers that are not driven by natural 
gas, thus resulting in zero GHG (methane) emissions. The results of the 
refreshed cost analysis for existing sources is provided in table 19.

  Table 19--Summary of Process Controller Systems Not Driven by Natural
      Gas Methane Cost Effectiveness Analysis for Existing Sources
------------------------------------------------------------------------
                     Location  type                            Cost
---------------------------------------------------------  effectiveness
                                                                \a\
                                                         ---------------
             Model plant  controller system               ($/ton methane
                                                             reduced)
------------------------------------------------------------------------
                         Sites With Electricity
------------------------------------------------------------------------
Small Production:
  Electric controllers..................................            $449
  Compressed air........................................           2,157
Medium Production:
  Electric controllers..................................             375
  Compressed air........................................           1,232
Large Production:
  Electric controllers..................................             347
  Compressed air........................................             899
Small Midstream:
  Electric controllers..................................             347
  Compressed air........................................             899
Large Midstream:
  Electric controllers..................................             334
  Compressed air........................................             538
Small T&S:
  Electric controllers..................................             732
  Compressed air........................................           1,924
Large T&S:
  Electric controllers..................................             754
    Compressed air......................................           1,906
------------------------------------------------------------------------
                        Sites Without Electricity
------------------------------------------------------------------------
Small Production:
  Electric controllers--Solar...........................             329
  Electric controllers--Generator.......................           1,384
  Compressed air--Generator.............................           4,207
Medium Production:
  Electric controllers--Solar...........................             281
  Electric controllers--Generator.......................             871
  Compressed air--Generator.............................           2,233
Large Production:
  Electric controllers--Solar...........................             264
  Electric controllers--Generator.......................             845
  Compressed air--Generator.............................           1,685
Small Midstream:
  Electric controllers--Solar...........................             264
  Electric controllers--Generator.......................             845
  Compressed air--Generator.............................           1,685
Large Midstream:
  Electric controllers--Solar...........................             258
  Electric controllers--Generator.......................             538
  Compressed air--Generator.............................             679
Small T&S:
  Electric controllers--Solar...........................             564
  Electric controllers--Generator.......................           1,493
  Compressed air--Generator.............................           2,797
Large T&S:
  Electric controllers--Solar...........................             582
  Electric controllers--Generator.......................           1,653
  Compressed air--Generator.............................           2,978
------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the
  savings for the natural gas that is not emitted and not lost. The cost
  effectiveness values shown in this summary table do not consider these
  savings. If the EPA were to consider these savings, then the cost
  effectiveness figures in the table ($/ton methane reduced) would
  reduce, which would mean the options assessed would be even more cost
  reasonable than already shown in this table.

    As shown in table 19, for every model plant in all sectors, there 
are two or more options for which the cost effectiveness for methane 
for existing sources is considered reasonable by the EPA. This is true 
for sites with electricity from the grid, as well as sites

[[Page 16929]]

without this electrical service. For example, for the small model plant 
in the transmission and storage segment at sites without access to 
electricity, the cost effectiveness values ($ per ton of methane) are 
$564, $1,493, and $2,797 for solar-powered electric controllers, 
electric controllers powered by a generator, and compressed air powered 
by a generator, respectively. While the cost effectiveness for 
compressed air powered by a generator is above the level typically 
considered reasonable by the EPA, the other two options are well below 
the levels considered reasonable. The discussion above related to 
technical feasibility of solar-powered controllers and secondary 
emissions from generators for new sources is equally applicable for 
existing sources. As for new sources, routing pneumatic controller 
emissions to a process and using self-contained natural gas-driven 
pneumatic controllers are other control options available to achieve a 
zero-emissions standard.
    In conclusion, based on comments received, the EPA refreshed the 
BSER cost analysis for existing sources. The EPA also considered other 
comments on the BSER analysis and the proposed zero-emissions 
presumptive standard for process controllers. After this consideration, 
the EPA continues to conclude that BSER for existing process 
controllers is the use of zero-emissions process controllers that do 
not emit methane to the atmosphere. Therefore, the final emission 
guideline maintains the proposed zero-emissions presumptive standard.
4. Compliance Dates
    Comment: Several commenters state that a 60-day compliance deadline 
for new/modified sources is unrealistic due to supply chain concerns, 
personnel shortages, and inflation. Due to supply chain shortages and 
disruption, one commenter remarked that generators and other equipment 
and parts necessary for zero-emissions systems can take up to 3 months 
or longer for delivery, while another reports that they currently 
experience lead times for non-natural-gas-driven pneumatic controllers, 
generators, and air compressors ranging from 12 to 24 months. The 
commenters note that there is no indication that this lead time will 
improve in the near future and believe it can be expected to worsen as 
owners and operators across the country increase demand in response to 
the final rule. Commenters contend that this leaves even the most 
responsible owner or operator without the ability to comply within 60 
days. Some commenters recommend a compliance deadline of 24 months from 
the publication date of the final rule and others propose at least a 1-
year timeframe for NSPS OOOOb compliance to allow for procurement and 
installation of the systems and equipment necessary (including labor 
necessary for installation).
    One commenter contends that supply chain considerations do not 
alter the reasonableness of the EPA's proposal. The commenter relays 
that EQT, the largest natural gas producer in the U.S., retrofitted all 
its sites to eliminate natural gas-driven controllers in less than 1.5 
years \375\ and another oil and gas producer anticipates it will have 
replaced ``nearly all'' of its controllers with zero-emitting devices 
within 4 years.\376\ The commenter adds that a recent report by Datu 
Research further underscores that the supply chain for the production 
of zero-emitting technologies is not a barrier for industrywide 
adoption of zero-emissions controllers and that, on the contrary, the 
supply chain is strong enough to support implementation of the EPA's 
proposed standards.\377\ According to the commenter, Datu's report 
identifies 40 providers of zero-emitting controllers, and a survey of 
nine of these providers demonstrates that suppliers are well-equipped 
to meet anticipated demand within the EPA's proposed regulatory 
timeline.\378\ The commenter remarks that some key findings of the Datu 
report include the following:
---------------------------------------------------------------------------

    \375\ ``EQT Eliminates Nearly 9,000 Natural Gas-Powered 
Pneumatic Devices,'' PRNewswire (January 4, 2023) https://www.prnewswire.com/news-releases/eqt-eliminates-nearly-9-000-natural-gas-powered-pneumatic-devices-301713418.html.
    \376\ Diamondback Energy, ``2021 Corporate Sustainability Report 
8'' (2021), https://www.diamondbackenergy.com/static-files/faf5ab25-5ab5-4404-8c04-c7bd387ae418.
    \377\ Data Research, ``Zero-emission Alternatives to Pneumatic 
Control: How Ready are Technology Providers to Meet Increased 
Demand?'' (Jan. 2023).
    \378\ Id. at 5, 9.
---------------------------------------------------------------------------

    <bullet> Technology providers have strategies for meeting current 
supply chain challenges. Though procurement delays have been a reality 
for some suppliers, they have employed strategies like paying higher 
prices, storing extra quantities of supplies, bringing in more 
procurement personnel, going to different distributors, spot-buying on 
the open market, and finding contract manufacturing sites. Larger 
companies reported facing fewer hurdles.\379\
---------------------------------------------------------------------------

    \379\ Id. at 3.
---------------------------------------------------------------------------

    <bullet> Regulatory certainty steadies demand. Even considering 
supply chain concerns, providers have confidence in their ability to 
expand production capacity so long as regulatory certainty helps keep 
demand steady over multiple years.\380\
---------------------------------------------------------------------------

    \380\ Id. at 11-12.
---------------------------------------------------------------------------

    Response: Based on these comments, it appears that some equipment 
necessary for the installation of zero-emitting process controllers may 
not be available quickly enough, and in large enough quantities, to 
enable new sources to comply with the final standard upon startup, or 
within 60 days after the publication of the final NSPS. Supplemental 
information submitted by one commenter provided information regarding 
current equipment lead time and market conditions.\381\ According to 
that information, some of the operators surveyed report that they are 
experiencing delays in the availability of process controllers, 
electrical transformers, generator skids, and compressor skids of up to 
12 months. In addition, the zero-emissions technology supplier survey 
information also indicates that some equipment providers will need to 
ramp up production, and some components may not be widely available 
within 60 days after the publication of the final rule.
---------------------------------------------------------------------------

    \381\ API. Operator Survey of Supply Chain Delays for Equipment 
Needed for EPA Proposed NSPS OOOOb Methane Rule.
---------------------------------------------------------------------------

    The equipment types discussed in the information provided by these 
commenters are relevant to the installation of zero-emitting 
controllers. Further, the equipment types that the EPA believes are 
necessary to comply with the final standards for process controllers in 
NSPS OOOOb are quite different from the type of equipment used to 
comply with the standards for these sources found in NSPS OOOOa. For 
example, compliance with NSPS OOOOa for most sources likely does not 
require electrical transformers, generator skids, or compressor skids. 
Due to these considerations, the EPA is not certain that new sources 
could obtain the equipment necessary to demonstrate compliance 
immediately upon the effective date of the final rule and is therefore 
finalizing a compliance deadline for process controllers that allows 
for up to 1 year from the effective date of the final rule. This means 
that new sources will have up to 1 year to come into full compliance 
with the final standard of zero emissions. Until that final date of 
compliance, owners and operators must demonstrate compliance with an 
interim standard which mirrors the requirements for sites in Alaska 
that do not have access to electrical power found at 40 CFR 
60.5390b(b). In summary, the requirements for such sites allow for two 
compliance options.

[[Page 16930]]

One option is to use low-bleed controllers and/or intermittent vent 
controllers, and to perform monitoring of intermittent vent controllers 
to ensure they do not vent during idle periods. The other option is to 
route process controller emissions to a control device achieving a 95 
percent reduction in emissions. As the current NSPS OOOOa requires that 
low-bleed controllers be used, owners/operators of new and recently 
modified or reconstructed sites will be able to readily obtain the 
equipment necessary for these types of process controllers. Complying 
with the interim standard described above does not require using the 
equipment that commenters claimed they could not easily obtain (i.e., 
the equipment needed to meet the zero-emissions standard). Therefore, 
the EPA expects no sites to have any problems complying with these 
interim requirements within 60 days after publication of the final 
rule. If an owner or operator opts to comply with the interim standard 
during the one year following publication of the final rule, then they 
must still comply with the final zero-emissions standard after the year 
has passed. Owners and operators can, and are encouraged to, comply 
with the final zero-emissions standard before the year has passed.
6. Modification and Reconstruction Criteria and Requirements
    Under 40 CFR 60.14, any physical or operational change to an 
existing facility resulting in an emissions increase is a modification. 
In the December 2022 Supplemental Proposal, we stipulated that in 
addition to this definition of a modification, a modification would 
occur for purposes of this particular affected facility when a process 
controller is added to a site, as this addition would increase 
emissions from the affected facility, which is the collection of 
controllers at a site.
    Comment: Commenters requested that the EPA clarify that, for 
purposes of the collection of process controllers at a site, a 
modification would occur only when a natural gas-driven process 
controller is added, rather than the addition of any type of process 
controller. The commenters pointed out that the addition of a 
controller not driven by natural gas would not increase emissions from 
the affected source.
    Response: While it was our intention in the December 2022 
Supplemental Proposal to only include the addition of natural gas-
driven controllers in the conditions that would constitute a 
modification, as only those controllers could potentially increase 
emissions, we agree that the proposed regulatory text did not specify 
this. We therefore have changed what we proposed for regulatory 
language to clarify that the addition of one or more natural gas-driven 
controllers to a site constitutes a modification.
    Comment: Commenters also requested that the EPA clarify which 
controllers would be considered in the determination of whether a 
reconstruction has taken place. In the December 2022 Supplemental 
Proposal, we included provisions that would allow owners and operators 
to choose to determine whether a reconstruction has occurred as it is 
defined in 40 CFR 60.15(b), based on the fixed capital cost of new 
process controllers, or they could determine whether a reconstruction 
had occurred based on the percentage of the total number of process 
controllers replaced.
    Response: Like the provisions for modifications, we are clarifying 
in the final rule that reconstruction would be considered to occur 
whenever greater than 50 percent of the number of existing onsite 
natural gas-driven process controllers are replaced, rather than the 
replacement of any type of process controller, as only natural gas-
driven process controllers are considered to be affected facilities for 
the NSPS.
    Comment: In addition to these clarifications regarding the criteria 
for determining whether a modification or reconstruction has taken 
place, one commenter stated that it is unclear how the notification 
requirements of 40 CFR 60.15 apply for reconstruction. The commenter 
noted that the proposed language in 40 CFR 60.5365b(d)(2)(ii) suggests 
that reconstructed natural gas-driven process controllers would be 
subject to some of the requirements included in 40 CFR 60.15, which 
include 60-day notification and Administrator approval. According to 
the commenter, this conflicts with information presented in table 5 of 
the proposed regulatory text, which stated that 40 CFR 60.15(d) does 
not apply to process controllers. The commenter believes it was the 
EPA's intent to not apply the additional notification and approval, 
given the number of facilities that will trigger reconstruction over 
time.
    Response: We agree that we did not intend for facilities to be 
required to notify the Administrator of upcoming process controller 
replacements that would constitute a reconstruction or for the 
Administrator to be required to review the notification and determine 
whether the replacements constitute a reconstruction. We have changed 
what we proposed for regulatory text to not refer to the requirements 
of 40 CFR 60.15(d) and have kept the information presented in table 5 
of the proposed regulatory text, which states that 40 CFR 60.15(d) does 
not apply to process controllers.
7. Change in Pneumatic Controller Terminology
    To assist with avoiding possible confusion about which types of 
``controllers'' are included in the definition of this affected 
facility, and which types of controllers must be considered for 
purposes of the reconstruction and modification provisions, we have 
changed the terminology from ``pneumatic controllers'' (used in both 
the November 2021 Proposal and the December 2022 Supplemental Proposal) 
to ``process controllers'' in the final rule. When reviewing comments, 
the EPA noticed that not all commenters used the same terminology, so 
the Agency thought it best to clarify now. The EPA has made this change 
both in the final rule preamble and the final regulatory text. The term 
``process controller'' is broader in scope because it includes 
pneumatic controllers as well as other types of controllers that are 
not pneumatic. Only a subset of process controllers used by oil and gas 
facilities are pneumatic controllers that use pressurized air 
(compressed air or instrument air) or gas to perform their functions. 
Other process controllers might use electricity to perform their 
functions. From a technical perspective, electronic process controllers 
are not true ``pneumatic'' devices, but these electronic process 
controllers can be used to perform the same function as a pneumatic 
controller, and they achieve the zero-emissions standard. The EPA 
changed the terminology because we did not want to inadvertently convey 
that misimpression that process controllers had to be pneumatic. To be 
clear, the final rule applies to the collection of natural gas-driven 
process controllers at a well site. Process controllers that are not 
driven by natural gas are not included in the affected facility. 
Further, only process controllers driven by natural gas will be counted 
when determining whether a modification or reconstruction has occurred.

E. Pumps

    In the December 2022 Supplemental Proposal, the EPA proposed for 
both the NSPS OOOOb and EG OOOOc to define the pumps affected facility, 
and designated facility, as the collection of all natural gas-driven 
pumps at a site. For a limited subset of the affected pump facilities, 
the EPA proposed a

[[Page 16931]]

tiered structure of standards based on conditions at the affected 
facility. Among other comments, the EPA received comments regarding: 
(1) the BSER analysis and conclusions, (2) the compliance dates, (3) 
the requirements associated with the tiered approach for some pumps, 
(4) the recordkeeping and reporting requirements for pumps not included 
in the definition of the affected facility, and (5) the criteria that 
would determine whether an affected pump facility was modified or 
reconstructed. These comments and the EPA's responses to these comments 
apply to the standards and presumptive standards in NSPS OOOOb and EG 
OOOOc, respectively. A summary of the comments received and the EPA's 
response to these comments, including any updates made to the final 
rule, as applicable, are provided below. The EPA's full response to 
comments on the November 2021 Proposal and December 2022 Supplemental 
Proposal, including any comments not discussed in this preamble, can be 
found in the EPA's RTC document for the final rule.\382\
---------------------------------------------------------------------------

    \382\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

    In addition to the updates made to the final rule to address these 
comments, one other change in terminology was made to address the types 
of equipment that may be used to perform the functions of pumps. That 
change is discussed further here.
1. BSER Analysis and Conclusions
    The EPA received several comments regarding the proposed standards 
for pumps, including requests that the BSER analyses for pumps be 
revised to more closely match the analyses conducted for process 
controllers, requests for technology-neutral standards, and comments 
regarding the infeasibility certifications required.
    Comment: One commenter states that the EPA relied on costs from the 
2016 and 2021 Carbon Limits reports for process controllers, but that 
the EPA used different costs and assumptions as they pertained to 
converting to electric (assumed to be grid power) and solar pumps, 
which are not well documented and appear to be based on old information 
dating back to 2012.
    Another commenter remarked that the EPA proposed a set of 
requirements for natural gas-driven process controllers completely 
distinct from that for natural gas-driven pumps, with sometimes 
conflicting statements made to justify the EPA's decisions. The 
commenter requested that the requirements for both process controllers 
and pumps be streamlined for consistency, with technology-neutral 
standards that do not require additional certifications and that allow 
for emissions to be routed to a control device. Another commenter urged 
the EPA to mirror the proposed process controller standard for pumps by 
including pumps routed to a process as a compliance option and 
eliminating the tiered feasibility exemption at sites without 
electricity.
    Response: The EPA acknowledges that the analysis for pumps in the 
December 2022 Supplemental Proposal relied on costs from previous 
analyses that were updated to reflect changes in prices due to 
inflation. However, those cost figures used in the December 2022 
Supplemental Proposal did not reflect more recent changes that have 
occurred in control technology or the impact of those changes on costs, 
such as a reduction in costs for solar panels and batteries. Therefore, 
the EPA updated its analysis for pumps to use the more recent 
information for non-natural gas-driven pump options. This included 
information from the Carbon Limits reports, which addressed pump 
options as well as process controllers.
    A summary of the results of the updated analysis showing the cost 
effectiveness of the pumps affected facility emissions control options 
is shown in table 20. Further information regarding the analysis 
conducted for pumps may be found in the NSPS OOOOb and EG OOOOc TSD for 
this final rulemaking, which is available in the docket for this 
action. The cost effectiveness values shown in table 20 are based on 
the estimated total annual costs and the emissions reductions 
associated with each control option. The emissions reductions for a 
combustion control device are assumed to be 95 percent and are assumed 
to be 100 percent for all other control options evaluated. For new 
sources that will be covered by NSPS OOOOb, cost effectiveness was 
calculated on a single-pollutant basis, where the total annual cost was 
applied entirely to the reduction of each pollutant, and was also 
calculated on a multipollutant basis, where half the cost of control is 
assigned to the methane reduction and half to the VOC reduction. Table 
20 shows the cost effectiveness values for GHG (methane) and VOC, which 
is applicable for the determination of BSER for new sources. Table 21 
provides the cost effectiveness for GHG (methane) for existing sources. 
Further information regarding the cost effectiveness values for pumps 
may be found in the NSPS OOOOb and EG OOOOc TSD for this rulemaking, 
which is available in the docket for this action.

      Table 20--Summary of Cost Effectiveness Analysis of Pump Emissions Reduction Options for New Sources
----------------------------------------------------------------------------------------------------------------
                                                                  Cost effectiveness ($/ton) \a\
                                                 ---------------------------------------------------------------
    Location type and number of pumps at site            Single pollutant                 Multipollutant
                                                 ---------------------------------------------------------------
                                                      Methane           VOC           Methane           VOC
----------------------------------------------------------------------------------------------------------------
                                             Sites With Electricity
----------------------------------------------------------------------------------------------------------------
Electric pumps--production segment:
    One diaphragm...............................            $349          $1,256            $175            $628
    Two diaphragm...............................             349           1,256             175             628
    Three diaphragm.............................             349           1,256             175             628
    Four diaphragm..............................             349           1,256             175             628
Electric pumps--transmission and storage
 segment:
    One diaphragm...............................             267           9,650             134           4,825
    Two diaphragm...............................             267           9,650             134           4,825
    Three diaphragm.............................             267           9,650             134           4,825
    Four diaphragm..............................             267           9,650             134           4,825
Compressed air-driven pumps--production segment:

[[Page 16932]]

 
    One diaphragm...............................           3,202          11,517           1,601           5,758
    Two diaphragm...............................           1,711           6,156             856           3,078
    Three diaphragm.............................           1,215           4,369             607           2,185
    Four diaphragm..............................             966           3,476             483           1,738
Compressed air-driven pumps--transmission and
 storage segment:
    One diaphragm...............................           2,451          88,469           1,225          44,235
    Two diaphragm...............................           1,310          47,291             655          23,646
    Three diaphragm.............................             930          33,565             465          16,783
    Four diaphragm..............................             740          26,702             370          13,351
----------------------------------------------------------------------------------------------------------------
                                            Sites Without Electricity
----------------------------------------------------------------------------------------------------------------
Electric solar pumps--production segment:
    One diaphragm...............................             395           1,421             198             711
    Two diaphragm...............................             395           1,421             198             711
    Three diaphragm.............................             395           1,421             198             711
    Four diaphragm..............................             395           1,421             198             711
Electric solar pumps--transmission and storage
 segment:
    One diaphragm...............................             302          10,918             151           5,459
    Two diaphragm...............................             302          10,918             151           5,459
    Three diaphragm.............................             302          10,918             151           5,459
    Four diaphragm..............................             302          10,918             151           5,459
Compressed air-driven pumps with a generator--
 production segment:
    One diaphragm...............................           5,130          18,453           2,565           9,226
    Two diaphragm...............................           2,676           9,624           1,338           4,812
    Three diaphragm.............................           1,857           6,682             929           3,341
    Four diaphragm..............................           1,448           5,210             724           2,605
Compressed air-driven pumps with a generator--
 transmission and storage segment:
    One diaphragm...............................           3,927         141,752           1,963          70,876
    Two diaphragm...............................           2,048          73,933           1,024          36,966
    Three diaphragm.............................           1,422          51,326             711          25,663
    Four diaphragm..............................           1,109          40,023             554          20,011
Route pump emissions to process through existing
 VRU--production segment:
    One diaphragm...............................             472           1,699             236             849
    Two diaphragm...............................             472           1,699             236             849
    Three diaphragm.............................             472           1,699             236             849
    Four diaphragm..............................             472           1,699             236             849
Route pump emissions to process through existing
 VRU--transmission and storage segment:
    One diaphragm...............................             361          13,050             181           6,525
    Two diaphragm...............................             361          13,050             181           6,525
    Three diaphragm.............................             361          13,050             181           6,525
    Four diaphragm..............................             361          13,050             181           6,525
Route pump emissions to existing control device--
 production segment:
    One diaphragm...............................             497           1,788             249             894
    Two diaphragm...............................             497           1,788             249             894
    Three diaphragm.............................             497           1,788             249             894
    Four diaphragm..............................             497           1,788             249             894
Route pump emissions to existing control device--
 transmission and storage segment:
    One diaphragm...............................             381          13,737             190           6,869
    Two diaphragm...............................             381          13,737             190           6,869
    Three diaphragm.............................             381          13,737             190           6,869
    Four diaphragm..............................             381          13,737             190           6,869
Route pump emissions to process through new VRU--
 production segment:
    One diaphragm...............................           6,985          25,127           3,493          12,563
    Two diaphragm...............................           3,729          13,413           1,864           6,706
    Three diaphragm.............................           2,643           9,508           1,322           4,754
    Four diaphragm..............................           2,101           7,556           1,050           3,778
Route pump emissions to process through new VRU--
 transmission and storage segment:
    One diaphragm...............................           5,347         193,021           2,673          96,510
    Two diaphragm...............................           2,854         103,035           1,427          51,518
    Three diaphragm.............................           2,023          73,040           1,012          36,520
    Four diaphragm..............................           1,608          58,043             804          29,021

[[Page 16933]]

 
Route pump emissions to new control device--
 production segment:
    One diaphragm...............................           7,971          28,673           3,985          14,336
    Two diaphragm...............................           4,234          15,230           2,117           7,615
    Three diaphragm.............................           2,988          10,750           1,494           5,375
    Four diaphragm..............................           2,366           8,509           1,183           4,255
Route pump emissions to new control device--
 transmission and storage segment:
    One diaphragm...............................           6,101         220,258           3,051         110,129
    Two diaphragm...............................           3,241         116,997           1,620          58,499
    Three diaphragm.............................           2,287          82,577           1,144          41,289
    Four diaphragm..............................           1,811          65,367             905          32,684
----------------------------------------------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the savings for the natural gas that is not
  emitted and not lost. The cost effectiveness values shown in this summary table do not consider these savings.
  If the EPA were to consider these savings, then the cost effectiveness figures in the table ($/ton methane
  reduced) would reduce, which would mean the options assessed would be even more cost reasonable than already
  shown in this table.


   Table 21--Summary of Cost Effectiveness Analysis of Pump Emissions
                 Reduction Options for Existing Sources
------------------------------------------------------------------------
                                                  Cost effectiveness ($/
                                                         ton) \a\
   Location type and number of pumps at site    ------------------------
                                                         Methane
------------------------------------------------------------------------
                         Sites With Electricity
------------------------------------------------------------------------
Electric pumps--production segment:
    One diaphragm..............................                     $349
    Two diaphragm..............................                      349
    Three diaphragm............................                      349
    Four diaphragm.............................                      349
Electric pumps--transmission and storage
 segment:
    One diaphragm..............................                      267
    Two diaphragm..............................                      267
    Three diaphragm............................                      267
    Four diaphragm.............................                      267
Compressed air-driven pumps--production
 segment:
    One diaphragm..............................                    3,461
    Two diaphragm..............................                    1,731
    Three diaphragm............................                    1,154
    Four diaphragm.............................                      865
Compressed air-driven pumps--transmission and
 storage segment:
    One diaphragm..............................                    2,649
    Two diaphragm..............................                    1,325
    Three diaphragm............................                      883
    Four diaphragm.............................                      662
------------------------------------------------------------------------
                        Sites Without Electricity
------------------------------------------------------------------------
Electric solar pumps--production segment:
    One diaphragm..............................                      395
    Two diaphragm..............................                      395
    Three diaphragm............................                      395
    Four diaphragm.............................                      395
Electric solar pumps--transmission and storage
 segment:
    One diaphragm..............................                      302
    Two diaphragm..............................                      302
    Three diaphragm............................                      302
    Four diaphragm.............................                      302
Compressed air-driven pumps with a generator--
 production segment:
    One diaphragm..............................                    6,143
    Two diaphragm..............................                    3,072
    Three diaphragm............................                    2,048
    Four diaphragm.............................                    1,536
Compressed air-driven pumps with a generator--
 transmission and storage segment:
    One diaphragm..............................                    4,702
    Two diaphragm..............................                    2,351

[[Page 16934]]

 
    Three diaphragm............................                    1,567
    Four diaphragm.............................                    1,176
Route pump emissions to process through
 existing VRU--production segment:
    One diaphragm..............................                      251
    Two diaphragm..............................                      251
    Three diaphragm............................                      251
    Four diaphragm.............................                      251
Route pump emissions to process through
 existing VRU--transmission and storage
 segment:
    One diaphragm..............................                      192
    Two diaphragm..............................                      192
    Three diaphragm............................                      192
    Four diaphragm.............................                      192
Route pump emissions to existing control
 device--production segment:
    One diaphragm..............................                      264
    Two diaphragm..............................                      264
    Three diaphragm............................                      264
    Four diaphragm.............................                      264
Route pump emissions to existing control
 device--transmission and storage segment:
    One diaphragm..............................                      202
    Two diaphragm..............................                      202
    Three diaphragm............................                      202
    Four diaphragm.............................                      202
Route pump emissions to process through new
 VRU--production segment:
    One diaphragm..............................                    7,719
    Two diaphragm..............................                    3,985
    Three diaphragm............................                    2,740
    Four diaphragm.............................                    2,118
Route pump emissions to process through new
 VRU--transmission and storage segment:
    One diaphragm..............................                    5,908
    Two diaphragm..............................                    3,050
    Three diaphragm............................                    2,098
    Four diaphragm.............................                    1,621
Route pump emissions to new control device--
 production segment:
    One diaphragm..............................                    7,971
    Two diaphragm..............................                    4,234
    Three diaphragm............................                    2,988
    Four diaphragm.............................                    2,366
Route pump emissions to new control device--
 transmission and storage segment:
    One diaphragm..............................                    6,101
    Two diaphragm..............................                    3,241
    Three diaphragm............................                    2,287
    Four diaphragm.............................                    1,811
------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the
  savings for the natural gas that is not emitted and not lost. The cost
  effectiveness values shown in this summary table do not consider these
  savings. If the EPA were to consider these savings, then the cost
  effectiveness figures in the table ($/ton methane reduced) would
  reduce, which would mean the options assessed would be even more cost
  reasonable than already shown in this table.

    As seen in tables 20 and 21, for sites without electricity with 
three diaphragm pumps, the cost effectiveness values for all options 
fall within the ranges typically considered reasonable by the EPA. 
Specifically, for new sources at production sites, the single-pollutant 
cost effectiveness of solar-powered electric controllers is $395 per 
ton of methane and $1,421 per ton of VOC. For compressed air systems 
driven by a generator, the single-pollutant cost effectiveness value 
for methane is $1,857 per ton, which is considered reasonable, as are 
the multipollutant cost effectiveness values ($929 per ton of methane 
and $3,341 per ton of VOC). For the transmission and storage segment, 
the single-pollutant methane cost effectiveness for solar-powered 
electric controllers is $302 per ton and $1,422 per ton for compressed 
air systems driven by a generator. These are both within the range 
considered reasonable for methane.
    For existing sources without access to grid power, the methane cost 
effectiveness value for production sites with three diaphragm pumps is 
$395 per ton for solar-powered electric pumps and $2,048 per ton for 
compressed air systems powered by a generator. At transmission and 
storage sites, for the otherwise same sources (existing sources without 
electricity, with three diaphragm pumps), methane cost effectiveness 
values are $302 per ton for solar-powered electric pumps and $1,567 per 
ton for compressed air systems powered by a generator. These values are 
all within the ranges considered reasonable for methane.
    For sites without electricity with one or two diaphragm pumps, the 
cost effectiveness values for compressed air systems powered by a 
generator are not consistently within the range considered reasonable 
by the EPA. This leaves solar-powered electric pumps as the only option 
evaluated that has cost effectiveness values in the range

[[Page 16935]]

considered reasonable by the EPA for both the production and the 
transmission and storage segments. However, the EPA has some concerns 
about the technical feasibility of solar-powered pumps in some 
situations. Specifically, the Carbon Limits report, which was a 
reference the EPA relied upon for this analysis, states that ``[s]ites 
with a large number of pumps or with pumps with high energy or power 
demand may represent a challenge for 100 percent solar-powered electric 
systems. In addition, shortly after completion, some wells may require 
high volumes of methanol injection, and powering pumps to inject this 
high volume can strain these systems.'' \383\
---------------------------------------------------------------------------

    \383\ Carbon Limits. (2016) Zero emission technologies for 
pneumatic controllers in the USA--Applicability and cost 
effectiveness. Available at https://www.carbonlimits.no/wp-content/uploads/2017/01/Report_FINAL.pdf.
---------------------------------------------------------------------------

    While the EPA believes that solar-powered pumps are suitable for 
some applications, the EPA acknowledges concerns about their technical 
feasibility in some situations experienced at oil and gas sites. The 
EPA concluded that it is not appropriate to establish BSER based solely 
on solar-powered pumps. Therefore, the EPA created three subcategories: 
(1) Pumps at sites with access to electrical power, (2) pumps at sites 
without electrical service with three or more natural gas-driven 
diaphragm pumps, and (3) pumps at sites without electrical service with 
fewer than three natural gas-driven diaphragm pumps. The BSER 
determinations for these categories are discussed below. These 
determinations apply for both new and existing sources.
a. Pumps at Sites With Access to Electrical Power
    The options evaluated for sites with electrical power are electric 
pumps and pneumatic pumps driven by compressed air systems. The EPA 
considers both of these options to be adequately demonstrated. For all 
scenarios at sites with electricity, the cost effectiveness values are 
within the range considered reasonable by the EPA (see tables 20 and 
21). There could be secondary air impacts associated with the 
generation of the additional electricity, but those impacts are 
expected to be negligible. See the NSPS OOOOb and EG OOOOc TSD for this 
rulemaking for a discussion of these impacts. In conclusion, the EPA 
determined that a zero-emissions standard represents the BSER for pumps 
at sites with access to electrical power. This includes all diaphragm 
and piston pumps included in the affected facility at the site.
b. Pumps at Sites Without Electrical Service With Three or More Natural 
Gas-Driven Diaphragm Pumps
    The options evaluated for sites without access to electrical power 
are solar-powered electric pumps and pumps driven by compressed air 
systems powered by a generator. As discussed above, the EPA considers 
pumps driven by compressed air systems powered by a generator to be 
adequately demonstrated. While the EPA recognizes the technical 
limitations of solar-powered pumps for some applications, the EPA finds 
that they are an option for many sites. For all scenarios where three 
or more diaphragm pumps are present at a site without electricity, the 
cost effectiveness values for both solar-powered pumps and compressed 
air systems are within the range considered reasonable by the EPA (see 
tables 20 and 21). There will be secondary air impacts associated with 
the use of generators, but based on a site-specific analysis, the EPA 
concludes that the benefits of the methane and VOC reductions outweigh 
the potential negative impacts. See section XI.D.2 of this document and 
the NSPS OOOOb and EG OOOOc TSD for this rulemaking for a discussion of 
these secondary air impacts from generators. While not shown here, for 
sites without access to electrical power that contain only piston 
pumps, the EPA did not identify any control options resulting in zero 
emissions that were considered cost effective. However, if a non-
natural-gas zero-emissions system is installed to reduce diaphragm pump 
emissions, it would be cost effective to also use zero-emissions piston 
pumps. Therefore, the BSER determination for pumps at sites without 
access to electrical power and three or more diaphragm pumps is zero 
emissions of GHG (methane) and VOC. This is the BSER determination 
regardless of the number of piston pumps at the site. In conclusion, 
the EPA determined that BSER for pumps at sites with three or more 
diaphragm pumps without access to electrical power is zero emissions of 
methane and VOC from all diaphragm and piston pumps at the site.
c. Pumps at Sites Without Access to Electrical Power With Fewer Than 
Three Natural Gas-Driven Diaphragm Pumps
    As discussed above, given the EPA's conclusion that solar-powered 
pumps are not technically feasible for some common applications and the 
fact that the analysis did not show cost effectiveness values of a 
compressed air system powered by a generator to be consistently within 
the range that the EPA considers reasonable at sites with fewer than 
three diaphragm pumps, the EPA concludes that a zero-emissions standard 
does not reflect the BSER for sites without access to electrical power 
that have fewer than three diaphragm pumps.
    For this subcategory, the EPA evaluated other emissions control 
options, including routing the emissions to a process and routing the 
emissions to a combustion device. In most cases, a VRU will be required 
to enable the captured gas from the pump to be routed to a process. 
Therefore, costs were estimated for installing a closed vent system and 
VRU in order to route the gas to a process. It was assumed that this 
would achieve a 100 percent reduction in methane and VOC emissions. 
Costs were also estimated to install a closed vent system and a new 
combustion device to reduce the emissions, assuming a methane and VOC 
reduction of 95 percent. The EPA considers both routing emissions to a 
process and routing emissions to a combustion device to be adequately 
demonstrated emissions reduction techniques. As shown in tables 20 and 
21, both options of routing emissions to a process via a new VRU or to 
a new combustion device have cost effectiveness values outside the 
ranges the EPA considers reasonable. Therefore, the EPA concludes that 
requiring the installation of a new VRU or control device for pumps at 
these sites is not the BSER.
    The EPA also evaluated routing emissions through an existing VRU to 
a process (or routing directly to a process if that is possible) and 
routing emissions to an existing combustion device. Both of these 
options are adequately demonstrated since the emissions reduction 
technique is already being used for other equipment at the site. 
Further, the cost effectiveness of both options is in the range 
considered reasonable by the EPA. Therefore, the EPA concludes that, 
for sites without access to electricity and fewer than three diaphragm 
pumps, the BSER is routing to a process where an existing VRU is 
available or to a combustion device where an existing one is available.
d. Summary of Final Rule
    Considering our revised analysis and BSER determinations, for 
affected and designated facilities at sites with access to electrical 
power and at sites without access to electrical power with three or 
more diaphragm pumps, the final rule and presumptive standard require 
these facilities to have zero GHG (methane)

[[Page 16936]]

and VOC emissions from all diaphragm and piston pumps. Zero emissions 
may be achieved either by using pumps not powered by natural gas (and 
thus not an affected or designated facility) or by routing natural gas-
driven pump emissions through a CVS to a process. As explained in the 
December 2022 Supplemental Proposal, the EPA understands that emissions 
routed through a CVS to a process would achieve a 100 percent emissions 
reduction from the pumps and therefore would meet a zero-emissions VOC 
and GHG standard. Like what was included in the supplemental proposal, 
the CVS demonstration requirements that there are no identifiable 
emissions from the CVS apply in the final rule. Unlike what was 
proposed, the final rule does not require a demonstration that using 
pumps not driven by natural gas is infeasible before compliance by 
routing emissions to a process is allowed.
    For sites without access to electrical power with fewer than three 
diaphragm pumps, the final requirements are that natural gas-driven 
pump emissions must be routed through a CVS to a process if the site 
has a VRU, but if the site does not have a VRU, emissions can be routed 
to an onsite control device that achieves a 95 percent emissions 
reduction. If there is no control device onsite that achieves a 95 
percent emissions reduction, emissions must be routed to a control 
device(s) onsite that achieves less than a 95 percent emissions 
reduction. If no VRU or control devices are onsite, emissions from 
natural gas-driven pumps are not required to be controlled. A summary 
comparison of the emissions standards included in the December 2022 
Supplemental Proposal and the final rule is included in table 22.

 Table 22--Comparison of Pump NSPS Standards and EG Presumptive Standards Between the Supplemental Proposal and
                                                 the Final Rule
----------------------------------------------------------------------------------------------------------------
                                      Supplemental proposal
                                       affected/designated    Final rule affected/
   Standard/presumptive standard          facility site        designated facility          Difference(s)
                                         characteristics      site characteristics
----------------------------------------------------------------------------------------------------------------
Zero emissions.....................  Sites with electricity  Sites with electricity  Supplemental proposal
                                                              and Sites with >=3      required non-natural gas-
                                                              diaphragm pumps.        driven pumps; final rule
                                                                                      allows non-natural gas-
                                                                                      driven pumps and/or
                                                                                      routing pump emissions
                                                                                      through CVS to a process
                                                                                      and/or other control means
                                                                                      that achieves zero
                                                                                      emissions.
95 percent control.................  Sites without           No sites..............  95 percent emissions
                                      electricity and >=4                             reduction required under
                                      diaphragm pumps.                                supplemental proposal
                                                                                      after demonstrations that
                                                                                      it is technically
                                                                                      infeasible to use non-gas
                                                                                      driven pump, and to route
                                                                                      emissions through a CVS to
                                                                                      a process; 95 percent
                                                                                      emissions reduction not
                                                                                      directly required for any
                                                                                      sites in the final rule.
Route emissions to existing control  Sites without           Sites without           Use of control device
 device.                              electricity and <4      electricity and <3      required under
                                      diaphragm pumps.        diaphragm pumps.        supplemental proposal
                                                                                      after demonstrations that
                                                                                      it is technically
                                                                                      infeasible to use non-gas
                                                                                      driven pump and to route
                                                                                      emissions to a process;
                                                                                      technical infeasibility
                                                                                      demonstrations not
                                                                                      required in final rule,
                                                                                      but final rule requires
                                                                                      routing emissions to a
                                                                                      process if a VRU is onsite
                                                                                      before a control device
                                                                                      can be used.
----------------------------------------------------------------------------------------------------------------

    It should be noted that there are similarities between the BSER 
analyses for natural gas-driven pumps and natural gas-driven process 
controllers. For both types of sources, the EPA evaluated a number of 
options that are not powered by natural gas and thus have zero methane 
and VOC emissions. As discussed above, for sites without access to 
electrical power with fewer than three diaphragm pumps, there are no 
cost-effective zero-emissions control options that the EPA found to be 
adequately demonstrated. For pumps at these sites, the only zero-
emissions option with values the EPA considers to be cost-effective was 
solar-powered pumps. Given the power needs for some pumps to properly 
operate and the potential inadequacies of solar-powered systems to 
provide that amount of energy, the EPA determined that solar-powered 
systems do not represent BSER for pumps. Therefore, the EPA created a 
subcategory for sites without access to electrical power and fewer than 
three pumps and established different emissions control requirements 
for that subcategory. In contrast, for controllers, there was more than 
one adequately demonstrated zero-emissions option evaluated for every 
sized model plant throughout the sectors with cost effectiveness values 
considered reasonable. Therefore, even if there are power limitations 
for solar-powered process controllers, which require much less energy 
than pumps to properly operate, there are other cost-effective zero-
emissions options available, and consideration of other emissions 
control options or subcategories of process controller affected 
facilities was not necessary.
    Comment: In the December 2022 Supplemental Proposal, the EPA 
proposed a hierarchy of emissions control requirements for sites that 
did not have access to electrical power. Under this approach, the EPA 
proposed that an owner or operator would be required to first evaluate 
pump options that do not use natural gas and provide a certified 
demonstration that such options are infeasible before being allowed to 
use the next tier of emissions control options. For instance, at sites 
without access to electrical power, the proposal allowed for pump 
emissions to be routed to a process, but only after certified 
assessments were made demonstrating that it was technically infeasible 
to use solar-powered pumps and infeasible to use pumps powered by 
compressed air. One commenter stated that the EPA should remove the 
certifications associated with the hierarchy of pump compliance 
options. The commenter stated that the proposed certification 
requirements are unreasonably onerous because, in each case, the 
certifying individual must essentially prove a negative--that the 
otherwise applicable zero-emissions approaches are ``technically 
infeasible.'' The commenter stated that there is no definition of 
technical infeasibility in the proposed rule, but the words could be 
construed as setting an exceedingly

[[Page 16937]]

high bar, such that a given non-emitting technique is ``infeasible'' 
based solely on a technical assessment of whether it can theoretically 
be physically applied in the given situation, even though it could be 
inordinately expensive. According to the commenter, this outcome would 
not be lawful because it would violate the statutory requirement that 
BSER and the corresponding standard of performance must be cost-
effective. The commenter added that a ``technical infeasibility'' 
standard allows for second-guessing by regulators or citizen enforcers, 
which invites a ``battle of the experts'' in potential enforcement 
actions. According to the commenter, this diminishes the possibility 
that the opt-outs can be implemented with reasonable certainty.
    The commenter also reported that the express threat of possible 
personal liability on the part of certifiers will limit the number of 
individuals willing to make the needed certifications, particularly 
considering the uncertainties about what will be needed as a practical 
matter to demonstrate ``technical infeasibility.'' The commenter stated 
that the clear opportunity and possibility of second-guessing will be 
further material disincentives.
    Response: In consideration of these comments, the EPA reviewed the 
proposed ``certification of infeasibility'' requirements. The EPA 
restructured the final standards for pumps based on comments received 
on the December 2022 Supplemental Proposal. The final rule no longer 
includes the complex hierarchy of technical feasibility demonstrations 
that was included in the December 2022 Supplemental Proposal. Instead, 
the final rule includes a subcategory based on clear criteria such that 
sources can be certain as to which emissions standards apply without 
demonstrations of technical infeasibility.
    Comment: One commenter mentioned that the EPA proposed to allow 
operators to route natural gas-driven pump emissions to a control 
device, but only if the operators can demonstrate that routing to a 
process is technically infeasible and that it is infeasible to use 
pumps not driven by natural gas. The commenter urged the Agency to 
recognize the substantial investments that operators have already made 
to route emissions from pumps to control devices by allowing any 
natural gas-driven pump to be routed to controls--not only in 
situations where non-natural-gas technology and routing to a process 
are each technically infeasible.
    Response: As explained above, for the final rule we have removed 
the proposed requirement for demonstrations of technical infeasibility 
before the use of other equivalent control options may be used for 
pumps. In the final rule, we have further added the conditions under 
which pump emissions may be routed to a control device, which reflect 
our BSER determinations. For sites without access to electrical power 
and that have two or fewer diaphragm pumps, pump affected facility 
emissions may be routed to a control device if there is no VRU onsite.
2. Compliance Dates
    Comment: Two commenters state that a 60-day compliance deadline for 
new/modified sources is unrealistic due to supply chain concerns, 
personnel shortages, and inflation. Due to supply chain shortages and 
disruption, one commenter reports that companies are experiencing 
backorders for some equipment, including non-natural-gas-driven pumps, 
generator skids, and air compressor skids, with current lead times 
ranging up to 12 months. The commenters note that there is no 
indication that this lead time will improve in the near future and 
believe it can be expected to worsen as owners and operators across the 
country increase demand in response to the final rule. One commenter 
recommended a compliance deadline of 12 to 26 months from the 
publication date of the final rule and one commenter proposed at least 
a 1-year timeframe for NSPS OOOOb compliance to allow for procurement 
and installation of the systems and equipment necessary (including 
labor necessary for installation).
    One commenter requested that the EPA extend implementation 
timelines--particularly for sources that became NSPS OOOOb affected 
facilities prior to the date of final rule publication. The commenter 
remarked that until the effective date of NSPS OOOOb, some of these 
facilities would be unregulated under an existing NSPS or would begin 
operating as NSPS OOOOa affected facilities and may then need to 
complete retrofits to comply with newly applicable NSPS OOOOb 
standards. For example, the commenter states that NSPS OOOOa pneumatic 
pumps are not subject to a zero-emissions standard but would be subject 
to zero-emissions standards under NSPS OOOOb, requiring retrofit within 
60 days after the final rule's publication in the Federal Register. 
According to the commenter, this is not enough time to acquire retrofit 
equipment that will be in high demand, and likely short supply, as 
operators across the country place orders for equipment to meet the 
zero-emissions standard. In addition, the commenter reports that 
operators must acquire engineering resources to engineer the 
installation of zero-emissions pneumatic systems. They report that 
these engineering resources, too, are likely to be in high demand and 
short supply. The commenter asserts that the timing of compliance 
obligations is particularly pronounced for pneumatic pumps, as 
according to the commenter, operators may no longer use pneumatic pumps 
that are driven by natural gas, subject to limited exceptions. The 
commenter notes that the November 2021 Proposal did not go so far as to 
eliminate the use of natural gas-driven pneumatic pumps entirely. The 
commenter states that operators may need to completely replace natural 
gas-driven pneumatic pumps that would have complied with the standards 
described in the November 2021 Proposal.
    Response: Based on these comments, and for the same reasons 
explained in section XI.D.4 of this preamble for process controllers, 
the EPA is finalizing a NSPS compliance deadline for pumps required to 
meet a zero-emissions standard that allows for up to 1 year from the 
effective date of the final rule.
    The equipment that owners and operators will need to comply with 
the final standard of zero emissions for pumps is, in some situations, 
the same equipment that owners and operators will need to comply with 
the final standard for process controllers. Based on comments, it 
appears that some equipment necessary for the installation of zero-
emitting pumps may not be available quickly enough, and in large enough 
quantities, to enable new sources to comply with the final standard 
upon startup, or within 60 days after the publication of the final 
NSPS. As is the case for process controllers, the equipment types that 
the EPA believes are necessary to comply with the final zero-emissions 
standard for pumps in NSPS OOOOb are quite different from the type of 
equipment used to comply with the standards for these sources found in 
NSPS OOOOa. Due to these considerations, the EPA is not certain that 
new sources needing to meet the zero-emissions standard could obtain 
the equipment necessary to demonstrate compliance on the proposed 
timeline. This change to the final rule compliance timeline in NSPS 
OOOOb for pumps does not apply to sites without access to grid 
electricity that have fewer than three diaphragm pumps because those 
sites are not required to demonstrate zero emissions.
    Until the final date of compliance with the zero-emissions 
standard,

[[Page 16938]]

owners/operators must demonstrate compliance with an interim standard 
which mirrors the requirements for pumps at sites without access to 
grid electricity that have fewer than three diaphragm pumps found at 40 
CFR 60.5393b(b). In summary, the standards for these sites require that 
GHG and VOC emissions from all natural gas-driven pumps in the affected 
facility be routed to a process if a VRU is onsite. If a VRU is not 
onsite, emissions must be reduced by 95 percent if a control device 
with at least this emissions reduction capability is already available 
onsite or may be reduced by less than 95 percent if a control device is 
onsite but is not capable of reducing GHG and VOC emissions by 95 
percent or more. As these requirements are similar to the current NSPS 
OOOOa requirements for pumps at well sites, owners/operators of new and 
recently modified or reconstructed sites subject to NSPS OOOOb will be 
able to readily obtain the equipment necessary for this interim 
standard, to the extent that equipment is even necessary. The only 
difference compared to NSPS OOOOa is that NSPS OOOOb requires emissions 
to be routed to a process if a VRU is already on the site. The 
information available to the EPA and provided by commenters does not 
suggest any equipment backlogs for common piping that may be needed to 
route emissions to a process through a VRU. Complying with the interim 
standard described above does not require using the equipment that 
commenters claimed they could not easy obtain (i.e., the equipment 
needed to meet the zero-emissions standard). Therefore, the EPA expects 
no sites to have any problems complying with these interim requirements 
within 60 days after publication of the final rule. If an owner or 
operator opts to comply with the interim standard during the one year 
following publication of the final rule, then they must still comply 
with the final zero-emissions standard after the year has passed. 
Owners and operators can, and are encouraged to, comply with the final 
zero-emissions standard before the year has passed.
3. Recordkeeping and Reporting Requirements for Pumps Not Included in 
the Affected Source
    Comment: Commenters pointed out that 40 CFR 60.5410b(g)(1) requires 
owners and operators to submit an identification of all pumps that are 
not powered by natural gas in the initial annual report required by 40 
CFR 60.5420b(b)(10)(i), and such pumps are not part of the pumps 
affected facility definition. The commenters recommended that owners or 
operators only be required to maintain records sufficient to determine 
compliance with the regulations. The commenters contend that having 
requirements for equipment that is not part of an affected source 
exceeds the EPA's authority granted under CAA section 111 and add that 
there is no environmental benefit to keeping or submitting information 
for equipment that cannot have emissions. The commenters recommended 
that the EPA remove any reporting or recordkeeping requirements for 
these pumps from the final regulations.
    Response: After considering this comment, we have determined that 
it is appropriate in this instance to require identification of the 
equipment that is included in the affected facility, rather than the 
equipment that is not part of the affected facility. The pumps included 
in the affected facility are those that are subject to the emissions 
standards in the rule, whereas pumps not included in the affected 
facility are not subject to the emissions standards in the rule and 
also have no potential to emit methane or VOCs. Therefore, we have 
revised the recordkeeping requirements to require identification only 
of pumps that meet the finalized definition of an affected facility, 
which are those pumps that are driven by natural gas and that are in 
operation for 90 days or more in a calendar year.
4. Modification and Reconstruction Criteria and Requirements
    Comment: Commenters requested that the EPA clarify that, for 
purposes of the collection of controllers or pumps at a site, a 
modification occurs only when a natural gas-driven pump is added. The 
commenters pointed out that the addition of a pump not driven by 
natural gas would not increase emissions from the affected source. 
Commenters also requested that the EPA clarify which pumps would be 
considered in the determination of whether a reconstruction has taken 
place.
    Response: While it was our intention in the December 2022 
Supplemental Proposal to only include the addition of natural gas-
driven pumps in the conditions that would constitute a modification, as 
only those pumps could increase emissions, we agree that the proposed 
regulatory text did not specify this. We therefore have updated what we 
proposed for regulatory language to clarify that the addition of one or 
more natural gas-driven pumps to a site constitutes a modification. We 
also are clarifying in the final rule that reconstruction would be 
considered to occur whenever greater than 50 percent of the number of 
existing onsite natural gas-driven pumps are replaced.
    Comment: In addition to these clarifications regarding the criteria 
for determining whether a modification or reconstruction has taken 
place, one commenter stated that it is unclear how the notification 
requirements of 40 CFR 60.15 apply for reconstruction. The commenter 
noted that the proposed language in 40 CFR 60.5365b(d)(2)(ii) suggests 
that reconstructed natural gas-driven pumps would be subject to some of 
the requirements included in 40 CFR 60.15, which include 60-day 
notification and Administrator approval. According to the commenter, 
this conflicts with information presented in table 5 of the regulatory 
text, which states that 40 CFR 60.15(d) does not apply to pumps. The 
commenter believes it was the EPA's intent to not apply the additional 
notification and approval, given the number of facilities that will 
trigger reconstruction over time.
    Response: We agree that we did not intend for facilities to be 
required to notify the Administrator of upcoming pump replacements that 
would constitute a reconstruction or for the Administrator to be 
required to review the notification and determine whether the 
replacements constitute a reconstruction. We have updated what we 
proposed for regulatory text to not refer to the requirements of 40 CFR 
60.15(d) and have kept the information presented in table 5 of the 
proposed regulatory text, which states that 40 CFR 60.15(d) does not 
apply to pumps.
5. Change in Pneumatic Pump Terminology
    In addition to the revisions to the modification and reconstruction 
criteria and requirements for pumps, to assist with avoiding possible 
confusion about which types of pumps are included within the definition 
of the affected facility and which types of pumps must be considered 
for purposes of the reconstruction and modification provisions, we have 
changed the terminology of ``pneumatic pumps'' (used in both the 
November 2021 Proposal and the December 2022 Supplemental Proposal) to 
simply ``pumps'' in the final rule. The EPA has made this change both 
in the final rule preamble and the final regulatory text. The term 
``pumps'' is broader in scope because it includes pneumatic pumps as 
well as other types of pumps that are not pneumatic. Only a subset of 
pumps used by oil and gas facilities are pneumatic pumps that use 
pressurized air or gas to perform their functions. Other pumps might 
use electricity to

[[Page 16939]]

perform their functions. From a technical perspective, electronic pumps 
are not true ``pneumatic'' devices, but these electronic pumps can be 
used to achieve the zero-emissions standard. The EPA changed the 
terminology because we did not want to inadvertently convey that 
misimpression that pumps had to be pneumatic. To be clear, the final 
rule applies to the collection of natural gas-driven pumps. Pumps that 
are not driven by natural gas are not included in the affected 
facility. Further, only pumps driven by natural gas will be counted 
when determining whether a modification or reconstruction has occurred.

F. Wells and Associated Operations

    In the December 2022 Supplemental Proposal, the EPA proposed to 
define a well affected facility, and well designated facility, to 
consist of a single well. The EPA also proposed standards for well 
affected facilities and designated facilities for oil wells with 
associated gas, gas wells that undergo liquids unloading, and wells 
that undergo completions. A summary of the comments received and the 
EPA's response to these comments, including any changes made to the 
final rule, as applicable, are provided below. The EPA's full response 
to comments on the November 2021 Proposal and December 2022 
Supplemental Proposal, including any comments not discussed in this 
preamble, can be found in the EPA's RTC document for the final 
rule.\384\
---------------------------------------------------------------------------

    \384\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

1. Well Affected Facility and Designated Facility Definitions
    In the December 2022 Supplemental Proposal, rather than including 
three separate definitions for well affected facilities (as initially 
proposed in the November 2021 Proposal) for (1) oil wells with 
associated gas, (2) gas wells that undergo liquids unloading, and (3) 
wells that undergo completions, the EPA proposed a single definition 
for a well affected facility, which was defined as a single well, in 
the proposed NSPS OOOOb. A well is defined as a hole drilled for the 
purpose of producing oil or natural gas. The EPA proposed separate 
standards for well completions, associated gas from oil wells, and gas 
well liquids unloading operations, all or some of which could apply to 
a given well affected facility. A well affected facility would be 
required only to comply with the standards that are applicable to the 
well. For example, a gas well would not be subject to the standard for 
oil wells with associated gas. The proposed NSPS OOOOb specified that a 
modification to an existing well occurs when the definition of 
modification in 40 CFR 60.14 is met, including when an existing well 
undergoes hydraulic fracturing or refracturing.
    For the EG OOOOc rule, the EPA proposed, similar to NSPS OOOOb, a 
definition of well designated facility as a single well. Modification 
provisions do not apply under EG OOOOc. The December 2022 Supplemental 
Proposal included proposed presumptive standards for associated gas 
from oil wells and gas well liquids unloading. However, since the 
fracturing or refracturing of an existing well would constitute a 
modification under NSPS OOOOb, which would make the well a well 
affected facility under NSPS OOOOb, there would never be an existing 
well subject to well completion requirements and no requirements are 
specified for well completions under EG OOOOc. More discussion of the 
well affected facility/designated facility specific to each of the 
three associated well operations is provided in sections X.F.2, 3, and 
4 of this document.
    The EPA did not receive comments on the proposed definition of a 
well affected facility or designated facility that warranted changes to 
what was proposed in the December 2022 Supplemental Proposal. 
Therefore, the definitions have been finalized as proposed.
2. Associated Gas From Oil Wells
    In section X.F.2 of this document, the final NSPS OOOOb and EG 
OOOOc requirements for oil wells with associated gas are summarized. 
The EPA received many comments on the December 2022 Supplemental 
Proposal on the following topics: the definition of associated gas, the 
BSER analysis for new wells, BSER for existing wells, temporary venting 
and flaring, and the infeasibility determination and certification. For 
each of these topics, a summary of the proposed rule, the comments, the 
EPA responses, and changes made in the final rule (if applicable), are 
discussed here. These comments and the EPA's responses to these 
comments generally apply to the standards and presumptive standards in 
both the NSPS OOOOb and EG OOOOc respectively. The instances where the 
comment and/or response only applies to NSPS OOOOb or EG OOOOc are 
noted. The EPA's full response to comments on the November 2021 
Proposal and December 2022 Supplemental Proposal, including any 
comments not discussed in this preamble, can be found in the EPA's RTC 
document for the final rule.\385\
---------------------------------------------------------------------------

    \385\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

a. Definition of Associated Gas
    Neither the November 2021 Proposal nor the December 2022 
Supplemental Proposal included a definition of ``associated gas.''
    Comment: Several commenters \386\ suggested that a definition of 
``associated gas'' be added. Commenters expressed that it is important 
for the EPA and the regulated community to have a common understanding 
of the definition of associated gas. One commenter added that, without 
a definition, the term ``associated gas'' could take on various 
meanings including the most literal interpretation of any gas 
associated with oil well production, which might include emissions from 
other NSPS OOOOb or EG OOOOc affected/designated facility types that 
the EPA regulates in other sections of its proposal--e.g., a collection 
of fugitive emissions components or storage vessels. Commenters 
provided several suggestions for this definition, including:
---------------------------------------------------------------------------

    \386\ EPA-HQ-OAR-2021-0317-2248, -2294, -2326, -2360, and -2428.
---------------------------------------------------------------------------

    <bullet> Associated gas means the gas that can be separated from 
the produced liquids in the first stage of separation at a pressure 
sufficient for it to flow into the gathering system.
    <bullet> Associated gas means the natural gas which originates at 
wells operated primarily for oil production and occurs either in a 
discrete gaseous phase at the wellhead or is released from the liquid 
hydrocarbon during the initial stage of separation after the wellhead.
    <bullet> Associated gas means the natural gas which originates at 
oil wells operated primarily for oil production and occurs either in a 
discrete gaseous phase at the wellhead or is released from the liquid 
hydrocarbon during the initial stage of separation after the wellhead.
    <bullet> Associated gas means the natural gas evolved from 
hydrocarbon liquids during the initial stage of separation following 
production from the wellhead. Associated gas does not

[[Page 16940]]

include natural gas associated with well completion or downhole well 
maintenance activities.
    Response: The EPA agrees with the commenters that a definition of 
associated gas would be beneficial to provide clarity to regulatory and 
enforcement agencies and to the regulated community. First, our 
intention is to regulate the gas that is released from the liquid at 
the first stage of separation, so we included that characteristic in 
the definition in the final NSPS OOOOb and EG OOOOc.
    One commenter suggested that the EPA define associated gas by using 
the phrase ``in a discrete gaseous phase at the wellhead,'' arguing 
that this description is necessary to avoid a broad interpretation of 
associated gas that encompasses any gas associated with oil well 
production. The EPA believes that the commenter's suggested language is 
not necessary to clearly define associated gas and believes that it 
could add confusion.
    We do not believe that the most literal interpretation offered by 
the commenter that any gas associated with oil well production might be 
considered associated gas, and we do not feel a need to include such a 
clarification in the definition. However, we recognize that there could 
be confusion between the emissions associated with well completions and 
associated gas. This is particularly the case in situations where a 
permanent separator has been placed onsite during the completion 
activities and used during the separation flowback stage. The 
definition of flowback in 40 CFR 60.5430b of the final rule specifies 
that the flowback period ends when either the well is shut in and 
permanently disconnected from the flowback equipment or at the startup 
of production. This provides a clear distinction between when the 
completion flowback requirements end and the associated gas production 
begins. Therefore, the final definition of associated gas includes the 
phrase, ``Associated gas production begins at the startup of production 
after the flowback period ends.'' The full definition of ``associated 
gas'' for this final rule is included below and can also be found at 40 
CFR 60.5430b and 40 CFR 60.5430c.
    Comment: One commenter \387\ requested that the EPA allow certain 
provisions for wildcat or delineation wells in its proposal with 
respect to the associated gas from oil well provisions. The commenter 
explains that such wells are exploratory in nature and are typically 
located in remote locations far from any form of permanent 
infrastructure, including gathering infrastructure. Wildcat or 
delineation wells will typically only produce for a short period of 
time after flowback ends in order to complete well testing, which is 
used to determine the production flow rate along with other parameters 
such as the gas composition before the well is shut in or capped in 
accordance with state protocols. According to the commenter, in many 
instances an operator will not know or understand the composition of 
the gas until after the well is drilled. The commenter suggests that 
this combination of characteristics makes it impracticable to install 
gas gathering infrastructure or plan for other forms of beneficial use 
at a wildcat or delineation well. Noting that the EPA has exempted such 
wells from NSPS OOOOa standards for well completions, the commenter 
recommends that the EPA allow special considerations for handling 
associated gas since these activities are exploratory in nature and are 
typically not located near existing infrastructure.
---------------------------------------------------------------------------

    \387\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA acknowledges that the types of associated gas 
wells that are the focus of these rule requirements are wells that 
consistently produce, and potentially emit, natural gas. The temporary 
nature of wildcat and delineation wells is not conducive to warrant the 
construction of piping to connect to a natural gas gathering system or 
to utilize another solution where the gas could be used. Further, as 
noted by the commenter, the owners and operators of wildcat or 
delineation wells typically do not have knowledge of the nature and 
composition of the gas until after the well is drilled, which further 
hinders the ability to implement a beneficial-use solution. Therefore, 
the EPA has clarified in the definition of associated gas that gas from 
wildcat or delineation wells, which are defined in 40 CFR 60.5430b, is 
not associated gas for purposes of regulation under NSPS OOOOb and EG 
OOOOc. In response to these comments, the final rule includes the 
following definition in 40 CFR 60.5430b and 40 CFR 60.5430c:
b. BSER Analysis for New Wells
    In the November 2021 Proposal, the EPA determined that the BSER for 
associated gas was routing the associated gas from oil wells to a sales 
line. In the preamble for the November 2021 Proposal (86 FR 63236-39), 
and in the associated TSD, the EPA evaluated several equivalent options 
that would all effectively eliminate direct emissions of VOC and 
methane from associated gas, including routing the associated gas to a 
sales line, utilizing the associated gas in a ``beneficial'' manner, 
and reinjecting the gas. Regarding the cost impacts of routing the gas 
to a sales line, the EPA assumed ``that in situations where gas sales 
line infrastructure is available, there is minimal cost to owners and 
operators to route the associated gas to the sales line. While 
situations at well sites can differ, which would impact this cost, the 
EPA believes that in every situation the value of the natural gas 
captured and sold would outweigh these minimal costs of routing the gas 
to the sales line, thus resulting in overall savings.'' 86 FR 63237. 
The EPA then concluded with, ``Given the prevalence of this practice, 
the environmental benefit, and the economic benefits to owners and 
operators, the EPA concludes that BSER is routing associated gas from 
oil wells to a sales line.'' 86 FR 63237. However, in 2021, the EPA 
also recognized that there are situations where there would not be 
access to a sales line and therefore also evaluated the costs and 
impacts of routing associated gas to a flare.
    In the December 2022 Supplemental Proposal, the EPA again 
determined that BSER was routing the associated gas to a sales line and 
again proposed this requirement. The supplemental proposal also 
included that ``[i]f access to a sales line is not available, the gas 
can be used as an onsite fuel source or used for another useful purpose 
that a purchased fuel or raw material would serve. If demonstrated that 
a sales line and beneficial uses are not technically feasible, the gas 
can be routed to a flare or other control device that achieves at least 
95 percent reduction in methane and VOC emissions.'' 87 FR 74710.
    While no comments were received on the EPA's earlier assertion in 
the November 2021 Proposal that there would be minimal cost to route 
the gas to an available sales line, comments were received on the 
flaring analysis. As a result of these comments, the EPA updated the 
flaring analysis in the December 2022 Supplemental Proposal. This 
updated flaring analysis assumed an initial capital cost of $100,579 to 
install a new flare, which was the recommended cost provided by a 
commenter. Assuming a 7 percent interest rate and 10-year capital 
recovery period, along with an annual maintenance and operational cost 
of $25,000, the estimated annual cost was $36,044. Details of this cost 
estimate are included in the TSD for the December 2022 Supplemental 
Proposal.
    The EPA also updated the analysis of the associated gas emissions 
in the December 2022 Supplemental Proposal because the analysis 
performed for the

[[Page 16941]]

November 2021 Proposal included emissions from associated gas wells 
that the EPA concluded were not representative of ``routine'' venting 
situations. The resulting analysis was a representative well with 
uncontrolled potential associated gas emissions of 343.6 tpy of methane 
and 96 tpy of VOC. The details of this analysis may also be found in 
the TSD for the December 2022 Supplemental Proposal.
    Comments were received on the December 2022 Supplemental Proposal 
related to the representative baseline emissions analysis and the 
assumption that the costs of routing to a sales line or other 
beneficial use were minimal.
i. Baseline Emissions for Representative Well
    Comment: One commenter \388\ stated that the EPA seemed to bias the 
data selected for baseline emissions to fit their expectation rather 
than using actual reported data. The commenter cited section 6.3.1 of 
the supplemental proposal TSD.
---------------------------------------------------------------------------

    \388\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: In the TSD for the December 2022 Supplemental Proposal, 
the EPA identified 95 facilities/basins that reported associated gas 
venting emissions (through GHGRP subpart W data) for 2019. For each 
facility/basin, the number of wells venting is reported, along with the 
total methane vented from all wells. For each facility/basin, we 
calculated the average emissions per well. These average well emissions 
ranged from 0.015 tpy to over 2,400 tpy. Almost 20 percent of the 
facilities/basins had average well methane emissions lower than 0.2 
tpy.
    Explanations of the specific causes of emissions are not provided 
in the GHGRP subpart W outputs, but it would be expected that routine 
venting of associated gas would result in emissions greater than this 
level as the DOE indicates that the average associated gas production 
for an oil well is around 7.5 boe per day,\389\ which would be around 
450 tons of methane emissions per year. In order to avoid selecting a 
well associated gas venting level that was unreasonably low, a weighted 
average well emissions level was calculated, using the total emissions 
from the facility/basin as the weighting factor. The result is an 
estimated average annual methane emissions level of 344 tpy. Applying 
the representative composition yields a representative VOC emissions 
level of 96 tpy.
---------------------------------------------------------------------------

    \389\ https://www.eia.gov/petroleum/wells/pdf/full_report.pdf.
---------------------------------------------------------------------------

    The intention of the analysis that the commenter discusses was to 
develop an emissions level estimate that represented the routine 
venting of associated gas--that is, situations where the associated gas 
was vented and not usually routed to a sales line or used for another 
purpose. As alluded to by the commenter, we assumed that the low 
emitting situations likely represent instances where venting was only 
temporary, and thus we discounted their contribution to the 
representative emissions level. As discussed in detail in section 
XI.F.2.f of this document, we recognized that the proposed rule did not 
adequately distinguish between ``routine'' and ``temporary'' 
situations. The final rule includes limited conditional allowances for 
venting in temporary situations where the associated gas is routed to a 
sales line normally (or used for another beneficial purpose) but due to 
circumstances or disruptions operators are not able to maintain normal 
operations without temporarily venting.
    In conclusion, the EPA continues to believe that the associated gas 
emissions estimate levels used for the December 2022 Supplemental 
Proposal's representative well appropriately characterizes a well that 
routinely vents the gas. Therefore, no changes were made to the 
representative well emissions level.
ii. BSER Cost Analysis
    As noted earlier in this document, both in the November 2021 
Proposal and in the December 2022 Supplemental Proposal, we assumed 
that there would be minimal cost to route the gas to an available sales 
line, which was determined to represent BSER.
    Comment: In comments on the December 2022 Supplemental Proposal, 
one commenter \390\ stated that the associated gas model plant analysis 
did not include assumptions reflective of actual proposed requirements. 
They pointed out that none of the beneficial reuse emerging 
technologies were included in the model plant analysis, and that it was 
unclear how the EPA justified the inclusion of these technologies 
related to costs, feasibility, or environmental benefit/disbenefit.
---------------------------------------------------------------------------

    \390\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Another commenter \391\ also recognized that the EPA declined to 
quantitatively analyze the cost of routing to a sales line and the 
other beneficial use options, but the commenter provided a study \392\ 
that included estimates of the costs of various gas recovery options. 
Specifically, this study estimated the costs of routing to a sales line 
(pipeline gathering), onsite use (for fueling equipment or for local 
electricity generation), gas-to-wire, onsite compressed natural gas 
(CNG), onsite liquefied natural gas (LNG), and gas reinjection. Based 
on the cost data from this study, the commenter concluded that the cost 
effectiveness values for all abatement methods are well within the 
range that the EPA finds reasonable.
---------------------------------------------------------------------------

    \391\ EPA-HQ-OAR-2021-0317-2433.
    \392\ Rystad Energy. ``Cost of Flaring Abatement, Final 
Report.'' January 31, 2022.
---------------------------------------------------------------------------

    Response: While the first commenter indicated that the EPA did not 
perform an analysis of the BSER options, the commenter did not provide 
any information to support their comments. Contrary to this comment, 
the EPA did perform a BSER analysis. The EPA found the study provided 
by the second commenter to be informative regarding the extent of 
flaring in the U.S. and fundamental considerations in non-flaring 
abatement options. However, we closely examined this information and 
determined that the basis for these cost estimates lacked some details 
that the EPA thought necessary in order to use them as the basis for a 
BSER analysis. See EPA-HQ-OAR-2021-0317-2433 attachment T to review the 
data submitted.
    In addition to following up with the single commenter that provided 
cost information for non-flaring options,\393\ the EPA performed a 
search for cost information from other sources. One source identified 
with detailed cost information that the EPA found to be informative was 
a study performed by ICF International for the Interstate Natural Gas 
Association of America (INGAA) Foundation.\394\ In addition to a 
plethora of information regarding midstream infrastructure, this study 
included detailed costs for the installation of gathering and boosting 
systems and associated lines. Specifically, it provided detailed cost 
information for, among other things, pipeline costs and compression/
pumping costs. The gathering pipeline costs were provided starting in 
2010 and projected to 2035 for pipe sizes ranging from 2 inches to 30 
inches. In conversations with the authors of this

[[Page 16942]]

report,\395\ the commenter indicated that the most representative pipe 
sizes for connecting a well to an existing gathering system were either 
4 or 6 inches.
---------------------------------------------------------------------------

    \393\ Please see June 5, 2023, meeting memorandum for meeting 
between the EPA and EDF and Rystad in EPA-HQ-OAR-2021-0317.
    \394\ North America Midstream Infrastructure through 2035 
Significant Development Continues. The INGAA Foundation, Inc. 
Prepared by ICF. June 18, 2018. Available at: https://ingaa.org/north-america-midstream-infrastructure-through-2035-significant-development-continues/.
    \395\ See EPA Docket EPA-HQ-OAR-2021-0317 for record of June 21, 
2023, call with INGAA Foundation/ICF.
---------------------------------------------------------------------------

    This information was used to estimate the costs for connecting the 
associated gas from a well site to a nearby gathering system/sales line 
for the representative well discussed earlier in this document. 
Specifically, costs were estimated for both 4- and 6-inch pipe sizes 
and for a variety of distances, in miles, to the gathering system. 
Other assumptions in this analysis were that the compressor horsepower 
needed was 25 horsepower and the capital recovery was based on 7 
percent interest rate and 10 years. Annual operation and maintenance 
costs were estimated to be 25 percent of the total capital costs. Table 
23 provides the results of this analysis.

                          Table 23--NSPS Cost Analysis for Routing Associated Gas to Sales Line for Representative New Well \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    Cost effectiveness ($ per ton of emission reduction)
                                   ---------------------------------------------------------------------------------------------------------------------
                                         Without considering savings                                    Considering savings
    Pipe size      Length (miles)  ---------------------------------------------------------------------------------------------------------------------
    (inches)                         Single pollutant    Multipollutant              Single pollutant                         Multipollutant
                                   ---------------------------------------------------------------------------------------------------------------------
                                     Methane    VOC     Methane    VOC          Methane               VOC               Methane               VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
4...............  1...............      $158     $569       $79     $285  Net Savings.......  Net Savings.......  Net Savings.......  Net Savings.
4...............  3...............       257      926       129      463  59................  213...............  38................  137.
4...............  5...............       357    1,283       178      641  158...............  570...............  88................  315.
4...............  7...............       456    1,640       228      820  258...............  927...............  137...............  494.
4...............  10..............       604    2,175       302    1,087  423...............  1,522.............  212...............  761.
4...............  20..............     1,100    3,958       550    1,979  919...............  3,306.............  459...............  1,653.
4...............  30..............     1,596    5,742       798    2,871  1,415.............  5,090.............  707...............  2,545.
4...............  40..............     2,092    7,526     1,046    3,763  1,910.............  6,873.............  955...............  3,437.
4...............  50..............     2,587    9,310     1,294    4,655  2,406.............  8,657.............  1,203.............  4,329.
6...............  1...............       171      615        85      307  Net Savings.......  Net Savings.......  Net Savings.......  Net Savings.
6...............  3...............       295    1,062       148      531  97................  349...............  57................  205.
6...............  5...............       420    1,510       210      755  222...............  797...............  119...............  429.
6...............  7...............       544    1,957       272      979  346...............  1,244.............  181...............  652.
6...............  10..............       731    2,629       365    1,314  549...............  1,976.............  275...............  988.
6...............  20..............     1,353    4,867       676    2,433  1,171.............  4,214.............  586...............  2,107.
6...............  30..............     1,975    7,104       987    3,552  1,793.............  6,452.............  897...............  3,226.
6...............  40..............     2,597    9,342     1,298    4,671  2,415.............  8,690.............  1,208.............  4,345.
6...............  50..............     3,219   11,580     1,609    5,790  3,037.............  10,927............  1,519.............  5,464.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The representative well has associated gas methane emissions of 343.6 tpy and VOC emissions of 95.5 tpy.

    As provided in table 23, the single-pollutant cost effectiveness 
for methane ranges from $158 to $3,219 per ton of methane emissions 
eliminated. If the value of the gas that will be sold (i.e., the 
savings) is considered, the range is from a net savings to $3,037 per 
ton. The per-ton VOC cost effectiveness ranges from $569 to $11,580 
without savings and ranges from a net savings to $10,927 considering 
the savings. The multipollutant cost effectiveness values range from 
$79 per ton of methane and $286 per ton of VOC to $1,609 per ton of 
methane and $5,790 per ton of VOC. If savings are considered, these 
multipollutant cost effectiveness values range from a net savings to 
$1,519 per ton of methane and $5,464 per ton of VOC. More details on 
this analysis are provided in the 2023 NSPS OOOOb and EG OOOOc Final 
Rule TSD.
    The EPA determines that the estimated costs, for both pipe sizes 
for distances out to 50 miles are reasonable, when considering 
multipollutant reductions of methane and VOC. The EPA factors in that 
owners and operators of newly drilled wells have the flexibility to 
plan and coordinate the construction of gas gathering systems even over 
extended distances. Our analysis shows that constructing up to 50 miles 
of pipeline is a cost-effective means of managing associated gas at 
representative volumes of gas. In cases where the cost of construction 
of gathering line or gas volume differs significantly from these 
representative parameters, the other options for managing associated 
gas are available under the standards. The information presented in 
table 23 supports the assumption that the EPA made in the November 2021 
Proposal and the December 2022 Supplemental Proposal that routing to a 
sales line is cost-effective.
c. BSER Conclusion for New Sources
    In the December 2022 Supplemental Proposal, we concluded that BSER 
was routing the associated gas to a sales line. In addition, we 
recognized that there were other options that achieved the same level 
of emissions reduction as routing to a sales line. Therefore, we 
proposed four compliance options to reduce emissions of methane and VOC 
from associated gas from new oil wells. These options were: (1) recover 
the associated gas from the separator and route the recovered gas into 
a gas gathering flow line or collection system to a sales line, (2) 
recover the associated gas from the separator and use the recovered gas 
as an onsite fuel source, (3) recover the associated gas from the 
separator and use the recovered gas for another useful purpose that a 
purchased fuel or raw material would serve, or (4) recover the 
associated gas from the separator and reinject the recovered gas into 
the well or inject the recovered gas into another well for enhanced oil 
recovery.
    Routing associated gas to a sales line is an adequately 
demonstrated method of emissions reduction. This is supported by the 
statements of one industry commenter,\396\ which indicated that 
recovering associated gas from the separator and routing the recovered 
gas into a gas gathering flow line or collection system to a sales line 
``explains standard business operations for thousands of wells 
producing a vital energy resource throughout the country.'' They add 
that ``[s]elling natural gas is part of our business.'' The 
environmental benefit of routing associated gas to a sales line is 
significant, as there are no GHG

[[Page 16943]]

(methane) or VOC emissions. As outlined in the TSD for this final rule, 
there are also minimal nonair quality health and environmental impacts 
related to routing gas into a sales line. Further, as discussed in 
section XI.F.2.b of this document, in response to comments, the EPA 
obtained information related to the costs of connecting to a sales line 
and performed an analysis, the results of which showed that the cost of 
routing to sales is reasonable given the emissions reductions. Given 
these considerations, the EPA again concludes that BSER is routing 
associated gas from oil wells to a sales line. In addition, the EPA 
continues to accept that the other three options proposed achieve 
equivalent emissions reductions to routing to a sales line and that 
they should be allowed as regulatory alternatives to the BSER.
---------------------------------------------------------------------------

    \396\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    The December 2022 Supplemental Proposal for new sources allowed the 
associated gas to be routed to a flare or control device that reduces 
methane and VOC emissions by at least 95.0 percent if a determination 
was made that it was not technically feasible to route the associated 
gas to a sales line, use it as onsite fuel or for another beneficial 
purpose, or inject/reinject it due to technical or safety reasons, and 
the determination was certified by a professional engineer or another 
qualified individual with expertise in the uses of associated gas. 
Ongoing, continuous flaring in the absence of a method for capturing 
and selling, putting to beneficial use, or storing associated gas is 
referred to as ``routine'' flaring. As described previously in this 
preamble and in response to comments described below, the EPA has 
changed these provisions for the final NSPS OOOOb rule to specify that 
routine flaring is disallowed at new wells that commence construction 
24 months after the effective date of this final rule. As discussed in 
detail below, new sources can take this requirement into account when 
planning. Moreover, the final rule provides for an orderly ``phase in'' 
of this requirement through compliance deadlines that vary based on the 
date of construction, and it also recognizes reasonable exemptions for 
temporary or emergency uses of flaring. These requirements for new 
wells reflect comments and information the EPA received in response to 
the December 2022 Supplemental Proposal.
    Comment: Numerous commenters supported the EPA's proposal to allow 
for multiple compliance options as alternatives to routing gas to a 
sales line, and several pointed out that the proposed list was 
consistent with the options allowed in New Mexico and Colorado. For 
instance, one commenter \397\ stated, ``As in the EPA's supplemental 
proposal, Colorado and New Mexico require operators to capture 
associated gas from oil wells and either route the gas to a sales line 
or put it to an alternative use. The alternative uses allowed in New 
Mexico largely overlap with those included in the EPA's supplemental 
proposal and include, among other things, power generation on lease, 
liquids removal on lease, reinjection for underground storage, and 
other alternative uses approved by the division. For wells that are not 
connected to a pipeline, Colorado similarly allows operators 
flexibility to use other options to capture gas including to generate 
electricity or to process the gas to recover natural gas liquids, 
without venting or flaring.''
---------------------------------------------------------------------------

    \397\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    The commenter \398\ also recommended that the EPA remove any 
specific reference to ``enhanced oil recovery.'' The commenter 
explained that other preferable options exist for injected or 
reinjected gas, such as permanent storage in porous geological 
formations, and there is no reason to disallow or subordinate these 
alternatives.
---------------------------------------------------------------------------

    \398\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA agrees with this comment and therefore has 
eliminated specific reference to enhanced oil recovery in the final 
rule for both NSPS OOOOb and EG OOOOc. Specifically, the fourth 
compliance option (alternative standard) under the final rule allows 
the recovery of associated gas from the separator and reinjection into 
the well or injection into another well. Removal of reference to 
enhanced oil recovery means that sources can choose to reinject 
regardless of whether doing so results in additional oil being produced 
or recovered from the well. This compliance option still results in 
equivalent emissions reductions to the BSER.
    Comment: Many commenters objected to the allowance of routine 
flaring for new sources. One commenter \399\ urged the EPA to eliminate 
pollution from routine flaring except in emergency situations and to 
define the term ``emergency'' clearly and narrowly. The commenter 
recommended that exemptions only be applicable to short-term and 
temporary flaring. Another \400\ suggested that routine flaring from 
new wells can never be justified due to the technical infeasibility of 
some alternative. The commenter stated that routine flaring is readily 
preventable at new wells with proper planning and coordination. Another 
commenter \401\ urged the EPA to adopt NSPS and EG that effectively 
prohibit routine flaring of associated gas from new and existing oil 
wells, with the only exceptions related to safety and emergencies, by 
requiring owners or operators to capture all or most of the gas. 
Another commenter \402\ strongly supported the EPA's proposed 
requirement that owners and operators of oil wells with associated gas 
must capture that gas and route it to a sales line. However, they 
stated the belief that the EPA can and should take further steps to 
eliminate routine flaring. They asserted that the EPA should replace 
the broad technical infeasibility exception that would allow operators 
to continue routinely flaring with narrowly defined exemptions 
applicable only to short-term and temporary flaring. Another commenter 
\403\ called for a nationwide ban on routine flaring, characterizing 
the practice as wasteful and unnecessary. The commenter points out that 
leading state examples and the commitments made by multiple operators 
demonstrate that eliminating routine flaring is feasible and cost-
effective.
---------------------------------------------------------------------------

    \399\ EPA-HQ-OAR-2021-0317-2394.
    \400\ EPA-HQ-OAR-2021-0317-2433.
    \401\ EPA-HQ-OAR-2021-0317-2410.
    \402\ EPA-HQ-OAR-2021-0317-2392.
    \403\ EPA-HQ-OAR-2021-0317-2408.
---------------------------------------------------------------------------

    The commenter noted that numerous operators have committed to 
eliminate routine flaring as part of the World Bank's ``Zero Routine 
Flaring by 2030'' initiative. To date, 54 oil companies and 34 
governments have endorsed the ``Zero Routine Flaring by 2030'' 
initiative. Based on satellite estimates and publicly reported flaring 
data, together the endorsers represent approximately 60 percent of 
global flaring. The commenter added that ExxonMobil ``recently 
announced a commitment to end routine flaring while also expressing 
support for regulations banning this wasteful practice.'' They urged 
the EPA to revise its proposal to prohibit routine flaring by requiring 
that operators use one of the four gas recovery abatement methods 
included in the EPA's proposal. They suggested that the EPA allow for 
flaring only during explicit, narrowly tailored, and time-limited 
exemptions. They believed that doing so would more clearly and 
unequivocally prohibit pollution stemming from routine flaring, as well 
as enhance the enforceability of the rule.

[[Page 16944]]

    One industry commenter \404\ reported that it is actively working 
to reduce flaring of associated gas across each of its operating areas 
and has committed to eliminate routine flaring by 2030. Since the 
commenter's standard practice is to only bring wells online where 
adequate sales line capacity exists, the commenter supports the 
restriction of the routine flaring of associated gas from oil wells 
that are considered ``new'' sources.
---------------------------------------------------------------------------

    \404\ EPA-HQ-OAR-2021-0317-2360.
---------------------------------------------------------------------------

    Commenters also pointed out that Colorado and New Mexico do not 
allow the long-term routine flaring of associated gas. One \405\ 
recommended that the EPA should follow the lead of these states and 
prohibit routine flaring of associated gas from new and existing oil 
wells except in very limited cases such as emergencies and for safety 
reasons.
---------------------------------------------------------------------------

    \405\ EPA-HQ-OAR-2021-0317-2410.
---------------------------------------------------------------------------

    One commenter \406\ stated that a standard based on approaches like 
those adopted in Colorado and New Mexico, which clearly limit and 
delineate circumstances where temporary flaring would be permitted, 
represents the ``best system'' for several reasons. For one, it would 
require gas recovery but contain reasonable exemptions for temporary 
flaring during certain activities that may require flexibility to vent 
or flare. Thus, this system would ``reduc[e] emissions as much as 
practicable'' and reflect the ``maximum practicable degree of 
control.'' The standard would permit technological flexibility by 
allowing the use of a multitude of abatement methods, including routing 
to a sales line, injection, or reinjection, use as onsite fuel, or use 
for another alternative purpose. The commenter pointed out that the 
costs of a capture standard are reasonable, cost-effective, and in some 
instances even profitable for operators.
---------------------------------------------------------------------------

    \406\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA finds these arguments for not allowing routine 
flaring under any circumstance for new sources to be compelling. The 
EPA reviewed the comments from across the industry on our proposal to 
direct the gas to a sales line or adopt another gas management 
technique that did not require flaring. The conclusion that the EPA 
reached for new sources was that operators did not demonstrate or even 
explain that routing to a sales line or the alternatives were 
infeasible, only that specific circumstances could make certain 
alternatives more attractive than others. The most cited factors for 
deciding between the proposed alternatives were the logistics of each 
option and the costs of adopting any method as a function of the amount 
of available gas and whether the well was new, existing, or a marginal 
well nearing the end of production. Since the objective of our proposal 
was to cost-effectively minimize the emissions that result from 
associated gas, and flaring emits more than the zero-emissions options, 
we looked at the group of wells where the factors allowing a non-
flaring option were most in favor of operators. New wells fit the 
criteria where factors worked most in favor of not flaring. New wells 
benefit from new investment and the benefit of planning to accommodate 
each option best suited to the site. Production is highest at startup, 
meaning that from the start of production a new well would have 
anywhere from 10 to 30 years of production to draw upon to manage and 
amortize the investment required to manage associated gas. Our analysis 
of the costs of connecting to a sales line indicated that for 
representative amounts of gas at reasonable distances, the outlook for 
amortization of the capital investment was reasonable. See table 22 
above. Where distances or logistics might make connection to sales 
lines less attractive, commenters provided cost and qualitative support 
that the other alternatives would likely be used rather than connecting 
to sales, provided they had the benefit of space and time to plan for 
managing the associated gas when construction was beginning. As 
mentioned above, companies themselves have made voluntary commitments 
to eliminate flaring in the near future, by 2030.\407\ While those 
commitments are on a longer time horizon than this final rule, our 
decision to limit the prohibition on routine flaring to only new wells 
means the timelines between implementation of the NSPS and the 
voluntary commitments are in the range of about 4 years apart 
(considering the phase-in period for the final associated gas standards 
in the NSPS). We heeded industry comments that a significant time 
horizon would be required to make such a transition, and we chose 24 
months from the effective date of the final rule as the most flexible 
option that would provide meaningful and timely reductions without 
disrupting the near-term investments taking place now. We concluded 
that, for new sources, opportunities exist for advance planning to 
route the associated gas to a sales line, use it as onsite fuel or for 
another beneficial purpose, or inject/reinject it. Therefore, in the 
final rule, the EPA has eliminated the allowance for new sources that 
associated gas can be routinely routed to a flare or other control 
device. As explained further below, the EPA is finalizing a phase-in 
approach for this standard for the NSPS OOOOb.
---------------------------------------------------------------------------

    \407\ To date, 54 oil companies and 34 governments have endorsed 
the ``Zero Routine Flaring by 2030'' initiative. See ``Global 
Initiative to Reduce Gas Flaring: ``Zero Routine Flaring by 2030,'' 
EPA Docket ID EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    As discussed in section XI.F.2.f of this document, the EPA 
recognizes that a source routing the associated gas to a sales line, 
using it as onsite fuel or for another beneficial purpose, or 
injecting/reinjecting it will likely encounter temporary situations 
where it is infeasible or unsafe to route the associated gas to a sales 
line, use it as onsite fuel or for another beneficial purpose, or 
inject/reinject it. Therefore, the final rule allows temporarily 
routing to a flare or other control device in specified situations.
    In addition, the EPA acknowledges that owners or operators may have 
already planned and initiated efforts to drill new wells based on the 
allowance of routing to a flare or control device with an infeasibility 
determination that was included in the December 2022 Supplemental 
Proposal. The EPA also accepts that existing wells that are modified or 
reconstructed may be limited in the options to route to a sales line or 
comply with one of the other options. Therefore, the final rule 
includes special allowances for these situations. This is discussed in 
section XI.F.2.d of this document.
d. Considerations for New Sources for Which Construction Commenced 
Prior to the Final Rule and for Reconstructed and Modified Sources
    In the December 2022 Supplemental Proposal, the EPA proposed to 
allow new sources to routinely route associated gas to a flare or 
control device with a demonstration and certification that routing the 
associated gas to a sales line, using it as onsite fuel or for another 
beneficial purpose, or injecting/reinjecting it was infeasible for 
technical or safety reasons. A new source is defined as a well that 
commenced construction, reconstruction, or modification after December 
22, 2022. Further, the definition of ``commenced'' found within 40 CFR 
60.2 applies for purposes of NSPS OOOOb. That definition states that 
``commenced means . . . that an owner or operator has undertaken a 
continuous program of construction or modification or that an owner or 
operator has entered into a contractual obligation to undertake and 
complete, within a reasonable time, a continuous

[[Page 16945]]

program of construction or modification.''
    As discussed in section XI.F.2.c of this document, the EPA believes 
that, with the full knowledge and understanding of the final rule, 
owners planning on drilling new wells in the future have the ability to 
plan ahead to ensure that the associated gas is routed to a sales line, 
used as onsite fuel or for another beneficial purpose, or injected/
reinjected. However, the EPA acknowledges that new wells have commenced 
construction in the period between December 22, 2022, and the date of 
publication of this final rule, and that it is reasonable for owners 
and operators of such wells to have assumed that the final rule could 
have continued to allow the proposed allowance to routinely flare the 
associated gas or route it to a control with an infeasibility 
determination and certification. The EPA concludes that for wells in 
this situation, it is appropriate to allow the associated gas to be 
routinely routed to a flare or control device with a determination and 
certification that it is technically infeasible \408\ to route the 
associated gas to a sales line, use it as onsite fuel or for another 
beneficial purpose, or inject/reinject it. The EPA encourages owners 
and operators of these sources to continue to seek opportunities to 
route the associated gas to a sales line, use it as onsite fuel or for 
another beneficial purpose, or inject/reinject it. These methods will 
not only eliminate the environmental impacts of routine flaring but 
will also significantly reduce the compliance burden on the owners and 
operators. Therefore, the final rule allows sources that have made the 
requisite determination and certification to route the associated gas 
to a flare or control device that achieves a 95.0 percent reduction in 
VOC and methane emissions for those wells for which construction was 
commenced between December 22, 2022, and the effective date of the 
final rule, which is May 7, 2024. This is only allowed with a 
demonstration and certification that it is technically infeasible to 
route the associated gas to a sales line, use it as onsite fuel or for 
another beneficial purpose, or inject/reinject it. This demonstration 
and certification must then be renewed annually. See section XI.F.2.g 
of this document for a discussion of comments received on the 
infeasibility determination and certification process and the 
requirements contained in the final rule.
---------------------------------------------------------------------------

    \408\ As discussed in section XI.F.2.g of this document, based 
on comments, the EPA determined that the need to flare associated 
gas due to safety reasons is a temporary circumstance and would not 
result in the need to routinely flare in place of routing the 
associated gas to a sales line, using it as onsite fuel or for 
another beneficial purpose, or injecting/reinjecting it. Therefore, 
temporary flaring due to safety reasons is allowed without any type 
of infeasibility determination or certification.
---------------------------------------------------------------------------

    The EPA recognizes that existing sources that undergo 
reconstruction or modification and thus become new sources also face 
different circumstances than new wells for which construction commences 
with full knowledge of the ``no routine flaring'' requirement in the 
final rule. These wells were likely originally drilled without the 
expectation that the EPA would be proposing and promulgating 
requirements that would require the routing of associated gas to a 
sales line, using it as onsite fuel or for another beneficial purpose, 
or injecting/reinjecting it as required by the final rule. The location 
of these existing wells that are undergoing reconstruction or 
modification is established and the owner or operator does not have the 
ability to move the well to allow connection more easily to a sales 
line, to inject into another well, or perhaps to utilize any other 
option. Therefore, the EPA concluded that it is appropriate to allow 
wells reconstructed or modified after December 22, 2022, to routinely 
flare associated gas or route it to control with a technical 
infeasibility determination and certification. This demonstration and 
certification must then be renewed annually.
    Finally, the EPA acknowledges that owners and operators could have 
initiated the planning stages of a new well based on the December 2022 
Supplemental Proposal even though they may not have specifically 
undertaken the activities that meet the definition of ``commenced 
construction.'' Therefore, owners and operators may have made 
preliminary plans assuming that flaring or routing to control would be 
allowed with a determination that it is technically infeasible to route 
the associated gas to a sales line, use it as onsite fuel or for 
another beneficial purpose, or inject/reinject it. The final rule 
allows sources that commence construction within a certain period after 
the effective date of the rule to routinely route the associated gas to 
a flare or to a control device for a short period, after which they are 
required to route the associated gas to a sales line, use it as onsite 
fuel or for another beneficial purpose, or inject/reinject it. This 
will allow owners and operators to proceed with plans, but also not 
allow routine flaring or routing to control for an extended period. 
Specifically, the final rule allows wells for which construction 
commences between May 7, 2024 and May 7, 2026 to route the associated 
gas to a flare or to a control device that achieves a 95.0 percent 
reduction in VOC and methane emissions, with the proper demonstration 
of technical infeasibility, until May 7, 2026. Routine flaring for 
these sources is only allowed with a demonstration and certification 
that it is technically infeasible to route the associated gas to a 
sales line, use it as onsite fuel or for another beneficial purpose, or 
inject/reinject it. This demonstration and certification must then be 
renewed annually. After May 7, 2026, these sources will no longer be 
able to routinely flare associated gas, and must route the associated 
gas to a sales line, use it as onsite fuel or for another beneficial 
purpose, or inject/reinject it. For information regarding technical 
infeasibility demonstrations, including examples, see section 
X.F.2.a.i. of this document.
e. BSER for Existing Sources
    In the December 2022 Supplemental Proposal, the EPA proposed 
presumptive standards for associated gas from existing oil wells for 
the EG OOOOc that mirrored those for new sources under NSPS OOOOb. That 
is, EG OOOOc included four compliance options to eliminate emissions of 
methane from associated gas from existing oil wells. These options 
were: (1) recover the associated gas from the separator and route the 
recovered gas into a gas gathering flow line or collection system to a 
sales line, (2) recover the associated gas from the separator and use 
the recovered gas as an onsite fuel source, (3) recover the associated 
gas from the separator and use the recovered gas for another useful 
purpose that a purchased fuel or raw material would serve, or (4) 
recover the associated gas from the separator and reinject the 
recovered gas into the well or inject the recovered gas into another 
well for enhanced oil recovery. Associated gas was allowed to be routed 
to a flare or other control device if the owner or operator 
demonstrated that all four options were infeasible due to technical or 
safety reasons and if that demonstration is approved by a certified 
professional engineer or other qualified individual.
    Comment: One commenter \409\ suggested that there was a fundamental 
flaw in the EPA's process that has resulted in a misguided BSER 
determination for existing sources that effectively regulates existing 
sources the same as new and modified sources. Another commenter claimed 
that the EPA's recurring conclusion that

[[Page 16946]]

designated facilities under the EG should be the same as affected 
facilities under the NSPS did not recognize the differences between new 
and existing sources.\410\
---------------------------------------------------------------------------

    \409\ EPA-HQ-OAR-2021-0317-2294.
    \410\ EPA-HQ-OAR-2021-0317-2446.
---------------------------------------------------------------------------

    Response: The EPA generally agrees with the commenters that 
consideration must be given to any meaningful differences between new 
and existing sources in determining the respective BSER. The EPA 
proposed that routing the associated gas from existing wells to a sales 
line was an adequately demonstrated method of emissions reduction and 
the costs were reasonable. We also determined that the other equivalent 
compliance options also were appropriate for existing sources (we did 
not identify any limitations that would universally inhibit use of the 
alternatives for existing sources). We recognized that there could be 
situations where it was infeasible to comply with one of these options, 
so the proposed presumptive standards in EG OOOOc included the 
allowance to routinely flare the associated gas or route it to control 
if it was demonstrated and certified that the earlier listed four 
alternatives were infeasible due to technical or safety reasons.
    As discussed in section XI.F.2.c of this document, the final rule 
will phase out the option for new sources to routinely route the 
associated gas to a flare or control device. In addition, numerous 
comments were submitted regarding considerations related to wells that 
produce low levels of associated gas. In light of the changes to the 
NSPS and comments received specific to existing sources of associated 
gas, the EPA reevaluated the BSER for existing sources. This revised 
BSER analysis for existing sources recognizes that, unlike new sources, 
existing sources may not have taken into account distance to a gas line 
when choosing their location and cannot readily do so now.\411\
---------------------------------------------------------------------------

    \411\ See full BSER analysis in chapter 4 of the final TSD for 
this rulemaking.
---------------------------------------------------------------------------

    Comment: Commenters \412\ believed that the EPA needs to maintain 
flaring as an option for wells with little associated gas. They 
maintained that the gas production rate is too low to be able to 
justify the expense of routing to a sales line or even investing in the 
equipment to inject the gas back into the reservoir. Many times, the 
gas production rate is too low to be able to reliably operate an engine 
to produce power to operate surface equipment. They added that low 
production wells need to have the option to flare the gas as an 
environmentally acceptable option. The commenters believed that 
eliminating this option would be an unnecessary burden on small 
businesses.
---------------------------------------------------------------------------

    \412\ EPA-HQ-OAR-2021-0317-2168 and -2172.
---------------------------------------------------------------------------

    The commenters pointed out that much of the associated gas from low 
production wells does not meet the requirements to be sold on an 
interstate pipeline system. The gas may require water, nitrogen, 
CO<INF>2</INF>, and heavier hydrocarbons (ethane, propane, butane, 
pentane, and hexane) to be removed prior to its being sold into the gas 
market. The cost to make the gas ``pipeline spec'' usually exceeds the 
benefit of selling the gas on the pipeline. The commenters provided 
that this is another example where low production wells should be 
exempt from the proposed regulation.
    Another commenter \413\ explained that, for many of their existing 
wells, no sales line is readily available, and even if one was 
available, the volume of associated gas may be too low to reach a sales 
line. The commenter recommended that the EPA reconsider this 
requirement for existing well sites, in recognition that the 
infrastructure is unlikely to be present to make such a requirement 
feasible.
---------------------------------------------------------------------------

    \413\ EPA-HQ-OAR-2021-0317-2283.
---------------------------------------------------------------------------

    Yet another commenter \414\ recommended that the EPA maintain an 
exemption for low production wells. The commenter explained that many 
of the low production wells operate with low pressure and low gas-to-
oil ratios, so the PTE is significantly less than the PTE for higher-
production wells that were recently drilled.
---------------------------------------------------------------------------

    \414\ EPA-HQ-OAR-2021-0317-2172.
---------------------------------------------------------------------------

    Response: As discussed in section XI.F.2.b of this document, the 
EPA obtained data and performed a cost analysis of collecting the 
associated gas and routing it to a sales line for a representative new 
well. As discussed, this representative new well had methane emissions 
of 343.6 tpy. In response to the comments regarding low associated gas 
production wells, the EPA performed an analysis for varying baseline 
emissions levels and distances to the gathering system. Specifically, 
the EPA evaluated the costs of routing associated gas to a sales line 
for distances up to 5 miles using a 4-inch pipe. The results of this 
analysis are provided in table 24.

        Table 24--Methane Cost Analysis of Routing to Sales Line for Low Associated Gas Production Wells
----------------------------------------------------------------------------------------------------------------
                                      Miles from gathering system cost effectiveness ($/ton methane reduced)
Associated gas methane emissions -------------------------------------------------------------------------------
              (tpy)                    0.25            0.50              1               3               5
----------------------------------------------------------------------------------------------------------------
10..............................          $3,961          $4,387          $5,239          $8,646         $12,053
20..............................           1,882           2,095           2,520           4,224           5,927
30..............................           1,188           1,330           1,614           2,750           3,886
40..............................             842             948           1,161           2,013           2,865
50..............................             634             719             889           1,571           2,252
60..............................             495             566             708           1,276           1,844
70..............................             396             457             579           1,065           1,552
80..............................             322             375             481             907           1,333
90..............................             264             311             406             785           1,163
100.............................             218             260             346             686           1,027
----------------------------------------------------------------------------------------------------------------

    Based on the results of this analysis, the EPA decided it was 
appropriate to separate existing oil wells with associated gas into two 
subcategories. For wells with 40 tpy of methane emissions, the cost 
effectiveness of routing to sales was considered reasonable at 
distances in a range of about 3 miles. We assume that the methane 
emissions are equivalent to the amount of methane contained in the 
associated gas. Therefore, the two subcategories are those with 
associated gas that contains 40 tpy or less methane and those that 
contain greater than 40

[[Page 16947]]

tpy methane. The EPA then developed BSER separately for these two 
subcategories.
i. BSER for the Subcategory of Wells With Associated Gas Containing 40 
tpy or Less Methane
    For wells that produce 40 tpy or less of associated methane gas, 
the analysis shows that, depending on the distance from the well to the 
gathering system, it could sometimes be cost-effective to route the 
associated gas to a sales line, and sometimes not. Assuming that there 
is an existing flare or control device onsite that could accept the 
associated gas, the cost to direct the associated gas into the flare 
would be minimal (approximately $6,100 capital cost, with an annual 
cost of $670). The cost effectiveness of routing to an existing flare 
for an associated gas well where the associated gas contains 40 tpy of 
methane is $18 per ton of methane, which is well within the range that 
the EPA has considered reasonable. In fact, the cost effectiveness for 
wells with 1 tpy of methane ($915/ton) is still reasonable. For the 
installation of a new flare, the cost effectiveness for a well where 
the associated gas contains 40 tpy methane is $1,758 per ton of 
methane, which is also considered reasonable. Considering that routing 
associated gas to a flare or control device is an adequately 
demonstrated method and considering this cost effectiveness leads the 
EPA to conclude that BSER to reduce the methane emissions from 
associated gas from existing oil wells where the associated gas 
contains 40 tpy or less of methane is routing to a flare. This outcome 
is consistent with the recommendations made by the commenters.
    Comment: One commenter \415\ stated that repeated, onerous 
technical infeasibility analyses and detailed recordkeeping should be 
eliminated in the final rule for wells with low associated gas 
production.
---------------------------------------------------------------------------

    \415\ EPA-HQ-OAR-2021-0317-2403.
---------------------------------------------------------------------------

    Response: Because the EPA has determined that BSER for this 
subcategory of existing sources is routing to a flare or control 
device, the final model rule does not include a requirement to 
demonstrate technical infeasibility for wells with associated gas 
containing 40 tpy or less of methane. The presumptive standard allows 
sources in this subcategory to routinely flare without needing to make 
a demonstration of technical infeasibility. However, the final 
presumptive standard does include the requirement to calculate and 
document the methane content of associated gas using the GOR. The 
calculation is based on a simplified version of the methodology in 
subpart W of the GHGRP.
    Note that under the presumptive standard in the final EG, owners 
and operators of these low associated gas production wells are allowed 
to route the associated gas to a sales line, use it as onsite fuel or 
for another beneficial purpose, or inject/reinject it. In fact, the EPA 
encourages this option where possible. If a source elects to comply 
with one of these options, the presumptive standard would not require 
that source to comply with the requirement to calculate the annual 
methane content of the associated gas.
    Comment: One commenter \416\ stated that many older, existing well 
sites in the Midland Basin do not have flares onsite, and it would 
present a significant capital expense to add a flare or similar control 
device at each existing well site. Another commenter \417\ stated that 
``for many conventional oil wells in Pennsylvania and New York, a gas 
sales line is not reasonably available. The ``associated gas'' produced 
at these conventional oil and gas well sites would not be sufficient to 
sustain a flare, much less justify the changes and capital expenditures 
needed to attempt to use the gas onsite. The commenter indicated that 
the EPA must expressly allow Pennsylvania and New York conventional oil 
producers to vent the small volumes of ``associated gas,'' which the 
commenters contend is the only safe and environmentally sound method of 
dealing with associated gas at some Pennsylvania conventional oil 
wells. The first commenter stated that the EPA should consider the 
remaining useful life of these existing sources, as required by the 
CAA.
---------------------------------------------------------------------------

    \416\ EPA-HQ-OAR-2021-0317-2283.
    \417\ EPA-HQ-OAR-2021-0317-1341.
---------------------------------------------------------------------------

    Response: The EPA acknowledges these comments and understands that 
certain situations exist where the methane content in the associated 
gas is low and there is not a flare or control device onsite. The EPA 
also recognizes that the cost of installing a new flare or control 
device solely to reduce the methane emissions from the associated gas 
could be above what is typically considered reasonable by the EPA for 
wells with very low levels of methane. Both commenters cite instances 
where the wells are older and located in specific geographic locations. 
We conclude that these situations are most likely to occur for older 
wells where the wells are approaching the end of their useful lives. 
The EPA also believes that the wells discussed by comments do not 
represent the majority of designated facilities across the country. 
Therefore, the EPA did not elect to further subcategorize wells with 40 
tpy or less associated gas methane into those sites with and without 
existing control devices. First, the EPA believes that many of these 
sites likely have existing control devices already onsite that could 
accommodate the associated gas. The EPA is aware that several states, 
including New Mexico, North Dakota, and Texas, have regulations that 
require control devices in certain situations that are relevant here. 
Second, we believe that the particular sites discussed by commenters 
could be candidates for states to examine under the RULOF framework of 
40 CFR part 60, subpart Ba, when states are developing their state 
plans in accordance with these final EG in 40 CFR part 60, subpart 
OOOOc. States can consider the RULOF-specific situations at the low 
associated gas production wells that do not have flares or other 
control devices onsite to possibly apply a standard of performance less 
stringent than the presumptive standard in this EG consistent with the 
EPA's implementing regulations. Further, the EPA acknowledges that the 
Agency did not assess costs for existing wells that are located more 
than 5 miles away from a gathering system, and states may wish to 
examine the possibility of invoking RULOF for situations where a well 
with low levels of associated gas is located a far distance away from a 
gathering system and cannot otherwise comply with the alternatives 
included in the presumptive standard.
ii. BSER for the Subcategory of Wells With Associated Gas Containing 
Greater Than 40 tpy Methane
    As discussed for new sources, routing associated gas to a sales 
line is an adequately demonstrated method for reducing methane 
emissions. As shown in table 23, the cost effectiveness of routing the 
gas to a sales line for wells with associated gas containing greater 
than 40 tpy methane is at levels considered reasonable by the EPA, 
especially in situations where the well is relatively near the 
gathering system. Therefore, the EPA determined that BSER for this 
subcategory is routing the associated gas to a sales line. As with new 
sources, the EPA believes that the other options that achieve the same 
level of emissions reduction should be allowed.
    As discussed for modified and reconstructed sources, the EPA 
recognizes that existing sources were likely originally drilled without 
the expectation that the EPA would issue these EG which include a 
presumptive

[[Page 16948]]

standard of routing the associated gas to a sales line, using it as 
onsite fuel or for another beneficial purpose, or injecting/reinjecting 
it. The location of these existing wells is established, and the owner 
or operator may not have the ability to move the well to allow a closer 
connection to a sales line, to inject into another well, or perhaps to 
utilize any other option. Therefore, the EPA concluded that it is 
appropriate to allow existing wells with greater than 40 tpy methane to 
routinely flare associated gas or route it to control with a technical 
infeasibility determination and certification which is renewed 
annually.
    The final presumptive standards for existing wells with associated 
gas containing greater than 40 tpy methane are to reduce or eliminate 
emissions of methane by: (1) Recovering the associated gas from the 
separator and routing the recovered gas into a gas gathering flow line 
or collection system to a sales line, (2) recovering the associated gas 
from the separator and using the recovered gas as an onsite fuel 
source, (3) recovering the associated gas from the separator and using 
the recovered gas for another useful purpose that a purchased fuel or 
raw material would serve, or (4) recovering the associated gas from the 
separator and reinjecting the recovered gas into the well or injecting 
the recovered gas into another well. In addition, the final presumptive 
standards for this subcategory allow the associated gas to routinely be 
routed to a flare or control device that reduces methane and VOC 
emissions by at least 95.0 percent if annual demonstrations are made 
that it is technically infeasible to route the associated gas to a 
sales line, use it as onsite fuel or for another beneficial purpose, or 
inject/reinject it and the determination is certified by a professional 
engineer or another qualified individual with expertise in the uses of 
associated gas. See section XI.F.2.g of this document related to the 
infeasibility determination and certification.
    Comment: One commenter \418\ stated that the EPA failed to 
understand the implications of inherent production depletion on the 
economics and emissions from smaller wells. The commenter asserted that 
there are fundamental factors that are not adequately considered in the 
EPA assessments, and that, as oil and natural gas wells undergo their 
inherent depletion, the reduced volumes of production limit the amount 
of emissions that can be generated.
---------------------------------------------------------------------------

    \418\ EPA-HQ-OAR-2021-0317-2446.
---------------------------------------------------------------------------

    Response: The EPA understands the depletion of production over time 
and understands that it impacts the associated gas volume, and thus the 
methane contained in the associated gas. Therefore, the presumptive 
standard included in the final EG includes the provision that existing 
wells whose production is less than 40 tpy of methane upon becoming a 
designated facility can flare routinely without a demonstration of 
technical infeasibility. The EPA determined that for wells with above 
40 tpy of methane it is reasonable to route the gas to a sales line or 
choose an equivalent alternative, or in the absence of a feasible 
alternative, to flare the gas. While the level of gas production may 
decline over time from above 40 tpy to below, the EPA considers the 
cost of control of the gas from designation as a designated facility 
producing over 40 tpy to the time of well closure to be reasonable, and 
considers that the cost may be mitigated by any recovery from an 
associated gas management technique that allows some cost savings. 
Further, if an owner/operator is already complying with a zero-
emissions option, then they should be able to continue to comply with 
that option cost-effectively, even if their production declines, as 
they have already made the investment.
f. Temporary Flaring/Venting
    Comment: A number of comments were received on the topic of 
temporary flaring and venting. Commenters from across the spectrum 
(industry, state agencies, environmental organizations) agree that 
there are extenuating circumstances beyond the reasonable control of 
the operator that can result in the inability to exercise the primary 
use option. Further, there is agreement that flaring should be allowed 
in these circumstances. Commenters encouraged the EPA to distinguish 
between ``routine'' and ``non-routine'' flaring events.
    In the December 2022 Supplemental Proposal, we proposed ``to 
require that if owners and operators anticipate that there may be 
interruptions in the ability to route the associated gas to a sales 
line or to use it for another beneficial purpose, they must provide a 
technical or safety demonstration in their annual report and install 
and operate a control device that achieves the required reduction 
during these temporary periods'' (p. 74780).
    While there was agreement among the commenters on the need to allow 
temporary flaring, there was also universal objection to this proposed 
requirement for technical or safety demonstrations to justify flaring. 
One commenter \419\ urged the EPA to abandon the broad, unclear 
technical infeasibility exemption. Another \420\ recommended the 
replacement of the ``technical infeasibility'' exemption with clearly 
delineated circumstances for temporary flaring. Another \421\ contended 
that, for those situations where the gas from the well is connected to 
a sales line and there are instances where the gas needs to be routed 
intermittently to a control device for equipment maintenance, repairs, 
emergencies, or other similar situations, this type of flaring should 
not have to undergo repeated, onerous infeasibility determinations and 
detailed recordkeeping requirements. Another commenter \422\ requested 
that for wells where the operator has designed and configured the 
separator to recover and sell or beneficially use associated gas, the 
EPA remove the requirement to provide an infeasibility or safety 
justification for controlling associated gas when the primary means of 
disposition is temporarily unavailable. Another commenter \423\ 
explained that when a facility is designed with a certain configuration 
for handling the disposition of associated gas, it is unreasonable to 
expect facilities to design for multiple uses based on emerging 
technologies before they can resort to flaring, especially during these 
short, intermittent periods. They did not support making technical or 
safety demonstrations where disruptions or interruptions in the gas 
gathering infrastructure result in the need to route the associated gas 
to a control device for temporary periods. One commenter \424\ 
suggested that, rather than an infeasibility determination being 
required for every instance, a one-time infeasibility determination 
should suffice.
---------------------------------------------------------------------------

    \419\ EPA-HQ-OAR-2021-0317-2408.
    \420\ EPA-HQ-OAR-2021-0317-2433.
    \421\ EPA-HQ-OAR-2021-0317-2403.
    \422\ EPA-HQ-OAR-2021-0317-2326.
    \423\ EPA-HQ-OAR-2021-0317-2428.
    \424\ EPA-HQ-OAR-2021-0317-2403.
---------------------------------------------------------------------------

    Commenters \425\ recommended that, rather than requiring an 
infeasibility demonstration for specific instances, the EPA delineate 
instances in the rule where temporary flaring is allowed. Commenters 
generally indicated that flaring should be allowed during upset 
conditions, which one commenter \426\ defined as emergency 
circumstances outside of the control of an operator that can interrupt 
its ability to comply with the standard. Commenters also provided

[[Page 16949]]

specific situations, including the following:
---------------------------------------------------------------------------

    \425\ EPA-HQ-OAR-2021-0317-2408 and -2433.
    \426\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    <bullet> Due to a temporary, unplanned loss of connection to, or 
ability to route gas to, a gathering system.
    <bullet> During the commissioning of pipelines, equipment, or 
facilities.
    <bullet> When the natural gas does not meet pipeline 
specifications.
    <bullet> Temporary failure of equipment.
    <bullet> During startup and shutdown activities.
    <bullet> During maintenance activities.
    <bullet> During construction activities and facility modifications.
    <bullet> During well testing.
    In addition to suggesting that the EPA delineate specific instances 
when temporary flaring is allowed, commenters recommended that the EPA 
establish clear time limitations during which the flaring is permitted.
    In addition, one commenter \427\ identified circumstances where 
venting may be warranted. The commenter acknowledged that venting may 
be necessary for safety. In addition, they added that operators may 
need to vent for a very brief period during downhole monitoring 
activities, namely when monitoring the downhole pressure during 
bradenhead monitoring and packer leakage tests.
---------------------------------------------------------------------------

    \427\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Commenters stressed that state rules, specifically in Colorado and 
New Mexico, allow operators to flare or vent gas for short periods of 
time during upset conditions or emergencies, including temporary 
unavailability of access to a gathering line. Further, both states list 
specific instances and time frames when flaring is allowed. Examples 
cited by the commenters include the following.
    A commenter \428\ discussed circumstances where the EPA may 
consider exemptions from its capture requirements in which flaring is 
authorized. One circumstance that may give rise to an operator's need 
to flare on a temporary basis is the commissioning of pipelines, 
equipment, or facilities. The commenter provides that New Mexico allows 
operators to flare temporarily during these circumstances, and even 
then ``only for as long as necessary to purge introduced impurities.'' 
An operator may need to flare temporarily when it is first connecting 
to a pipeline that has just been constructed if the pipeline was 
cleaned out with substances that the midstream operator does not want 
in the gas.
---------------------------------------------------------------------------

    \428\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    The commenters report that both Colorado and New Mexico allow 
operators to vent or flare during bradenhead monitoring. Colorado 
limits bradenhead monitoring to 30 minutes. New Mexico also allows 
operators to flare or vent during packer leakage tests.
    Commenters \429\ stated that New Mexico allows for temporary 
venting or flaring during an emergency. An emergency means ``a 
temporary, infrequent, and unavoidable event in which the loss of 
natural gas is uncontrollable or necessary to avoid a risk of an 
immediate and substantial adverse impact on safety, public health, or 
the environment'' other than in certain exceptions. One such exception 
is ``venting or flaring of natural gas for more than 8 hours after 
notification that is caused by an emergency, an unscheduled 
maintenance, or a malfunction of a natural gas gathering system.'' In 
other words, an upstream operator may vent or flare during a temporary, 
infrequent, and unavoidable event involving loss of connection to a 
sales line provided the midstream operator notifies the producer of the 
disruption to the operator of the sales line. However, an upstream 
operator cannot vent longer than 8 hours in this circumstance.
---------------------------------------------------------------------------

    \429\ EPA-HQ-OAR-2021-0317-2433 and -2408.
---------------------------------------------------------------------------

    One commenter \430\ provided that both Colorado and New Mexico 
allow operators to flare or vent gas for a short period of time during 
upset conditions or emergencies which include temporary unavailability 
of access to a gathering line. The commenter explained that the 
Colorado rules provide a concise, clear definition of upset condition 
combined with a limit on the amount of time an operator may flare or 
vent during such circumstances. Colorado allows operators to vent or 
flare for up to 24 cumulative hours during an upset condition while New 
Mexico allows operators to vent or flare for up to 8 hours during an 
emergency. Loss of a connection to a pipeline qualifies as an upset 
condition under the Colorado rules and an emergency under the New 
Mexico rules.
---------------------------------------------------------------------------

    \430\ EPA-HQ-OAR-2021-0317-2408.
---------------------------------------------------------------------------

    The commenter added that New Mexico allows for temporary venting or 
flaring during an emergency. An emergency means ``a temporary, 
infrequent, and unavoidable event in which the loss of natural gas is 
uncontrollable or necessary to avoid a risk of an immediate and 
substantial adverse impact on safety, public health, or the 
environment'' other than in certain exceptions.
    Response: As discussed in section XI.F.2.b of this document, the 
representative well and the BSER analysis are focused on associated gas 
emissions during routine operations. We appreciate the information and 
insights provided by the commenters, and overall we agree with the 
recommendations.
    First, we recognize that there are circumstances that could arise 
that are beyond the control of the owner or operator and that could 
result in the temporary inability to comply with the standards, and we 
do not believe it is appropriate to require the shut-in of the well in 
such instances.
    We agree with the commenters that the proposed requirement to 
demonstrate infeasibility based on technical or safety reasons for each 
of these temporary instances is not the most efficient solution. 
Rather, in the final rule, we have incorporated an approach similar to 
requirements adopted by New Mexico and Colorado. The final rule 
identifies specific circumstances in which temporary flaring or venting 
are allowed. The final rule also includes maximum timeframes for each 
circumstance. Following are the specifics included in the final rule. 
Temporary flaring (or routing to a control device to achieve 95 percent 
reduction) is allowed:
    <bullet> For up to 24 hours during a deviation caused by a 
malfunction.
    <bullet> For up to 72 hours during repair, maintenance including 
blowdowns, a packer leakage test, a production test, or commissioning.
    <bullet> For up to 30 days during temporary interruption in service 
from the gathering or pipeline system.
    <bullet> For up to 72 hours if associated gas does not meet 
pipeline specifications.
    While temporary flaring or routing to a control device is allowed 
in these situations, it is important to ensure that, with the 
additional gas that is being routed to the flare or control device 
during this temporary period, the flare or control device continues to 
operate properly. Therefore, the final rule includes the requirement 
that the owner or operator demonstrate that applicable flare or control 
device requirements are being met during the temporary period when the 
associated gas is routed to the control.
    Comment: One commenter \431\ supported the use of temporary control 
devices for situations when the associated gas could not be routed to a 
sales line, used as onsite fuel or for another beneficial purpose, or 
injected/reinjected. The commenter explains that some sites may have 
permanent control devices for these scenarios. However, temporary 
controls can be used to

[[Page 16950]]

minimize emissions during planned maintenance, startup, and shutdown 
activities. Emissions from these temporary controls are permitted as an 
alternate operating scenario, as a part of normal operations. Another 
commenter supported flaring the gas by using a permanent or temporary 
control device that achieves 95 percent efficiency during periods of 
time when the associated gas is routed to the control device.
---------------------------------------------------------------------------

    \431\ EPA-HQ-OAR-2021-0317-2218.
---------------------------------------------------------------------------

    Response: In the December 2022 Supplemental Proposal, we stated 
that we anticipated that a control device used to reduce emissions 
during these temporary periods ``would need to be permanently 
installed.'' However, we specifically requested comment on whether the 
use of temporary controls could also serve this purpose. Commenters 
responded that such control devices would likely be permanent controls, 
albeit control systems that are present for reasons other than 
providing redundant control for associated gas.\432\
---------------------------------------------------------------------------

    \432\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    The EPA has determined that it is not necessary that a control 
device be permanently installed for these situations. However, if a 
temporary flare or control device is used, it is required to meet the 
same control device requirements as a permanent control device.
    In addition to the allowance for temporary flaring or routing to a 
control device, the final rule allows venting in the following 
circumstances and durations:
    <bullet> For up to 12 hours to protect the safety of personnel.
    <bullet> For up to 30 minutes during bradenhead monitoring.
    <bullet> For up to 30 minutes during a packer leakage test.
    The final rule requires that detailed records be kept of each of 
these venting situations.
g. Infeasibility Demonstration and Certification
    The proposed NSPS OOOOb regulation and EG OOOOc presumptive 
standards both included the allowance that associated gas could be 
routed to a flare or control device after a demonstration and 
certification that it is infeasible to route the associated gas to a 
sales line or to comply with the other options. The December 2022 
Supplemental Proposal required that this demonstration include a 
detailed analysis documenting and certifying the technical or safety 
infeasibility for all options. It also listed specific types of other 
useful purposes that owners and operators were required to address, 
specifically methane pyrolysis, compression of gas for transport to 
another facility, conversion of gas to liquid, and production of 
liquified natural gas. The proposal required that this demonstration be 
certified by a professional engineer or another qualified individual 
with expertise in the uses of associated gas.
    As discussed in section XI.F.2.f of this document, there were many 
comments submitted that objected to the proposal to require a 
demonstration of infeasibility based on technical or safety reasons for 
temporary use of a flare or control device in instances when the 
primary option (e.g., routing the associated gas to a sales line, using 
it as onsite fuel or for another beneficial purpose, or injecting/
reinjecting it) is unavailable. Rather they suggested that the rule and 
presumptive standards include specific instances when such temporary 
flaring or routing to control is allowed. As also discussed in section 
XI.F.2.f of this document, the final rule includes such a list of 
specific circumstances. Therefore, the infeasibility demonstration and 
certification provisions in the final rule are applicable to situations 
where routing the associated gas to a sales line, using it as onsite 
fuel or for another beneficial purpose, or injecting/reinjecting it are 
not feasible and routing to a flare or control device is routine.
    On a related topic, one commenter \433\ suggested that safety 
concerns are by their nature temporary and would never give rise to the 
need to flare indefinitely. The commenter suggested that the EPA should 
therefore require that any safety-related flaring cease when the safety 
concern no longer exists. The EPA agrees that the need to flare or 
route to control for safety reasons is a temporary issue, and not a 
reason that would warrant long-term routine flaring. Therefore, the 
final rule allows routine flaring or routing to control based only on 
technical infeasibility, and not safety.
---------------------------------------------------------------------------

    \433\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Comment: Commenters \434\ suggested that the EPA not require 
consideration of predetermined beneficial uses for oil well associated 
gas, and, if the EPA retains such a list, any included beneficial use 
must be commercially viable. One commenter stated that the EPA proposed 
that operators must certify that use of ``recovered gas for another 
useful purpose that a purchased fuel or raw material would serve'' is 
not feasible ``due to technical or safety reasons'' before the operator 
may control associated gas onsite. They added that the EPA proposed 
that the feasibility analysis must include consideration of using gas 
for ``methane pyrolysis, compressing the gas for transport to another 
facility, conversion of gas to liquid, and the production of liquified 
natural gas.'' The commenter fully supports the beneficial use of 
natural gas where reasonably feasible and cost-effective and further 
supports development of additional technologies that would provide a 
broader range of potential beneficial uses. The commenter believed that 
the EPA's inclusion of a predetermined list of uses suggests that the 
EPA has determined each of these beneficial uses to be technically 
feasible, commercially available, and appropriately included as part of 
the associated gas BSER. The commenter contends that the EPA, however, 
has provided no support for this apparent determination. Accordingly, 
the commenter requested that the EPA remove this list of beneficial 
uses. Further, to the extent the EPA maintains such a list of 
beneficial uses, the commenter requested that the EPA remove any 
unproven ``emerging technologies.'' The commenter stated that CAA 
section 110(j) provides the appropriate pathway for sources to evaluate 
emerging technologies to meet NSPS. According to the commenter, 
requiring evaluation of unproven emerging technologies sidesteps both 
the BSER demonstration and the CAA section 110(j) process in violation 
of the CAA. Another commenter, a state agency,\435\ supported emerging 
technologies as potential methods for controlling emissions from oil 
and gas facilities and recommended that the rules allow the use of 
emerging technologies as a recognized method of achieving a beneficial 
use for associated gas. The commenter reported that some companies use 
the associated gas as fuel for electric generating units or compress 
the gas and send it to another site for processing. The commenter 
believed that useful purpose should include, but not be limited to, 
uses or purposes that a purchased fuel or raw material would serve. The 
commenter also believed that useful purpose should not be explicitly 
defined in the rule language, and that the owner or operator can 
provide a demonstration or certification that they meet this criterion. 
Due to the unpredictable nature of technological advancement, the 
commenter believed it would be shortsighted for the EPA to limit this 
aspect of the rule to only narrowly defined or specified processes or 
technologies. Certain technologies for

[[Page 16951]]

reducing methane and other GHG emissions, such as gas compression for 
offsite transport, can also result in collateral emissions of other 
regulated pollutants which are subject to the national ambient air 
quality standards (NAAQS).
---------------------------------------------------------------------------

    \434\ EPA-HQ-OAR-2021-0317-2326 and -2218.
    \435\ EPA-HQ-OAR-2021-0317-2218.
---------------------------------------------------------------------------

    Response: The EPA reviewed these comments and concluded that the 
regulation should not include a specific list of other beneficial uses, 
for the reasons pointed out by the commenters. However, as discussed in 
section X.F.2.a of this document, it is the responsibility of the owner 
and operator, along with the qualified professional engineer or other 
qualified personnel performing the evaluation, to conduct due diligence 
by ensuring that the list of options evaluated be comprehensive and 
address commercially viable solutions.
    Comment: One commenter \436\ argued that the EPA must limit the 
exemption by clearly delineating specific ``technical'' reasons that 
would justify flaring in lieu of the four gas recovery options. They 
stated that the EPA must require operators to demonstrate the physical 
impossibility of each of the gas recovery options to claim the 
exemption to flare. The commenter provided potential physical 
impossibility demonstrations for each abatement method.
---------------------------------------------------------------------------

    \436\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA believes that including specific criteria in the 
rule would be short-sighted and potentially eliminate legitimate 
reasons that an option is technically infeasible. As discussed in 
section X.F.2.a.1 of this document, the EPA generally characterizes 
acceptable reasons in the general categories of physically, 
logistically, or technically infeasible. Examples are provided in that 
section.
    Comment: One commenter \437\ suggested that the BSER opt-out should 
include economic factors in addition to technical feasibility. The 
commenter reported that the EPA concedes that it is proposing multiple 
regulatory requirements whose implementation would be so burdensome 
that they would be ``technically infeasible'' for some set of affected 
facilities. According to the commenter, the EPA thus gives affected 
facilities the ability to ``opt out'' of the performance standard if 
the affected facility can show that compliance with the performance 
standard would be infeasible for technical or safety reasons. The 
commenter contends that ``technically infeasible'' is a misnomer and 
that the EPA should explicitly include economic factors in addition to 
a technical feasibility analysis. The commenter stated that, instead of 
conflating technical feasibility and economic considerations, the EPA 
in its final rule should transparently state that economic factors must 
be part of an affected facility's ability to opt out of the regulatory 
requirement. A state agency commenter \438\ asked what factors or 
thresholds should be considered if economic feasibility needs to be 
assessed.
---------------------------------------------------------------------------

    \437\ EPA-HQ-OAR-2021-0317-2326.
    \438\ EPA-HQ-OAR-2021-0317-2247.
---------------------------------------------------------------------------

    Response: The EPA disagrees that economic feasibility is a valid 
criterion on which to allow routine flaring or routing to control as 
part of the standard. As shown in Table 23, the EPA has determined that 
the costs associated with the control option determined to be BSER 
(routing to a sales line) are reasonable. Put another way, the EPA has 
already considered costs when setting the standard. As such, there is 
no reason to allow for the type of ``economic feasibility'' showing 
that commenters are requesting. Further, to include economic 
feasibility as a criterion would necessarily take into account many 
aspects of plant operation that are not related to the cost of the 
control option (the BSER). The approach that commenters suggest could 
result in a situation where wells that are operating close to the 
margin due to inefficiencies and poor operation obtain an allowance to 
routinely flare while more efficiently operated wells do not. The EPA 
does not believe that allowing for this type of outcome is appropriate 
because it would unfairly provide preferential treatment to certain 
owners and operators based solely on the fact that their operation is 
less efficient. Lastly, allowing the type of economic feasibility that 
commenters are asking for would necessarily entail a certain degree of 
subjectivity that the EPA does not find to be appropriate in this 
context. The EPA believes that it would be inappropriate to establish 
such thresholds in this context and does not find it necessary.
    Comment: One commenter \439\ points out that the EPA proposal 
contemplated four abatement alternatives to deal with associated gas 
from oil wells. While each alternative has its pros and cons, the 
alternatives are also necessarily based upon, to some extent, well and/
or lease economics. The predominant methodology used by regulators, 
including the EPA, and operators, is to evaluate these economic 
decisions on the gas production only and its prevailing pricing. The 
commenter held that the entire well/lease revenue stream--including 
revenue from oil--needed to be considered, especially if the decision 
to get to a sales line is the question. The commenter stated that 
considering gas revenue only actually promotes waste and negative 
environmental impact. Therefore, according to the commenter, the EPA 
rejects economic viability as a criterion to be considered in the 
infeasibility determination that would allow routine flaring.
---------------------------------------------------------------------------

    \439\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA agrees with the premise of the comment that the 
standards for associated gas should not be limited to those options 
whose cost can be covered by the recovery of associated gas. The EPA's 
BSER analysis acknowledges that cost recovery through the sale or use 
of associated gas will contribute to the cost effectiveness of some 
methods of reducing emissions from associated gas, but the EPA did not 
make the ability to recover the gas for sale the defining criteria to 
select BSER or the equivalent alternatives. For example, an operator 
who chooses to inject the gas into the well or another well may not 
derive any financial benefit to injecting the gas in the form of 
greater oil production, but injecting the gas is acceptable in lieu of 
routing to a sales line because it achieves emissions reductions 
equivalent to those for routing the associated gas to a sales line.
    Comment: One commenter \440\ believed that the exemption for 
technical infeasibility presents enforcement challenges. While an 
operator's demonstration of technical infeasibility must be signed and 
certified as to its truth, accuracy, and completeness, the commenter 
provided that there is no requirement that the EPA review and approve 
this demonstration prior to an operator's flaring. Rather, the proposal 
only required that operators retain records of the certified 
demonstration and provide them to the EPA as part of annual reporting. 
The commenter indicated that this lack of requirement raises the 
possibility that flaring will occur in the absence of a full, accurate, 
complete, or otherwise adequate demonstration. The commenter indicated 
that in order for the EPA to identify any problems or shortcomings in 
the certified demonstration, the EPA must review the operator's 
documentation, but this review will necessarily occur after an operator 
has flared, potentially for a considerable amount of time. The 
commenter states that this opens the door to extended periods of 
flaring in violation of the rules. Another

[[Page 16952]]

commenter \441\ asserted that the technical infeasibility exemption 
places a significant compliance monitoring burden on the EPA, or on 
states with delegated air quality programs.
---------------------------------------------------------------------------

    \440\ EPA-HQ-OAR-2021-0317-2433.
    \441\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA does not agree with these commenters. As 
explained above, the final NSPS OOOOb and EG OOOOc include provisions 
that allow owners and operators to make certain technical infeasibility 
demonstrations in limited circumstances. To the extent that an owner or 
operator makes such a showing, the EPA believes that the requirement to 
submit the demonstration and certification of infeasibility in the 
annual report provides the opportunity for the EPA and/or state agency 
to conduct a review. In the event that the owner or operator submits an 
inadequate or fraudulent determination, or no determination at all when 
they should have, they could be subject to penalties. In addition, the 
professional engineer or other individual who certified the 
demonstration could be subject to penalties, including criminal 
charges. Therefore, no changes were made to the proposed requirements 
for submission of the demonstrations and certifications.
    Comment: With respect to the certification process, one commenter 
\442\ recommended that the EPA require certification by an independent 
third party. The commenter pointed out that the EPA proposed to allow 
certification by either a professional engineer or a ``qualified 
individual with expertise in the uses of associated gas.'' Notably, per 
the EPA's proposal, an operator could use an in-house engineer or other 
qualified individual, such as a contractor. The commenter noted that 
there is no requirement that the individual be independent from the 
operator. Certification by an independent third party, rather than a 
professional engineer or a ``qualified individual with expertise in the 
uses of associated gas,'' either of whom could be an in-house 
individual or a person with significant ties to the company, will 
enhance the credibility and reliability of the report. Certification by 
an independent third party of all demonstrations seeking a flaring 
exception is necessary to ensure a robust, complete, and accurate 
demonstration of the reasons underlying the flaring request.
---------------------------------------------------------------------------

    \442\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA does not agree that it is necessary for the 
certifier to be an independent third party. In many cases, a person 
most knowledgeable about the well characteristics and specifics of the 
operation may be someone employed by the company. While the EPA 
understands the concern raised by the commenter about the certification 
being made entirely ``in-house,'' the EPA points out the severe 
penalties and repercussions that could occur for both the owner/
operator and the certifier, as discussed here.
    Comment: The commenter \443\ requested that the EPA further clarify 
that both the certifier and the owner/operator may be subject to 
penalties for submission of a fraudulent or significantly flawed 
certification. The commenter notes that this clarification is 
consistent with the EPA's proposal for pneumatic pumps. The EPA 
proposed to include a technical infeasibility exemption from the zero-
emissions pneumatic pump standard, provided an operator submits a 
demonstration certified by a qualified professional engineer or in-
house engineer with relevant experience. The EPA notes that it ``is 
committed to ensuring that this technical infeasibility provision is 
not abused or used as a loophole . . . ,'' pointing to the potential 
for enforcement actions to be levied against both the owner/operator 
and the certifier upon submission of a ``fraudulent, or significantly 
flawed'' certification. The commenter urges the EPA to clarify that 
this same potential penalty is applicable to the submission of 
``fraudulent, or significantly flawed'' certifications in the context 
of associated gas at the affected well facility, if the EPA retains the 
technical infeasibility exemption.
---------------------------------------------------------------------------

    \443\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA agrees with the commenter. Flaws in a certified 
engineering analysis may result in an exception being inapplicable and 
a related enforceable violation of the standards. Fraudulent or 
significantly flawed certifications may result in both civil and 
criminal liability and penalties for the owner, operator, and the 
person that makes the certification.
    Comment: One commenter \444\ suggested that operators seeking to 
routinely flare must submit a thorough analysis and engineering 
certification comparable to the initial certification each year. The 
commenter recommended that this demonstration include the same 
information as the initial demonstration, namely a detailed analysis 
documenting the technical infeasibility or safety reasons for the 
infeasibility and an explanation as to why none of the four gas 
recovery options are technically feasible or safe. Each annual 
demonstration must be certified.
---------------------------------------------------------------------------

    \444\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA agrees with this comment and has clarified that 
the exemption is only valid for a 1-year period and that a 
demonstration and certification must be conducted each year to continue 
to flare or route to control.
3. Gas Well Liquids Unloading Operations
    In section X.F.3 of this document, the final NSPS OOOOb and EG 
OOOOc requirements for gas well liquids unloading operations are 
summarized. The BSER analysis is unchanged from what was presented in 
the November 2021 Proposal (see 86 FR 63211-14, section XII.D: Proposed 
Standards for Well Liquids Unloading Operations). Two regulatory 
approaches were proposed in the November 2021 Proposal. As discussed in 
the December 2022 Supplemental Proposal, the EPA considered the 
comments submitted and revised the proposed requirements. Details of 
these comments, the EPA's responses, and the rationale for the 
supplemental proposal are provided in the December 2022 Supplemental 
Proposal Federal Register preamble. As discussed in section X.F.1 of 
this preamble, in the December 2022 Supplemental Proposal, the EPA 
proposed to define the ``affected facility'' as a single well. Further, 
the EPA proposed the ``modification'' definition to apply to a single 
well that undergoes hydraulic fracturing or refracturing. Significant 
comments were received on the December 2022 Supplemental Proposal on 
the following topics: (1) the EPA's proposed zero-emissions standard, 
and (2) the EPA's proposed recordkeeping and reporting requirements. 
For each of these topics, a summary of the proposed rule, the comments, 
the EPA responses, and changes made in the final rule (if applicable), 
are discussed as follows. These comments and the EPA's responses to 
these comments would apply to the standards proposed in both the NSPS 
OOOOb and EG OOOOc because the same standards apply for both new and 
existing sources. The EPA's full response to comments on the November 
2021 Proposal and December 2022 Supplemental Proposal, including any 
comments not discussed in this preamble, can be found in the EPA's RTC 
document for the final rule.\445\
---------------------------------------------------------------------------

    \445\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (6 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).

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

[[Page 16953]]

a. Zero-Emissions Standard
    In the December 2022 Supplemental Proposal, the EPA proposed 
regulatory text specifying that all gas well liquids unloading 
operations would be subject to the regulatory requirements. The BSER 
proposed was to employ techniques or technologies that eliminate 
methane and VOC emissions. Where meeting the zero-emissions standard is 
infeasible due to technical or safety reasons, the EPA proposed to 
require the employment of best management practices to minimize methane 
and VOC emissions during well liquids unloading operations to the 
extent possible.
    The December 2022 Supplemental Proposal, however, specifically 
requested further comment and additional information on an alternative 
approach to applicability, where the standards for gas well liquids 
unloading would only apply to well liquids unloading operations that 
result in vented emissions.\446\
---------------------------------------------------------------------------

    \446\ 87 FR 74782.
---------------------------------------------------------------------------

    Comment: Several commenters \447\ opposed the EPA's proposed zero-
emissions standard or asserted that the EPA should only regulate 
unloading operations that vent emissions.
---------------------------------------------------------------------------

    \447\ EPA-HQ-OAR-2021-0317-0777, -0808, -2227, -2238, -2254, -
2258, -2294, -2391, and -2446.
---------------------------------------------------------------------------

    Another commenter \448\ stated that the BSER must be technically 
feasible for the source category. The commenter provided a brief 
overview of the proposed standard under NSPS OOOOb that requires owners 
or operators to perform liquids unloading with zero methane or VOC 
emissions (86 FR 63179). The commenter mentioned that the proposed 
standard is based on a determination that non-emitting techniques 
constitute the BSER for these sources. At the same time, the commenter 
pointed out that the EPA acknowledged that non-emitting techniques are 
not always feasible or safe and that the EPA provides alternative 
standards to cover those situations.
---------------------------------------------------------------------------

    \448\ EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    In general, the commenter supported this approach as a practical 
matter and agreed that non-emitting measures and methods should be used 
where they are technically feasible and cost-effective. The commenter 
highlighted that the EPA rightly understands that non-emitting 
approaches are not always practicable and that imposing an absolute 
requirement would constitute an unwarranted prohibition on necessary 
operations, such as liquids unloading, in many situations. With that in 
mind, the commenter believed that the proposed alternative best 
management practice measures are a common-sense solution.
    Another commenter \449\ argued that the EPA should replace what the 
commenter believed was an infeasible zero-emissions standard with a 
requirement that the affected well liquids unloading operations 
minimize emissions through best management practices. The commenter 
stated that they have significant experience using a variety of 
practices to safely and effectively minimize the emissions associated 
with gas well liquids unloading but are concerned that those practices 
would not satisfy the EPA's proposed zero-emissions requirement. 
According to the commenter, there are many reasons why liquids may 
accumulate in a wellbore and require liquid unloading, some of which 
reasons are due to external factors not in the control of the well 
operator. The commenter stated that the proposed standard would 
necessitate a detailed review and discussion of infeasibility for each 
event with no benefit to emissions.
---------------------------------------------------------------------------

    \449\ EPA-HQ-OAR-2021-0317-0777.
---------------------------------------------------------------------------

    The commenter recommended that, rather than establishing the 
proposed zero-emissions standard with an exception for unloading with 
minimized emissions when zero-emissions unloading is technically 
infeasible, the EPA establish the use of best management practices to 
minimize methane and VOC emissions during liquids unloading events to 
the extent possible as the standard itself. The commenter warned that 
the program contemplated by the EPA sets an impossible compliance bar, 
and the commenter further reiterates that a standard to develop and use 
best management practices to minimize methane and VOC emissions during 
liquids unloading events to the extent possible will achieve the same 
emissions reductions while eliminating the unnecessary burdens 
associated with demonstrating that zero-emissions unloading is 
infeasible.
    Another commenter \450\ asserted that the rule should only apply to 
venting during liquids unloading. The commenter added that industry 
innovated to address the environmental problem of venting during 
liquids unloading, and they believe that the EPA's proposal would 
disincentivize this innovation. The commenter explained that 
malfunctions of designed zero[hyphen]emissions liquids unloading events 
would be addressed with designed venting events, with required best 
management practices that minimize emissions, and with recordkeeping 
and reporting.
---------------------------------------------------------------------------

    \450\ EPA-HQ-OAR-2021-0317-2227.
---------------------------------------------------------------------------

    Similarly, another commenter \451\ contended that the 
implementation of the rule would be easier if the standards only 
applied to wells that vent. However, the commenter suggested that the 
EPA only develop emissions requirements for facilities that vent 
emissions, not for facilities that would only vent emissions if 
something goes wrong or not as planned. In these situations, the 
commenter recommended the EPA develop separate requirements that would 
apply.
---------------------------------------------------------------------------

    \451\ EPA-HQ-OAR-2021-0317-2258.
---------------------------------------------------------------------------

    One commenter \452\ requested that, with respect to the emissions 
standards for liquids unloading, the EPA revise the rule so that an 
unloading event which does not result in venting to the atmosphere is 
not an affected facility.
---------------------------------------------------------------------------

    \452\ EPA-HQ-OAR-2021-0317-2238.
---------------------------------------------------------------------------

    Conversely, another commenter \453\ supported the November 2021 
Proposal to define affected facilities to cover all wells undergoing 
liquids unloading as a critical requirement to ensure that operators do 
not simply claim to conduct liquids unloading events with zero-
emissions techniques, when venting is occurring. The commenter noted 
that the EPA has recognized, ``under some circumstances venting could 
occur when a selected liquids unloading method that is designed to not 
vent to the atmosphere is not properly applied (e.g., a technology 
malfunction or operator error).'' \454\ The commenter contended that in 
some cases, the malfunction or error could be so great that it results 
in venting 100 percent of the gas intended to be captured. Because of 
this possibility, the commenter argued, the EPA must require 
recordkeeping so it is aware of these events and overall emissions, and 
to build an understanding of what causes these errors and how they can 
be prevented. The commenter recommended that the EPA finalize the 
December 2022 Supplemental Proposal's option 1 and require operators of 
all wells undergoing liquids unloading to maintain records of the 
number of unloading events that occur, the method used, and any venting 
that occurred.
---------------------------------------------------------------------------

    \453\ EPA-HQ-OAR-2021-0317-2433.
    \454\ 86 FR 63179, November 15, 2021.
---------------------------------------------------------------------------

    Response: The December 2022 Supplemental Proposal required that all 
liquids unloading events employ techniques or technologies that

[[Page 16954]]

eliminate methane and VOC emissions (i.e., a ``zero-emissions 
standard''). If this was not feasible for safety or technical reasons, 
the EPA proposed to allow for the employment of best management 
practices to minimize venting of emissions to the extent possible. The 
EPA received comments that provided arguments against the proposed 
zero-emissions standard. These commenters generally emphasized that 
liquids unloading operations vary widely and standards should only 
apply to events that vent to the atmosphere. While we proposed a zero-
emissions standard, we recognized that not every well that undergoes 
liquids unloading will be able to eliminate venting.
    The EPA has determined that, because of the intermittent and 
necessary nature of allowing for variable methods and technologies 
employed to unload liquids, the inability to measure emissions during 
events, and the often-unpredictable timing as to when owners and 
operators may need to vent emissions, a work practice standard is more 
appropriate than an emissions standard for liquids unloading 
operations. When evaluating whether it is appropriate to establish an 
emissions standard, one of the things the EPA considers is whether the 
application of a measurement methodology is practical due to 
technological or economic limitations. While emissions can be measured 
from an unloading event, it may not be practical for many unloading 
events to be directly measured (e.g., venting may not be anticipated or 
planned, type of technology employed to unload liquids does not lend 
itself to direct measurement of emissions). This is reflected in GHGRP 
subpart W required measurement and calculation methodologies. While in 
the August 2023 GHGRP subpart W proposal, the EPA proposed that 
emissions from liquids unloading under GHGRP subpart W must be 
calculated using direct measurements (calculation method 1) at least 
once every 3 consecutive years for each well, the proposal would 
continue to allow flexibility by allowing for the use of non-
measurement calculation methods to accommodate times where direct 
measurement is not feasible or practical. For example, GHGRP subpart W 
calculation method 1 includes direct measurements, and methods 2 and 3 
are non-measurement calculation methods. A very small percentage of 
events reported to the GHGRP (less than 3 percent for years 2015 to 
2019) for liquids unloading events were based on calculation method 
1.\455\
---------------------------------------------------------------------------

    \455\ 2023 Final Rule-Liquids Unloading GHGRP Basic 
Analysis.xlsx. [See 2023 Final Rule TSD Supporting Spreadsheet 
Attachments.]
---------------------------------------------------------------------------

    The EPA also agrees that, by requiring that the proposed best 
management practices be implemented for liquids unloading events that 
vent, the same emissions reductions would be achieved, while 
eliminating the requirement for an owner or operator to have to 
document why it is infeasible to utilize a non-venting method due to 
technical, safety, or economic reasons. The EPA believes that best 
management practices can be implemented to safely and effectively 
minimize the emissions associated with gas well liquids unloading. 
However, with respect to commenters who believe that a well affected 
facility/designated facility that conducts gas well liquids unloading 
should only include liquids unloading events that vent, we disagree. As 
one of the commenters noted, and we agree, unintended/unplanned venting 
could occur from a malfunction or error and the EPA would want owners 
and operators to be required to follow best management practices and 
other reporting and recordkeeping requirements. Owners or operators can 
and should develop best management plans to minimize venting during 
liquids unloading, to include both planned/designed venting events and 
those venting events that occur that are unplanned.
    To conclude, the EPA has maintained its proposal that each well 
affected facility that unloads liquids is subject to the requirement to 
employ techniques or technology(ies) that minimize or eliminate venting 
of emissions during liquids unloading events to the maximum extent. For 
unloading technologies or techniques that result in venting to the 
atmosphere, the final rule requires that owners or operators employ 
best management practices that meet minimum specified criteria to 
minimize venting of methane and VOC emissions for each gas well liquids 
unloading operation. Unloading events that employ non-venting liquids 
unloading technologies and techniques that do not result in venting of 
methane and VOC emissions to the atmosphere are not subject to best 
management plan requirements and the associated recordkeeping and 
reporting requirements under the rule. An owner or operator of a well 
affected facility that employs non-venting liquids unloading 
technologies and techniques is only required to comply with minimal 
recordkeeping and reporting requirements. In instances where there may 
be an unplanned venting event, that event would be subject to the best 
management practices to minimize venting of emissions and the 
associated recordkeeping and reporting requirements. The EPA believes 
that the final work practice standard and associated recordkeeping and 
reporting requirements will incentivize owners or operators of well 
affected facilities and well designated facilities to minimize or 
eliminate the venting of emissions to the extent possible during 
liquids unloading events.
b. Recordkeeping and Reporting Requirements
    In the December 2022 Supplemental Proposal, the EPA proposed 
specific recordkeeping and reporting requirements related to well 
liquids unloading operations. Wells that utilized a non-venting method 
would have been required to maintain records of the number of well 
liquids unloading operations that occur within the reporting period and 
the method(s) used for each well liquids unloading operation. A summary 
of this information would also have been required to be reported in the 
annual report. In recognition that under some circumstances, venting 
could occur when a selected liquids unloading method that is designed 
to not vent to the atmosphere is not properly applied (e.g., a 
technology malfunction or operator error), under the proposed rule, 
owners and operators in this situation would have been required to 
record and report these instances, as well as document and report the 
length of venting and what actions were taken to minimize venting to 
the extent possible. Additionally, for wells that utilize methods that 
vent to the atmosphere, the proposed rule would have required: (1) 
Documentation explaining why it is infeasible to utilize a non-venting 
method due to technical, safety, or economic reasons; (2) development 
of best management practices that ensure that emissions during liquids 
unloading are minimized; (3) employment of the best management 
practices during each well liquids unloading operation and maintenance 
of records demonstrating that the best management practices were 
followed; and (4) reporting in the annual report both the number of 
well liquids unloading operations and any instances where the well 
liquids unloading operations did not follow the best management 
practices.

[[Page 16955]]

    Comment: Several commenters \456\ requested that the EPA not 
require recordkeeping and reporting of non-venting liquids unloading 
events. One commenter \457\ suggested that operators conducting liquids 
unloading operations with zero methane and VOC emissions should not be 
subject to burdensome recordkeeping, reporting, and other requirements. 
One of the commenters \458\ noted that the non-vented liquids unloading 
reporting requirements are not feasible due to the nature of those 
events and because of the administrative burden associated with the 
reporting requirements with no net gain in emissions reductions. 
Similarly, one commenter \459\ requested that the EPA remove reporting 
requirements that do not provide valuable emissions-related 
information.
---------------------------------------------------------------------------

    \456\ EPA-HQ-OAR-2021-0317-0599, -0749, -2227, -2238, -2294, -
2326, -2391, and -2428.
    \457\ EPA-HQ-OAR-2021-0317-2227.
    \458\ EPA-HQ-OAR-2021-0317-0749.
    \459\ EPA-HQ-OAR-2021-0317-2258.
---------------------------------------------------------------------------

    Another one of the commenters \460\ opposed the proposed 
recordkeeping and reporting obligations on owners or operators, on the 
grounds that they would be burdensome and yield no environmental 
benefit for well unloading activities that do not vent. For example, 
they noted, owners or operators of well affected facilities where gas 
well liquids unloading occurs must submit annual reports: (1) 
identifying the well affected facility; (2) disclosing the number of 
gas well liquid unloading operations that occurred there during the 
reporting period; (3) describing the unloading operation method used 
each time; and (4) reporting any deviations in detail along with 
corrective actions. See, e.g., proposed 40 CFR 60.5410b(b) and 
60.5415b(b). The commenter stated that when unloading operations do not 
result in any vented emissions, these reports serve no purpose. To 
avoid this result, the commenter recommended that the EPA clarify that 
the standards for gas well liquids unloading operations apply only to 
those operations that result in emissions to the atmosphere. The 
commenter stated that this action would appropriately limit the 
recordkeeping and reporting obligations and would still allow the EPA 
to gather compliance information for a well that vents to the 
atmosphere during liquid unloading. The commenter added that the EPA 
should also make similar changes to proposed 40 CFR 60.5390c in EG 
OOOOc.
---------------------------------------------------------------------------

    \460\ EPA-HQ-OAR-2021-0317-2391.
---------------------------------------------------------------------------

    One commenter \461\ recommended that proposed recordkeeping and 
reporting for liquids unloading operations be simplified into a 
manageable framework for operators and streamlined for liquid unloading 
operations that vent to the atmosphere. The commenter noted that the 
information proposed by the EPA within 40 CFR 60.5420b and 40 CFR 
60.5420c for the recordkeeping and reporting as it pertains to liquid 
unloading operations is focused more on an operator's tracking and 
certifying techniques and less on allowing an operator to perform the 
necessary procedures to unload liquids accumulated within the wellbore 
and maintain natural gas production with as minimal emissions as 
possible. To address this shortcoming, the commenter suggested that the 
EPA define the data that operators should track per unloading operation 
and remove all superfluous records that generate additional burden for 
the operator and the EPA without added environmental benefit. The 
commenter provided that these suggestions assume that liquid unloading 
operations are to be conducted using a work practice standard.
---------------------------------------------------------------------------

    \461\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Furthermore, the commenter contended that the current proposed 
recordkeeping requirements do not offer a reasonable framework for 
operators to maintain compliance assurance. In fact, the commenter 
stated, the EPA has included a certification by a professional engineer 
for every instance a well unloading operation vents emissions to the 
atmosphere, in 40 CFR 60.5420b(c)(2)(ii)(B) and 40 CFR 
60.5420b(b)(3)(ii)(B), based on the proposed zero-emissions standard. 
The commenter noted that an owner or operator may not know about gas 
well liquids unloading events that result in venting of emissions to 
the atmosphere until the liquid operation is taking place, based on a 
variety of parameters. For context, the commenter stated that a single 
well affected facility may undergo multiple liquid unloading operations 
in a single compliance period. For example, one well may necessitate an 
unloading schedule of four times in a year. Based on best management 
procedures, three of these events may occur with zero emissions, while 
one of the events might vent to atmosphere for a short duration using 
the same technique. The commenter believed the justification provisions 
in 40 CFR 60.5420b(c)(2)(ii)(B) to be untenable when the same technique 
used on a well may result in zero emissions during some liquid 
operations but not during all liquid unloading operations in the same 
compliance period. The commenter asserted that the fact is that in some 
instances a well liquid unloading operation may need to vent emissions 
for a short duration, sometimes as little as 30 minutes, to safely 
perform the liquid unloading operation. The commenter therefore 
requested that the EPA:
    1. Remove the additional engineering certification statements under 
the guise of technical demonstrations. These additional certifications 
would be unnecessary if the standard followed a work practice 
procedure.
    2. Limit recordkeeping and reporting to liquid unloading operations 
that result in emissions. This would reduce the administrative burden 
for thousands of liquid unloading operation events. This is also 
consistent with how both Colorado and New Mexico have organized 
recordkeeping and reporting for their state regulations.
    Similarly, another commenter \462\ requested that the recordkeeping 
and reporting requirements be amended to be a workable framework for 
operators to assure compliance, including removal of the certification 
statement by an engineer in every instance that venting may occur.
---------------------------------------------------------------------------

    \462\ EPA-HQ-OAR-2021-0317-2248.
---------------------------------------------------------------------------

    Another commenter \463\ similarly argued that the EPA should not 
require recordkeeping or reporting for each well liquid unloading 
operation conducted during the year unless the EPA has defined ``well 
liquid unloading operation'' to mean only those well liquid unloading 
operations intended to vent to the atmosphere. As the EPA recognized in 
its supporting documentation, the commenter reports that one primary 
methodology that may be used to reduce or eliminate venting from 
removal of liquids of gas wells is a plunger lift. In most operational 
scenarios, a plunger lift will assist with liquid removal from the 
wellbore without any venting to the atmosphere. The plunger lift will 
operate either on a set cycle or based upon pressures reflected in the 
wellbore. However, not all plunger lifts are designed to have the 
necessary equipment onsite to track each cycle of the plunger lift. 
Thus, the commenter explains, the EPA's proposal could require 
installation of equipment to track the plunger cycles while providing 
no emissions reductions benefits. The commenter noted that the EPA has 
not fully evaluated the cost of installing and operating such tracking

[[Page 16956]]

equipment in the BSER analysis, and given that there will be no 
emissions benefits, the EPA cannot show that such a requirement would 
be cost-effective. The commenter added that even where equipment is 
available to track the number of wellbore liquids removal events that 
do not vent to the atmosphere, the operational costs of undertaking 
that tracking are considerable and the data collected would be 
significant. According to the commenter, the EPA has provided no 
reasonable explanation for its need to obtain and track data relating 
to the number of wellbore liquids removal events that do not vent to 
the atmosphere. The commenter also stated that the EPA provides 
virtually no explanation for its decision to stick with option 1, other 
than the fact that ``malfunctions'' can result in vented emissions from 
liquids removal operations that would otherwise meet the zero-emissions 
standard. The commenter added that the EPA has no basis for concern 
with respect to malfunctions as it has implemented a robust AVO and OGI 
inspection program that would be expected to identify wells that have 
emissions during liquids removal that were not expected or intended.
---------------------------------------------------------------------------

    \463\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    The commenter concluded that one simple solution to this problem is 
to define well liquids unloading to mean only those wellbore liquids 
removal events that are intended to vent to atmosphere. By defining 
well liquids unloading in such a manner, the commenter believed, the 
EPA would encourage operators to find solutions that eliminate venting 
and to ensure that operators not only implement certain emissions 
reduction requirements to reduce venting to atmosphere but also record 
and report on those instances that do result in venting to the 
atmosphere.
    One commenter \464\ cited from the EPA-referenced study by Dr. 
Allen, University of Texas, Environmental Science & Technology, 
December 9, 2014, Methane Emissions from Process Equipment at Natural 
Gas Production Sites in the United States: Liquids Unloadings, ``Some 
wells with plunger lifts are automatically triggered and unload 
thousands of times per year.'' The commenter stated that just a single 
well with thousands of unloading events per year would create a 
significant reporting burden, and when wells do not vent, they argued, 
this reporting should not be required.
---------------------------------------------------------------------------

    \464\ EPA-HQ-OAR-2021-0317-2446.
---------------------------------------------------------------------------

    Response: The EPA considered the commenters' concerns and examples 
provided regarding the burden associated with the proposed liquids 
unloading operations recordkeeping and reporting requirements. These 
concerns were evaluated along with the comments received on the zero-
emissions standard. The EPA agrees that requiring an owner or operator 
to comply with some of the proposed recordkeeping and reporting 
requirements in instances where an unloading event does not result in 
venting to the atmosphere would impose a burden without any added 
benefit environmentally (e.g., requiring that the number of liquids 
unloading events that occurred when implementing a non-venting liquids 
unloading technology or technique be tracked and reported).
    As discussed under section X.F.3.a of this document, the EPA has 
determined that the intermittent and necessary nature of the variable 
methods and technologies employed to unload liquids, the inability to 
reliably measure emissions, and the unpredictable nature as to when it 
may be necessary to vent emissions makes a work practice standard more 
practical and appropriate for liquids unloading operations than a zero-
emissions standard. As a result of this determination, the final rule 
requires owners or operators of an affected gas well facility that 
unloads liquids to employ techniques or technology(ies) that minimize 
or eliminate venting of emissions during gas well liquids unloading 
events to the maximum extent. For unloading events that result in 
venting to the atmosphere, the final rule requires owners or operators 
of well affected facilities/well designated facilities employ best 
management practices to minimize venting of methane and VOC emissions 
for each gas well liquids unloading operation, in addition to having to 
comply with the associated recordkeeping and reporting requirements. 
Where liquids unloading events were conducted using a technology/
technique that eliminates venting to the atmosphere, the final rule 
only requires owners and operators to report the identification of the 
well along with the non-venting technology or technique used in their 
annual report. Where unplanned venting occurs from these wells during a 
compliance period, an owner or operator would be required to follow 
their best management practices plan for such events and comply with 
the associated recordkeeping and reporting requirements for those 
events.
    As a work practice standard, the engineering certification 
statement that would be required under the December 2022 Supplemental 
Proposal, which would have required an explanation of why it is 
infeasible to utilize a non-venting method due to technical, safety, or 
economic reasons, is unnecessary and has been removed from the final 
rule. Additionally, because there is no longer a requirement to comply 
with a zero-emissions standard, there is no longer a need to maintain 
records or reports containing information on a change of compliance 
method from a zero-emissions standard to the implementation of best 
management practices and vice versa.
4. Well Completions
    In the November 2021 Proposal, the EPA proposed to retain the 
requirements found in NSPS OOOO and NSPS OOOOa for reducing methane and 
VOC emissions through REC and completion combustion. The BSER analysis 
is unchanged from what was presented in the November 2021 Proposal (see 
86 FR 63234-36, section XII.I: Proposed Standards for Well 
Completions). The proposed regulatory text included in the December 
2022 Supplemental Proposal was similar to the regulatory text found in 
40 CFR 60.5375a for NSPS OOOOa. While the regulatory text was similar, 
the EPA was made aware of potential confusion related to the well 
completion requirements and well completion recordkeeping requirements 
for wildcat wells, delineation wells, and low-pressure wells. 
Therefore, the proposed regulatory text for NSPS OOOOb included 
language to clarify these particular standards for new, modified, and 
reconstructed sources moving forward. First, the EPA proposed 
regulatory text at 40 CFR 60.5375b(f) to clearly state the requirement 
to route emissions from wildcat well, delineation well, and low-
pressure well completions to a completion combustion device in any 
instance (unless combustion creates a fire or safety hazard or can 
damage tundra, permafrost, or waterways). The EPA was also made aware 
from implementation of NSPS OOOOa that owners and operators were 
unclear as to whether they can choose to comply with 40 CFR 
60.5375a(f)(3)(ii) and make a claim of technical infeasibility for the 
separator to function, which then precludes the requirement to route 
recovered emissions to a completion combustion device. The EPA noted in 
the December 2022 Supplemental Proposal that this preclusion was not 
the EPA's intent in NSPS OOOOa and for this reason, we proposed to 
clearly specify at 40 CFR 60.5375b(f) that an alternative to routing to 
a separator (instead of routing all

[[Page 16957]]

flowback to a completion combustion device) is available only when the 
owner or operator is able to operate a separator and has the separator 
onsite (or otherwise available for use) and ready for use to comply 
with the alternative during the entirety of the flowback period. 
Second, the EPA proposed to eliminate recordkeeping requirements which 
are not necessary for wildcat wells, delineation wells, and low-
pressure wells that had previously been included in NSPS OOOOa. 
Specifically, the EPA proposed to not require records for 
``beneficial'' use of recovered gas (i.e., routed to the gas flow line 
or collection system, reinjected into the well or another well, used as 
an onsite fuel source, or used for another useful purpose that a 
purchased fuel or raw material would serve) nor records of ``specific 
reasons for venting in lieu of capture.'' These records were not 
required for wildcat wells, delineation wells, and low-pressure wells 
because the well completion standards at 40 CFR 60.5375b(f) require 
that all flowback, or gas recovered from flowback through the operation 
of a separator, be routed to a completion combustion device (i.e., 
there will not be an instance, when complying with 40 CFR 60.5375b(f), 
that beneficial use of recovered gas will occur).
    The EPA did not receive comments on the EPA's well completion 
proposed requirements that would lead the EPA to change what was 
proposed in the December 2022 Supplemental Proposal and the EPA has 
finalized the well completion requirements as proposed for both the 
NSPS OOOOb and EG OOOOc.

G. Centrifugal Compressors

    In section X.G of this document, the final NSPS OOOOb and EG OOOOc 
requirements for centrifugal compressors are summarized. The BSER 
analysis for wet seal centrifugal compressors is unchanged from what 
was presented in the December 2022 Supplemental Proposal (see 87 FR 
74784-85, section IV.G: Centrifugal Compressors). However, detailed 
comments were received on the December 2022 Supplemental Proposal on 
the following topics: (1) redefining the affected facility to include 
compressors with dry seals and the proposed standard, (2) the EPA's 
proposal to base the standard of performance as a numeric standard for 
self-contained wet seal compressors and centrifugal compressors 
equipped with dry seals, (3) the need to clarify that the standard is 
on a per-seal basis, (4) other inherently low-emitting compressor 
configurations, (5) the EPA's extension of requirements to centrifugal 
compressors located at centralized production facilities, and (6) wet 
seal compressors equipped with a seal oil gas separation system 
utilized on the Alaska North Slope (ANS). For each of these topics, a 
summary of the proposed rule (where relevant), the comments, the EPA 
responses, and changes made in the final rule (if applicable), are 
discussed here. These comments and the EPA's responses to these 
comments generally apply to the standards proposed in both the NSPS 
OOOOb and EG OOOOc. The instances where the comment and/or response 
only applies to the NSPS OOOOb or EG OOOOc are noted. The EPA's full 
response to comments on the November 2021 Proposal and December 2022 
Supplemental Proposal, including any comments not discussed in this 
preamble, can be found in the EPA's RTC document for the final 
rule.\465\
---------------------------------------------------------------------------

    \465\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

1. Redefining the Affected Facility To Include Centrifugal Compressors 
With Dry Seals and the Proposed Standard
    In the December 2022 Supplemental Proposal, the EPA redefined the 
affected facility to include compressors with dry seals and proposed a 
dry seal volumetric flow rate of 3 scfm (per seal) as a numeric 
emissions standard.
    Comment: Several commenters \466\ stated that the EPA should not 
adopt the proposed dry seal standard of 3 scfm (per seal) because that 
standard is unsupported and not adequately justified. Specifically, two 
commenters \467\ stated that the EPA must first obtain data--both on 
cost and, more importantly, on feasibility and reasonableness of the 
standard itself--to support a proper BSER analysis.\468\ Any other 
approach, according to the commenters, would be arbitrary and 
capricious. The commenters described three main concerns (with support 
for each of their concerns detailed in the RTC document for this 
action) with the BSER determination. These concerns included the 
following:
---------------------------------------------------------------------------

    \466\ EPA-HQ-OAR-2021-0317-2282, -2366, -2399, -2428, and -2483.
    \467\ EPA-HQ-OAR-2021-0317-2282 and -2483.
    \468\ For example, the commenters noted that the EPA has 
recently proposed to require measurements for dry seal compressors 
under the GHGRP, proposed ``Revisions and Confidentiality 
Determinations for Data Elements Under the Greenhouse Gas Reporting 
Rule,'' 87 FR 36920, 36974 (June 21, 2022). If the EPA finalizes 
that requirement, it will start collecting data for dry seal 
emissions.
---------------------------------------------------------------------------

    (1) The commenters stated that the BSER determination contains 
insufficient data to support the proposed standard or the cost that 
would be required to maintain it. The commenters specifically dispute 
the appropriateness of reliance on section 95668(d)(4-9), California's 
Regulations \469\ for Greenhouse Gas Emission Standards for Crude Oil 
and Natural Gas Facilities, to support the standard. Research into the 
underlying sources of the California Air Resources Board (CARB) 
regulation does not yield supporting information for the development of 
the 3 scfm standard. According to the commenters, there is no data in 
the California rulemaking supporting any numeric standard for dry 
seals, much less a specific rate of 3 scfm.
---------------------------------------------------------------------------

    \469\ https://ww2.arb.ca.gov/sites/default/files/2020-03/2017FinalRegOrdersGHGEmissionStandards.pdf.
---------------------------------------------------------------------------

    (2) The commenters stated that the BSER determination does not 
consider data showing that seal emissions rate is a function of 
compressor size and suction pressure, and consequently, the standard 
does not properly account for compressor size; and
    (3) The commenters stated that record is devoid of any information 
(or data) indicating that proper maintenance and repair could reduce 
such compressors' dry seal emissions rate to 3 scfm or less, or any 
information regarding the associated costs of doing so.
    Several commenters \470\ emphasized that more reliable information 
and data are or will be available that could be used in developing a 
dry seal emissions standard. One of the commenters stated that based on 
data submitted to the EPA pursuant to GHGRP subpart W for the 2021 
calendar year, dry seal compressor driver power output ranged between 5 
and 42,000 horsepower and for wet seals the compressor driver power 
output ranged between 40 and 53,665 horsepower.\471\ The commenter 
expressed that it does not believe compressors associated with the 
higher end of this range should be expected to operate the same as 
compressors closer to the lower end of this range.
---------------------------------------------------------------------------

    \470\ EPA-HQ-OAR-2021-0317-2282, -2366, -2428, and -2483.
    \471\ Information was extracted from the EPA's Envirofacts 
database using the GHG query builder: https://enviro.epa.gov/query-builder/ghg.
---------------------------------------------------------------------------

    Several commenters \472\ stated that, for transmission and storage, 
the majority of turbines are manufactured by Solar Turbines. The 
commenters suggested

[[Page 16958]]

that the Solar Turbine Product Information Letter (PIL) \473\ be 
considered as a superior reference compared to the Natural Gas STAR 
document. Information available from Solar shows that dry seal 
emissions rates are a function of compressor type (e.g., size) and 
operating (suction) pressure. The commenters reported that the PIL 
provides data plots for a range of compressor sizes and suction 
pressures. The commenters stated that the PIL data plots clearly 
indicate that 3 scfm will be exceeded during standard operations for 
many units and/or at many suction pressures that are common on 
transmission systems. Since that data shows higher emissions rates for 
many applications, the commenters contended that it alone refutes the 
basis of the EPA's proposed 3 scfm emissions rate. According to the 
commenters, if the EPA insists on proceeding with a standard for dry 
seal compressors at this time, the EPA should establish a standard 
based on function/operating conditions for the seal (i.e., unit size 
and suction pressure); or, if the standard is a single emissions rate, 
it must be high enough to address the largest units and highest suction 
pressures in natural gas operations.
---------------------------------------------------------------------------

    \472\ EPA-HQ-OAR-2021-0317-2282, -2366, and -2483.
    \473\ Solar Turbines Product Information Letter (PIL) 251, 
``Emissions from Centrifugal Compressor Gas Seal Systems,'' January 
2013 (Attachment C of their Comments). [Attachment C was redacted in 
full in Docket.]
---------------------------------------------------------------------------

    As a result of these concerns, some commenters provided 
recommendations to the EPA for development of a dry seal emissions 
standard:
    <bullet> One commenter \474\ stated that the EPA should supplement 
the docket with information to support why the proposed value is 
representative of the population of dry seal compressors across the 
nation (taking into consideration compressor size variability).
---------------------------------------------------------------------------

    \474\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    <bullet> Several commenters \475\ recommended that the EPA postpone 
establishing any type of quantitative threshold for dry seal 
centrifugal compressors until after it finalizes amendments to GHGRP 
subpart W. See 87 FR 36920 (June 21, 2022) (proposed rule). Once those 
amendments are implemented, the commenters contended, the EPA would 
have thousands of data points to give a more accurate dry seal 
centrifugal compressor measurements that can be used for a subsequent 
emissions threshold.
---------------------------------------------------------------------------

    \475\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
---------------------------------------------------------------------------

    <bullet> Several commenters \476\ stated that if the EPA decides to 
re-propose a numeric emissions standard for dry seal compressors, it 
must first identify reliable information about emissions rates that are 
achieved by well-maintained dry seal compressors and the maintenance/
replacement activity needed to achieve them. Because of the functional 
dependence on unit size and suction pressure, they contended, it is 
likely that a single emissions rate is not sufficient, unless that rate 
is high enough to address the largest units and highest suction 
pressures in natural gas operations.\477\ Second, they suggested that 
any emissions rate standard must be expressed as a per-seal 
standard.\478\ Finally, they stated that, if the standard would require 
yearly measurements and monitoring of these compressors for the first 
time, as the current proposal does, the cost of monitoring \479\ would 
be part of the proposed standard and should be accounted for in the 
BSER analysis.
---------------------------------------------------------------------------

    \476\ EPA-HQ-OAR-2021-0317-2282, -2399, and -2428.
    \477\ One of the commenters expressed that they also believed 
the EPA should investigate whether the types of onboard sensors that 
Solar Turbines provides with some of its models are prevalent in the 
industry. If that is the case, these sensors--even if they do not 
measure emission rates specifically--may be adequate to provide 
information about the health of the dry seals, possibly supporting a 
standard requiring seal replacement as recommended by the 
manufacturer.
    \478\ The source information cited by the EPA (the California 
regulation and EPA Natural Gas STAR document) clearly indicates that 
this is an emission rate per seal, as does the Solar Turbines PIL. 
If a dry seal emission rate threshold is retained in the final rule, 
the commenters stated, it should be clearly indicated that the rate 
applies on a per-seal basis.
    \479\ For example, a flow meter is estimated to cost upwards of 
$10,000 and installation also costs upwards of $10,000.
---------------------------------------------------------------------------

    One commenter \480\ noted that, in principle, they do not object to 
a standard for dry seal compressors. However, they suggested that the 
EPA should: (1) recognize that 3 scfm is an approximate average rate 
for some dry seal compressors, but it is not characteristic of units 
that may have an emissions rate several times higher--e.g., large 
compressors with relatively high suction pressure; (2) consider the 
upper end range or tiered emissions rates in the standard; (3) conduct 
analysis and consider cost effectiveness of installing a seal vent 
recovery/control system if the emissions rate cannot be met; (4) 
account for the cost of additional monitoring that a numeric standard 
would require; (5) clarify that the selected standard applies for each 
dry seal, not for the entire compressor; and (6) if a standard is 
retained (considering the factors above), propose a work practice 
standard and define the schedule for operators to resolve the issue 
when a unit exceeds its defined emissions rate threshold.
---------------------------------------------------------------------------

    \480\ EPA-HQ-OAR-2021-0317-2366.
---------------------------------------------------------------------------

    While several of the commenters \481\ specifically recommended that 
the EPA wait for more accurate data based on GHGRP subpart W, they 
added that, if the EPA is intent on establishing a dry seal emissions 
threshold before receiving the GHGRP subpart W reports, they 
recommended relying upon the manufacturer's specified maximum leak rate 
for a particular unit. The commenters noted that a recent review of dry 
seal leak curves from a major supplier of centrifugal compressors to 
the natural gas industry indicates that dry seal leakage rates can vary 
from 2 to 20 scfm per compressor (with two seals per compressor), 
depending on the make, model, and operating suction pressure of the 
compressor. If the EPA wishes to set one threshold applicable to all 
dry seal centrifugal compressors in this rulemaking, the commenters 
recommended that the EPA set the threshold at 10 scfm per primary dry 
seal to allow for sufficient variability among existing dry seal leak 
rates.
---------------------------------------------------------------------------

    \481\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
---------------------------------------------------------------------------

    Response: The EPA has evaluated these comments and acknowledges 
that the data available on dry seal compressor emissions and flow rates 
was limited and that a 3 scfm volumetric flow rate performance standard 
may not be achievable for some centrifugal compressors equipped with 
dry seals, even when properly maintained and the dry seal is not in 
need of repair. Prior to receipt of these comments and based on 
available information and data, it was believed that these higher-
emitting dry seal compressors represented compressors in need of repair 
or maintenance. In fact, the EPA had not previously regulated 
centrifugal compressors equipped with dry seals because they were 
considered low-emitting when compared with compressors equipped with 
wet seals. What has become evident, however, is that some centrifugal 
compressors equipped with dry seals emit more than previously believed 
and that a properly functioning compressor equipped with a dry seal can 
be higher-emitting than a centrifugal compressor equipped with a wet 
seal that is subject to requirements under NSPS OOOOb.
    Given that compressors equipped with wet seals are regulated under 
NSPS OOOO, NSPS OOOOa, and the final NSPS OOOOb, and given that 
compressors equipped with dry seals are known to emit more than some

[[Page 16959]]

compressors with wet seals, the final rule retains the requirement to 
conduct volumetric flow rate monitoring and associated maintenance and 
repair (as needed) of these compressors consistent with what is 
required for centrifugal compressors equipped with wet seals. However, 
the EPA has revised the proposed volumetric flow rate performance 
standard for centrifugal compressors with dry seals to be 10 scfm/seal 
(i.e., representing a maximum flow rate applicable to all dry seals). 
Based on manufacturer data provided on dry seal rate curves for 
differing compressor models and configurations, a 10 scfm per seal flow 
rate performance standard is supported as a maximum flow rate 
performance standard that could be applicable to all dry seals until 
additional flow rate and emissions data are obtained under GHGRP 
subpart W.
    The 10 scfm per seal flow rate performance limit reflects ordinary 
performance of a well-maintained unit, therefore minimal additional 
costs are expected. In many instances, compressors equipped with dry 
seals will already be required to conduct annual compressor vent 
volumetric flow rate monitoring under GHGRP subpart W. Owners or 
operators of these compressors will be subject to minor recordkeeping 
and reporting requirements, and maintenance and repair requirements 
would only apply where the volumetric flow rate performance standard of 
10 scfm per seal is exceeded. For owners or operators not already 
required to conduct annual compressor vent volumetric flow rate 
monitoring under GHGRP subpart W, the only additional cost is the cost 
of conducting the required volumetric flow rate monitoring. See 
discussion in section XI.G.2 of this document on the EPA's decision to 
establish centrifugal compressor flow rate performance standards as 
work practice standards and not as numeric limits where an exceedance 
would be considered a violation.
    As commenters noted, the EPA has requested flow rate/emissions 
information under GHGRP subpart W for compressors equipped with dry 
seals. Based on information received, the EPA may revisit and revise 
the 10 scfm per seal volumetric flow rate performance standard for 
compressors equipped with dry seals in the future.
2. Numeric Standard Versus Work Practice Standard
    In reviewing the BSER determination and standards for centrifugal 
compressors proposed in November 2021, the EPA stated that it is 
feasible to prescribe a standard of performance, rather than a work 
practice standard, for centrifugal compressors complying with the NSPS 
OOOOb self-contained wet seal centrifugal compressor and EG OOOOc wet 
seal compressor volumetric flow rate performance standards. The BSER 
was therefore proposed to conduct repair and maintenance activities to 
maintain emissions at or below a specified flow rate. Based on this 
rationale, the EPA proposed a numeric emissions limit requirement. The 
major difference between the numeric emissions limit standard proposed 
under the December 2022 Supplemental Proposal and what the EPA proposed 
in November 2021 was that under the December 2022 Supplemental 
Proposal, owners and operators would be required to maintain emissions 
at or below the specified emissions limit (a measured emissions flow 
rate) whereas under the November 2021 Proposal, owners or operators 
would have been required to conduct repairs and maintenance after 
discovering an exceedance of a flow rate of the specified numeric 
emissions limit (a measured emissions flow rate).
    Comment: Several commenters \482\ asserted that the rule should 
clarify the required compliance obligations, include a repair or 
replacement timeline, and eliminate avoidable emissions from repair to 
wet and dry seals. According to the commenters, the proposed NSPS rule 
was drafted to require an emissions flow rate limit for wet and dry 
seals. If the individual seal exceeds the 3 scfm (or a group of seals 
exceeds the applicable standard), the EPA expects the operator to 
repair or replace that seal, as appropriate.\483\ The proposed rule did 
not describe what is required if the measurement at the seal vent 
exceeds the applicable flow rate. The commenters recommend that dry 
seal centrifugal compressors and self-contained wet seal compressors be 
regulated through work practice standards. The commenters also 
recommend that the rule provide a proposed timeline for repair or 
replacements, as well as delay-of-repair provisions, consistent with 
nearly all other NSPS drafted by the EPA.
---------------------------------------------------------------------------

    \482\ EPA-HQ-OAR-2021-0317-2258, -2282, -2305, -2326, -2399, -
2428, and -2483.
    \483\ See, e.g., 87 FR at 74711-12 (table 3).
---------------------------------------------------------------------------

    According to one commenter,\484\ the EPA, without sufficient 
explanation, summarily turned California's work practice standard into 
an emissions rate limitation. The commenter alleged there is nothing in 
the record about what measures would need to be implemented, and the 
associated cost, to meet such a limitation. The commenter stated that a 
delay-of-repair provision in such a regulatory scheme appropriately 
recognizes that the unit must be shut down to effect any such repair 
and replacement and that parts availability and supply chain 
disruptions may be relevant to how quickly the repair or replacement 
can be made. In addition, the commenter stated there is no record 
information indicating that it is feasible for the source to anticipate 
that a well-functioning wet seal that meets the 3 scfm limitation for 1 
year will exceed it before the next year's test, or the cost of doing 
so (if possible).
---------------------------------------------------------------------------

    \484\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------

    Several commenters \485\ suggested that the EPA allow one of the 
following corrective actions by an operator within 2 years if the 
applicable flow rate performance standard is exceeded:
---------------------------------------------------------------------------

    \485\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
---------------------------------------------------------------------------

    (1) repair or replace the dry seal, wet seal, or internal seal gas 
recovery system; and
    (2) route emissions from the dry seal vent through a closed vent 
system or from the degassing vent using a cover and closed vent system 
a control device; or
    (3) route emissions from the primary dry seal vent through a closed 
vent system or route the degassing vent using a cover and closed vent 
system to a process.
    The commenters \486\ recommended that if an operator cannot 
complete the corrective action within 2 years, then a corrective action 
plan with work scope and alternate schedule be submitted to the EPA 
under a work-practice-based framework. According to the commenters, 2 
years is a reasonable corrective action period since the corrective 
actions listed can require significant planning, scheduling, 
engineering, and construction. They explain that exceedance of the flow 
rate performance standard after 2 years (in the absence of a corrective 
action plan), or after the time stated in the corrective action plan, 
would result in a deviation subject to recordkeeping and reporting 
requirements similar to other types of compressors.
---------------------------------------------------------------------------

    \486\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
---------------------------------------------------------------------------

    Some commenters \487\ stated that the delay-of-repair provision is 
consistent with delay-of-repair requirements under 40 CFR 
60.5397a(h)(3), requiring repair within 2 years, or the next scheduled 
shutdown (whichever is earlier), where repairs are technically 
infeasible, where repairs would require a vent blowdown,

[[Page 16960]]

a compressor station shutdown, a well shutdown, or well shut-in, or 
where it would be unsafe to repair. Further, the commenters added that 
the EPA has taken this approach before in most of its NSPS 
regulations.\488\ In fact, the EPA has also proposed a delay-of-repair 
approach in other contexts of the December 2022 Supplemental Proposal 
for the NSPS where emissions caused by the repair would exceed the 
existing leak rate.\489\
---------------------------------------------------------------------------

    \487\ EPA-HQ-OAR-2021-0317-2282 and -2399.
    \488\ See, e.g., 40 CFR 60.482-9(c)(1) (delay of repair allowed 
if emissions of purged material resulting from immediate repair are 
greater than the fugitive emissions likely to result from delay of 
repair), and 40 CFR 60.5416(b)(10) (delay of repair permitted if 
emissions resulting from immediate repair would be greater than the 
fugitive emissions likely to result from delay of repair).
    \489\ See, e.g., proposed 40 CFR 60.5400b(h)(6)(ii)(A) (Delay of 
repair showing requires in part ``that emissions of purged material 
resulting from immediate repair are greater than the fugitive 
emissions likely to result from delay of repair.'').
---------------------------------------------------------------------------

    One commenter \490\ suggested 90 days as a reasonable timeframe 
given the significant variety of repair methods (including replacement) 
that may be appropriate for these units, as the EPA recognizes in its 
preamble.
---------------------------------------------------------------------------

    \490\ EPA-HQ-OAR-2021-0317-2282.
---------------------------------------------------------------------------

    Several commenters \491\ proposed revisions to regulatory language 
to implement the requested work practice approach and delay-of-repair 
provision.
---------------------------------------------------------------------------

    \491\ EPA-HQ-OAR-2021-0317-2282 and -2483.
---------------------------------------------------------------------------

    Response: The EPA acknowledges that the record for the 3 scfm per 
seal volumetric flow rate performance standard supports a work practice 
standard and not a numeric standard for centrifugal compressors 
equipped with wet seals. This is because the application of a 
measurement methodology to centrifugal compressors is not always 
practicable due to technological or economic limitations. It is not 
practicable here for an exceedance of the 3 scfm per seal volumetric 
flow rate to be a violation when the annual performance-based flow rate 
reflects whether there are performance issues with a seal that need to 
be addressed in order to take action to minimize the emissions/leak. 
This is similar to the basis and monitoring established for fugitive 
emissions component requirements, where a leak based on periodic 
monitoring triggers requirements to minimize the emissions/leak.
    The final rule has therefore been revised so that the format of the 
3 scfm per-seal performance-based volumetric flow rate performance 
standard for compressors equipped with wet seals is implemented as a 
work practice standard and not as a numeric limit where an exceedance 
would be considered a violation. Specifically, the final rule for 
reducing GHGs and VOC from new centrifugal compressors is repair or 
replacement of the wet seal where, based on the required monitoring, 
the per-seal volumetric flow rate performance standard is exceeded. If 
the volumetric flow rate measurement of the centrifugal compressor is 
greater than 3 scfm (in operating or standby pressurized mode) or a 
combined compressor seal rate greater than the number of compressor 
seals multiplied by 3 scfm, an owner or operator must repair or replace 
the centrifugal compressor seal within 30 calendar days after the date 
of the volumetric emissions measurement. As such, for centrifugal 
compressors equipped with wet seals, the volumetric flow rate of 3 scfm 
is an action level that, if exceeded, triggers the action of repairing 
or replacing the seal and is not a numeric limit.
    Delay-of-repair provisions under a work practice standard 
appropriately recognize that the unit must be shut down to affect any 
such repair and replacement and that parts availability and supply 
chain disruptions may be relevant to how quickly the repair or 
replacement can be made. As such, the final rule allows for a delay of 
repair if the repair or replacement would require a vent blowdown, or 
it would otherwise be infeasible or unsafe, until the next process unit 
shutdown. Specifically, delay of repair would be allowed if the repair 
or replacement of a seal (1) is technically infeasible, (2) would 
require a vent blowdown, (3) would require a process unit or facility 
to shut down, (4) needs to be delayed because parts or materials are 
unavailable, or (5) would be unsafe to repair during operation of the 
unit. In cases where there is a need for a delay of repair, the repair 
must be completed during the next scheduled process unit or facility 
shutdown for maintenance, after a scheduled vent blowdown, or within 2 
years, whichever is earliest.
    Delay-of-repair provisions under a work practice standard 
appropriately recognize that the unit must be shut down to effect any 
such repair and replacement and that parts availability and supply 
chain disruptions may be relevant to how quickly the repair or 
replacement can be made. As such, the final rule allows for a delay of 
repair if the repair or replacement would require a vent blowdown, or 
it would otherwise be infeasible or unsafe, until the next process unit 
shutdown. Specifically, delay of repair would be allowed if the repair 
or replacement of a seal (1) is technically infeasible, (2) would 
require a vent blowdown, (3) would require a process unit or facility 
to shut down, (4) needs to be delayed because parts or materials are 
unavailable, or (5) would be unsafe to repair during operation of the 
unit. In cases where there is a need for a delay of repair, the repair 
must be completed during the next scheduled process unit or facility 
shutdown for maintenance, after a scheduled vent blowdown, or within 2 
years, whichever is earliest. Delay of repair beyond the next scheduled 
compressor shutdown for maintenance is allowed for a centrifugal 
compressor wet and dry seal, if seal replacement is necessary during 
the compressor shutdown for maintenance, seal supplies have been 
depleted, and seal supplies had been sufficiently stocked before the 
supplies were depleted. Delay of repair beyond the next compressor 
shutdown for maintenance will not be allowed unless the next compressor 
shutdown for maintenance occurs sooner than 6 months after the first 
compressor shutdown for maintenance.
    The format of the volumetric flow rate performance standard for 
centrifugal compressors equipped with dry seals has also been revised 
in the final rule as a work practice standard and not as a numeric 
limit. However, for centrifugal compressors equipped with dry seals, 
the volumetric flow rate performance standard is 10 scfm per seal and 
not 3 scfm per seal (see section XI.G.1 of this document for discussion 
on centrifugal compressors with dry seals). As such, for centrifugal 
compressors equipped with dry seals, the volumetric flow rate of 10 
scfm is an action level that, if exceeded, triggers the action of 
repairing or replacing the seal and is not a numeric limit.
3. Clarification That the Standard Is Based on a Per-Seal Basis
    Comment: Several commenters \492\ requested clarification that the 
volumetric standard applies to each seal and not each compressor and 
that the rule text clearly address manifolded vents on a combined basis 
to reflect this. The commenters cited the precedent set by the CARB 
where wet seal compressors in California are restricted to 3 scfm per 
seal, and not per compressor as set forth in 17 Code of Colorado 
Regulations (CCR) section 95668.
---------------------------------------------------------------------------

    \492\ EPA-HQ-OAR-2021-0317-2258, -2282, -2305, -2366, -2399, -
2428 and -2483.
---------------------------------------------------------------------------

    One of the commenters \493\ noted that the EPA's preamble 
discussion, and at least some of the proposed rule text, imply that the 
emissions rate would be

[[Page 16961]]

on a per-seal basis, and the commenter understands this to be the EPA's 
intent. The commenter asserted that it is important that the EPA's 
final rule more clearly reflect this intent. Specifically, according to 
the commenter, the proposed text provided in 40 CFR 60.5380b or 40 CFR 
60.5385b(a) (and parallel EG OOOOc language) does not provide the 
distinction that the limits are per seal. The commenter asserted that 
it would be impractical for a compressor with multiple seals 
(centrifugal) to operate in the same way as a compressor with only a 
single seal.
---------------------------------------------------------------------------

    \493\ EPA-HQ-OAR-2021-0317-2282.
---------------------------------------------------------------------------

    The commenter \494\ stated that the rule language must more clearly 
address manifolded vents on a combined basis. The commenter noted that 
the December 2022 Supplemental Proposal preamble provided that the 
manifolded wet and dry seal flow rate must be ``less than or equal to 
the number of compressors multiplied by 3 scfm (in operating or standby 
pressurized mode).'' The commenter supported this approach, as it 
reflects the practicalities of measuring emissions from manifolded 
seals. The commenters also note that the approach is supported by the 
2006 Natural Gas STAR report, which states that emissions rates from 
two seal systems would be double the emissions from a single seal 
system.
---------------------------------------------------------------------------

    \494\ EPA-HQ-OAR-2021-0317-2282.
---------------------------------------------------------------------------

    The commenters elaborated on why they believed that this was the 
EPA's intent (for the standard to be based on a per-seal basis) and 
several commenters provided in-line regulatory text changes where they 
believed the clarification was needed.
    Response: The EPA agrees that the basis and intent of the standard 
is that it be applied on a per-seal basis and that clarity was needed 
in the NSPS OOOOb and EG OOOOc regulatory text. The final rule 
regulatory text has been revised to make this clear as suggested by the 
commenters. Specifically, clarifying changes have been made to 40 CFR 
60.5380b, paragraphs (a)(5) through (7) of NSPS OOOOb, and 40 CFR 
60.5392c, paragraphs (a)(1) and (2), of EG OOOOc.
4. Other Inherently Low-Emitting Compressor With Wet Seal 
Configurations
    Comment: In their comments on the November 2021 Proposal, one 
commenter \495\ stated that one type of low-emissions wet seal utilized 
in compressors in the transmission and storage sector is a mechanical 
seal, in which metal (tungsten carbide) is seated against carbide, with 
oil pressing against the outside of the actual seal. Because the oil is 
not in contact with the natural gas, the commenter explains that these 
wet seals have generally zero degassing emissions. According to the 
commenter, it makes no sense to subject such a zero-emissions wet seal 
to control requirements. Accordingly, the EPA should exclude 
compressors utilizing mechanical wet seals from the requirements 
otherwise applicable to wet seal compressors.
---------------------------------------------------------------------------

    \495\ EPA-HQ-OAR-2021-0317-0415 and -1391.
---------------------------------------------------------------------------

    The commenter \496\ provided additional information on mechanical 
seals in their comments on the December 2022 Supplemental Proposal for 
the EPA to evaluate that provided support that, with respect to 
mechanical wet seals, when a differential pressure is maintained on the 
system, there is no off-gassing of the lube oil. The commenter attached 
an example to their comment letter that shows that the oil is pumped 
via the seal oil pump to the seal gas bottle, when the seal oil 
pressure is maintained at 32 psi above discharge gas pressure.
---------------------------------------------------------------------------

    \496\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------

    Response: The EPA has evaluated the information provided by the 
commenter on mechanical seals for both the November 2021 Proposal and 
the December 2022 Supplemental Proposal. The EPA has made the 
determination that mechanical wet seals are inherently low-emitting 
where (1) a differential pressure is maintained on the system, (2) 
there is no offgassing of the lube oil, and (3) the mechanical seal is 
integrated into the compressor housing. As such, the final rule 
definition of self-contained wet seal compressor has been revised, for 
purposes of regulation, to include mechanical wet seals where (1) a 
differential pressure is maintained on the system, (2) there is no off-
gassing of the lube oil, and (3) the mechanical seal is integrated into 
the compressor housing. Self-contained wet seal centrifugal compressors 
are allowed to meet a 3 scfm/seal volumetric flow rate limit in lieu of 
being required to route emissions via a CVS to a control device or 
process under NSPS OOOOb.
5. Applicability of Requirements to Compressors Located at Centralized 
Production Facilities
    The EPA proposed in the November 2021 Proposal \497\ to define 
centralized production facilities separately from well sites because 
the numbers and sizes of equipment, particularly reciprocating and 
centrifugal compressors, are larger than for standalone well sites, 
which would not be included in the proposed definition of ``centralized 
production facilities.'' In the 2016 NSPS OOOOa, the EPA exempted 
reciprocating and centrifugal compressors located at well sites from 
the applicable compressor standards. However, the EPA believed the 
definition of ``well site'' in NSPS OOOOa may have caused confusion 
regarding whether centrifugal compressors located at centralized 
production facilities were also exempt from the standards, which was 
not our intent.
---------------------------------------------------------------------------

    \497\ See 86 FR 63110 at 63184-85 (November 15, 2021).
---------------------------------------------------------------------------

    To clarify our intent, the EPA defined centralized production 
facility as follows in the December 2022 Supplemental Proposal in both 
the NSPS OOOOb and EG OOOOc:

    Centralized production facility means one or more storage 
vessels and all equipment at a single surface site used to gather, 
for the purpose of sale or processing to sell, crude oil, 
condensate, produced water, or intermediate hydrocarbon liquid from 
one or more offsite natural gas or oil production wells. This 
equipment includes, but is not limited to, equipment used for 
storage, separation, treating, dehydration, artificial lift, 
combustion, compression, pumping, metering, monitoring, and 
flowline. Process vessels and process tanks are not considered 
storage vessels or storage tanks. A centralized production facility 
is located upstream of the natural gas processing plant or the crude 
oil pipeline breakout station and is a part of producing operations.

    Additionally, the EPA defined the affected facility under the NSPS 
OOOOb (and designated facility under EG OOOOc) as:

    (b) Each centrifugal compressor affected facility [and 
designated facility under the EG OOOOc], which is a single 
centrifugal compressor. A centrifugal compressor located at a well 
site is not an affected facility under this subpart. A centrifugal 
compressor located at a centralized production facility is an 
affected facility under this subpart.

    For purposes of analyses, the EPA determined it was appropriate to 
apply the same emission factors to centrifugal compressors located at 
centralized production facilities as those used for centrifugal 
compressors at gathering and boosting compressor stations. Given the 
results of that analysis, the EPA proposed to apply the proposed NSPS 
OOOOb requirements to centrifugal compressors located at centralized 
production facilities. At that time, the EPA proposed a new definition 
for ``centralized production facility'' intended to distinguish 
compressors at standalone well sites where the EPA has determined that 
the standard should not apply.

[[Page 16962]]

    Comment: One commenter \498\ requested that the EPA clarify the 
applicability of compressor standards to well sites. The commenter 
stated that the definition proposed for central[ized] production 
facilities may extend applicability to compressors located at well 
sites, which have historically been exempt from the compressor 
standards. As the EPA stated they have not updated their cost analyses 
with new information with respect to well sites, the commenters believe 
that extending applicability to well sites was not the EPA's intent. 
Another commenter \499\ urged the EPA to keep the current compressor 
exemptions shown in both subparts NSPS OOOO and OOOOa. The commenter 
specifically requests that the EPA maintain that each compressor 
``located at a well site, or an adjacent well site and servicing more 
than one well site, is not an affected facility.''
---------------------------------------------------------------------------

    \498\ EPA-HQ-OAR-2021-0317-0808.
    \499\ EPA-HQ-OAR-2021-0317-0923.
---------------------------------------------------------------------------

    Response: The EPA has finalized the proposed requirements related 
to the definitions of the centrifugal compressor affected facility/
designated facility and centralized production facility. Some of the 
commenters suggested that, by extending requirements to centralized 
production facilities, the EPA was extending requirements to well sites 
where centrifugal compressors were not previously regulated. That 
interpretation confirms that clarity was needed. Based on the proposed 
definition of the centrifugal compressor affected facility/designated 
facility, in addition to the proposed definition for centralized 
production facility as proposed in the December 2022 Supplemental 
Proposal, we believe that we clarified our intent. That intent is that 
centrifugal compressors located at well sites are not subject to 
requirements. However, centrifugal compressors located at centralized 
production facilities that consist of equipment at a single surface 
site used to gather, for the purpose of sale or processing to sell, 
crude oil, condensate, produced water, or intermediate hydrocarbon 
liquid from one or more offsite natural gas or oil production wells 
(including centrifugal compressors) are subject to centrifugal 
compressor requirements.
6. Wet Seal Compressors Equipped With a Seal Oil Gas Separation System 
Utilized on the Alaska North Slope (ANS)
    Comment: One commenter \500\ representing Alaska oil and natural 
gas companies requested that the EPA revise the proposed EG for 
existing wet seal centrifugal compressors to address the 
characteristics of the wet seal compressors deployed in Alaska oil 
production operations. The commenter reported that their members use 
wet seal compressors at their Alaska North Slope (ANS) and Cook Inlet 
production fields to increase the pressure of residual gas captured in 
production operations to enable delivery to gas processing plants and/
or reinjection into well fields. They noted that there are about 40 
compressor trains on the ANS installed for this purpose. The 
compressors in use on the ANS were installed in the late 1970s through 
mid-1980s and have not been modified or reconstructed. They range in 
size from 15,140 hp to 53,665 hp. None are currently subject to NSPS 
OOOO or NSPS OOOOa.
---------------------------------------------------------------------------

    \500\ EPA-HQ-OAR-2021-0317-2317.
---------------------------------------------------------------------------

    The commenter stated that all the wet seal centrifugal compressors 
in Alaska are equipped with a seal oil gas separation system that 
separates gas from the sour seal oil exiting the compressor seal 
assembly, upstream from the degassing drum. On the ANS the gas captured 
in the seal oil trap is routed to various outlets for use as turbine 
fuel, low-pressure fuel gas, compressor suction, flare purge or to 
flare (for destruction). In Cook Inlet the gas is processed for 
delivery to market. The commenter noted that the EPA described this 
technology enthusiastically in the 2014 Natural Gas STAR Report.\501\ 
Sour seal oil passes through a ``seal oil trap,'' a type of separator, 
prior to routing to the seal oil degassing drum. The commenter 
described the seal oil traps in their comments on the November 2021 
Proposal, which they resubmitted on the December 2022 Supplemental 
Proposal. The commenter included a process flow diagram of the seal oil 
recovery system on an ANS wet seal compressor. The commenter added that 
the EPA's 2014 Natural Gas STAR Report praised the seal gas recovery 
system deployed on the ANS as ``highly effective at capturing degassing 
emissions from wet seal centrifugal compressors . . .'' \502\
---------------------------------------------------------------------------

    \501\ EPA, Wet Seal Degassing Recovery System for Centrifugal 
Compressors (2014) at 3 (``2014 Natural Gas STAR Report''), included 
as attachment A to their comment letter.
    \502\ 2014 Natural Gas STAR Report.
---------------------------------------------------------------------------

    While the commenter supported the concept of adopting a volumetric 
limit based on diligent maintenance and repair as BSER for control of 
emissions from wet seal compressor vents, they asserted that the record 
does not support that the proposed 3 scfm limit can be met for all wet 
seal compressors. The commenter expressed support for the concept of 
adopting a flow rate limit based on maintenance and repair as BSER for 
control of emissions from wet seal compressor vents because they 
believe that such an option avoids the safety risks, engineering 
challenges, and extravagant cost of capturing and flaring low-volume, 
low-pressure vent streams. They asserted that the problem with the EG 
OOOOc proposal is that the 3 scfm proposed limit does not account for 
variability in the size and configuration of wet seal compressors 
within the source category and is not demonstrated or achievable for 
wet seal compressors of the size and configuration of those deployed in 
oil and gas production operations in Alaska.
    The commenter stated that they would support the designation of 
seal oil traps as an EG OOOOc compliance option for Alaska wet seal 
compressors. For several reasons, however, Alaska wet seal compressors 
equipped with seal oil traps do not uniformly meet the proposed 3 scfm 
limit. They explained that the volume of seal oil slip from a wet seal 
compressor correlates with compressor shaft size, pressure, and speed. 
Alaska wet seal compressors span a broad range of capacities, and the 
degassing drums serving the larger units vent higher volumes of seal 
gas. Attachment C to their comments provides a table showing flow rate 
data from 27 wet seal compressor degassing vents sampled by AOGA member 
Hilcorp for the EPA GHG emissions reporting. The table shows the flow 
rate per seal, but a single degassing drum can discharge gas from up to 
four seal oil traps. The variability in the data reflects the 
variability in size and configuration of the compressors and the fact 
that each seal oil trap operates on a discharge cycle, and a degassing 
drum may receive sour seal oil from up to four different seal oil traps 
at any moment. Depending on when in the cycle the sample is taken, the 
per-seal flow rate can exceed 3 scfm.
    Based on the degassing drum flow rate data summarized in table 1 
(of attachment C to their comment letter), the commenter proposed a 
volumetric flow limit for Alaska wet seal compressor vents of 9 scfm of 
methane and VOCs per seal, multiplied by the number of compressor seals 
venting through a common stack. For example, they note that a two-stage 
compressor has four seals (two per stage), all of which are manifolded 
into one vent to the atmosphere. If the per-seal flow limit was 9 scfm, 
the flow limit for the common vent should be 36 scfm.
    Response: The EPA reviewed information materials submitted by 
commenters related to the wet seal

[[Page 16963]]

centrifugal compressors in Alaska equipped with a seal oil gas 
separation system that separates gas from the sour seal oil exiting the 
compressor seal assembly, upstream from the degassing tank. These 
compressors are considered inherently low-emitting based on Natural Gas 
STAR and emissions/process information provided by the commenter. These 
wet seal compressors with the sour seal oil traps recapture gas and 
route the gas to the flare (simple pit flares), not to the ``compressor 
suction [as with defined self-contained wet seal compressors].'' These 
systems cannot always meet a 3 scfm limit due to the intermittent 
process affecting flow.
    The final EG OOOOc rule provides a new definition for a 
``centrifugal compressor equipped with sour seal oil separator and 
capture system'' and requires that, in Alaska, such compressors be 
allowed to meet a performance-based volumetric flow rate standard of 9 
scfm/seal, in lieu of the 3 scfm/seal performance-based volumetric flow 
rate standard to account for the variability in the flow rate data 
provided by the commenter that reflects the variability in size and 
configuration of these compressors and the fact that each seal oil trap 
operates on a discharge cycle, and a degassing drum may receive sour 
seal oil from up to four different seal oil traps at any moment.
    The final rule definition reads as follows:

    Centrifugal compressor equipped with sour seal oil separator and 
capture system means a wet seal centrifugal compressor system which 
has an intermediate closed process that degasses most of the gas 
entrained in the sour seal oil and sends that gas to either another 
process or combustion device. The de-gas emissions are routed back 
to a process or combustion device directly from the intermediate 
closed degassing process; after the intermediate closed process the 
oil is ultimately recycled for recirculation in the seals to the 
lube oil tank where any small amount of residual gas is released 
through a vent.

    Comment: In addition to the commenter's \503\ concerns related to 
the proposed volumetric performance-based standard requirement, the 
commenter added that the NSPS OOOOb capture and control requirements 
for new wet seal compressors are also not reasonably achievable for 
existing compressors in Alaska. The commenter noted that the December 
2022 Supplemental Proposal's proposed EG OOOOc offers the NSPS OOOOb 
control options as a fallback for wet seal compressors that cannot meet 
the presumptive 3 scfm flow limit, but they stated that these options 
would require a cover on the degassing drums, connected through a 
closed vent system to process or to a control device that achieves a 
95.0 percent reduction in emissions, should an existing compressor ever 
be modified or reconstructed. The commenter stated that in Alaska oil 
and gas production operations there is no cost-effective option to 
recover degassing drum emissions. Degassing drums vent small volumes of 
methane and VOCs at atmospheric pressure. They referred to flow rates 
reported in attachment C \504\ of their comment letter. They explained 
that the volumes reported are small because the seal oil traps capture 
and recycle most of the seal gas upstream of the degassing drum. They 
reported that operators would need to install new compression devices 
to boost degassing drum vent gas pressure to the approximately 20 psi 
that would enable delivery of those streams to the flare header line. 
The commenter stated that larger new compression devices would be 
required to boost vent gas to a much higher pressure that would enable 
delivery to a process line for injection into subsurface reservoirs.
---------------------------------------------------------------------------

    \503\ EPA-HQ-OAR-2021-0317-2317.
    \504\ Attachment C--Table of data titled, ``Hilcorp Alaska Wet 
Seal Combustion Turbines, Volumetric Flow Rate Per Seal (2016-2011). 
(Attachment C of their comment letter.)
---------------------------------------------------------------------------

    According to the commenter, the combination of low methane and VOC 
recoveries with high capture costs makes the capture and control 
alternative very expensive on a cost-per-ton basis. They referred to 
Kinder Morgan's comments on the November 2021 Proposal, where Kinder 
Morgan provides that the 95.0 percent reduction requirement is 
technically infeasible and cost-prohibitive even for wet seal 
compressors located on natural gas pipelines in the lower 48 
states.<SUP>505 506</SUP> For wet seal compressors deployed in Alaska 
production operations with seal oil traps, the cost per ton of covering 
the degassing drum vents and reducing emissions from those vents by 
95.0 percent would be prohibitive.
---------------------------------------------------------------------------

    \505\ Comments of Kinder Morgan Inc. on EPA Proposed Standards 
and Emissions Guidelines for the Oil and Natural Gas Sector at 8-20, 
Document ID No. EPA-HQ-OAR-2021-0317-1375 (``Kinder Morgan 
Comments'').
    \506\ The ``lower 48'' consists of the 48 adjoining U.S. states 
and the District of Columbia of the United States of America. The 
term excludes the only two noncontiguous states, which are Alaska 
and Hawaii, and all other offshore insular areas, such as the U.S. 
territories of American Samoa, Guam, the Northern Mariana Islands, 
Puerto Rico, and the U.S. Virgin Islands.
---------------------------------------------------------------------------

    Response: As discussed earlier in this document, the EPA agrees 
that ANS compressors equipped with a sour seal oil separator and 
capture system are inherently low-emitting and that the costs of 
requiring routing to a control device or process would be cost-
prohibitive for these compressors due to technical and costly retrofits 
that would be needed (e.g., would need to install new compression 
devices to boost degassing drum vent gas pressure) if any of their 
existing ANS compressors were to be modified or reconstructed. The 
commenters provided information and data to support their request that 
these sources be allowed to meet a performance-based volumetric flow 
rate standard in lieu of having to route emissions to a control device 
or process. As provided by the commenter, and the EPA agrees, 
recovering degassing drum emissions that vent small volumes of methane 
and VOC at atmospheric pressure because the seal oil traps capture and 
recycle most of the seal gas upstream of the degassing drum would not 
be cost-effective. The final standards for NSPS OOOOb have been revised 
to be consistent with what is being required under the EG OOOOc 
presumptive standards. As such, the NSPS OOOOb final rule has been 
revised to include a new definition for a ``centrifugal compressor 
equipped with sour seal oil separator and capture system'' and requires 
that, in Alaska, such compressors be allowed to meet a performance-
based volumetric flow rate standard of 9 scfm/seal. The volumetric flow 
rate of 9 scfm is an action level that, if exceeded, triggers the 
action of repairing or replacing the seal and is not a numeric limit.

H. Combustion Control Devices

    In section X.H of this preamble, the final NSPS OOOOb and EG OOOOc 
requirements for combustion control devices are summarized. The 
rationale for the proposed requirements was presented in the December 
2022 Supplemental Proposal in section IV.H. Combustion Control 
Devices.\507\ This section of the preamble presents a summary of 
significant comments received on the proposed requirements for 
combustion control devices and the EPA's response to those comments, as 
well as changes the EPA has made to the control device requirements 
since the December 2022 Supplemental Proposal. The EPA's full response 
to comments on the November 2021 Proposal and December 2022 
Supplemental Proposal, including any comments not discussed in this 
preamble, can be found in the EPA's RTC document for the final 
rule.\508\
---------------------------------------------------------------------------

    \507\ See 87 FR 74792-74796 (December 6, 2022).
    \508\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).

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

[[Page 16964]]

1. Outlet Concentration Limit
    Comment: Some commenters \509\ wanted to ensure that the 
concentration limit included in NSPS OOOOa for existing enclosed 
combustors will continue to be allowed in NSPS OOOOb and EG OOOOc. One 
commenter \510\ explained that destruction efficiency testing requires 
VOC sampling at the inlet and outlet of the control device but that 
many existing control devices do not have an inlet sampling port. The 
commenter notes that combined with the potential need to install 
additional monitoring equipment, allowing the use of a 20 ppm 
concentration limit will provide facilities that do not have inlet 
testing ports an alternative to meet compliance requirements for both 
NSPS OOOOb and EG OOOOc. Another commenter \511\ stated that the 
continuous monitoring option for organic compound concentration in the 
control device exhaust is meaningless without the corresponding outlet 
concentration performance standard. Additionally, the commenter 
requested that the EPA clarify how operators should handle compliance 
for existing control devices that are complying with the total organic 
compound concentration standard under NSPS OOOO or OOOOa.
---------------------------------------------------------------------------

    \509\ EPA-HQ-OAR-2021-0317-2399 and -2428.
    \510\ EPA-HQ-OAR-2021-0317-2399.
    \511\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA agrees that it is likely that most enclosed 
combustion devices that are being used to control affected facilities 
in NSPS OOOO and NSPS OOOOa demonstrate compliance during the 
performance test with the alternative outlet concentration limit 
instead of testing both the inlet and outlet of the control device. It 
remains the EPA's position that it is reasonable to allow owners and 
operators to continue to demonstrate compliance for these units with an 
outlet concentration. It is also plausible that owners and operators 
will have affected facilities under both NSPS OOOOb and EG OOOOc 
controlled by the same enclosed combustion device, and so we are adding 
the outlet concentration limit to both NSPS OOOOb and EG OOOOc.
    In response to the comments received, the EPA is adding an outlet 
concentration limit of 275 ppm volume as propane on a wet basis to both 
NSPS OOOOb and EG OOOOc. This is the same outlet concentration limit 
that is in NSPS OOOO and NSPS OOOOa. We anticipate that carrying over 
this limit would not require a new performance test for most of these 
existing control devices until the next periodic performance test is 
due or until operation of the control device changes in a manner that 
warrants a new performance test.
2. Monitoring Flares
    Comment: A commenter \512\ stated that while they support the 
requirements for no visible emissions and for monthly monitoring using 
EPA Method 22, the EPA could also consider alternative monitoring 
technologies and methods that would achieve equivalent or superior 
results. The commenter urged the EPA to also require flares and control 
devices to be monitored for compliance assurance during all fugitive 
emissions surveys, both under the OGI and AVO program and under the 
alternative periodic screening options. The commenter noted that 
control devices and flares, especially unlit and malfunctioning flares, 
are among the most observed and largest sources of methane emissions, 
and it is therefore critical that they are regularly inspected and 
monitored to ensure proper operation.\513\ The commenter further stated 
that multi-basin research has identified unlit flares across the entire 
country, and a Permian Basin study using flights conducted in 2020 
found that 5 percent of all active flares were unlit.\514\ Moreover, 
the commenter contends that monitoring flares and control devices 
during fugitive emissions surveys poses very little additional burden 
and can ensure emissions events are avoided.
---------------------------------------------------------------------------

    \512\ EPA-HQ-OAR-2021-0317-2433.
    \513\ The commenter cited to Genevieve Plant, et al., 
Inefficient and Unlit Natural Gas Flares Both Emit Large Quantities 
of Methane, 377 Sci. 6614 (2022), https://www.science.org/doi/10.1126/science.abq0385, and Daniel H. Cusworth, et al., 
Intermittency of Large Methane Emitters in the Permian Basin, 8 
Env't Sci. Tech. Letters 567 (2021), https://pubs.acs.org/doi/abs/10.1021/acs.estlett.1c00173, as examples.
    \514\ The commenter cited to David R. Lyon, et al., Concurrent 
Variation in Oil and Gas Methane Emissions and Oil Price During the 
COVID-19 Pandemic, 21 Atmos. Chem. Phys. 6605 (2021), https://acp.copernicus.org/articles/21/6605/2021/.
---------------------------------------------------------------------------

    Response: The EPA agrees that requiring owners and operators to 
check flare operation during a fugitive emissions inspection adds 
little additional burden and can help to reduce the incidence of unlit 
flares. This is something some owners and operators already do in 
practice, because in reviewing reports submitted under NSPS OOOOa, we 
noted that many owners and operators listed flares in the fugitive 
emissions report. Additionally, for technologies used under the 
provisions of the periodic screening and continuous monitoring advanced 
methane detection technology work practices in the final NSPS OOOOb and 
EG OOOOc, we anticipate that by the nature of the operation of these 
technologies, these technologies will detect unlit flares. Therefore, 
requiring owners and operators to look at flares during an OGI 
inspection will also help to even the playing field for all 
technologies used in fugitive emissions monitoring. In the final rule, 
we are requiring owners and operators to view the operation of their 
flares with an OGI camera during fugitive emissions inspections 
conducted with OGI to ensure that the flare is lit and that there are 
no uncontrolled emissions coming from the flare. We are also requiring 
owners and operators to ensure that the flare is operating properly 
during AVO inspections by visually confirming that the pilot flame is 
lit and operating properly.
    Comment: A commenter \515\ stated that with respect to the 
alternative to continuous flow monitoring, the EPA must include 
requirements to reassess the engineering assessment when there are 
changes to the sources vented to the flare, such as when additional 
sources are routed to the control device, or those upstream sources 
change, because the flow rate could increase, and proper destruction 
efficiency would not be ensured.
---------------------------------------------------------------------------

    \515\ EPA-HQ-OAR-2021-2362.
---------------------------------------------------------------------------

    Response: The EPA agrees with the commenter that the assessment for 
maximum flow rate to an enclosed combustor or flare must be updated 
when there are changes to the device's operation that are expected to 
impact the initial assessment. We have revised the language in the 
final rule to reflect this requirement.
3. Visible Emissions Observations
    Comment: Commenters suggested that the EPA should permit the use of 
cameras for operators to perform visual inspections of flare and 
combustor smoke under EPA Method 22.\516\ Visible light cameras such as 
security cameras are widely available and deployed at oil and gas 
sites, and they can be positioned such that they can view potential 
smoke from combustors and flares. Therefore, commenters request that 
the EPA clarify that operators can utilize visible light cameras to 
remotely observe flares and combustors for smoke and specify 
installation and operation requirements such cameras need to

[[Page 16965]]

meet. Another commenter \517\ noted that video camera systems are 
allowed as an alternative to EPA Method 9 observation under broadly 
applicable approved Alternative Test Method 82 (ALT-082).\518\ 
Commenters also suggested that artificial intelligence and machine 
learning should be allowed to continuously screen the video feed for 
smoke detection and if smoke is detected, alert the operator that an 
EPA Method 22 follow-up is required.\519\
---------------------------------------------------------------------------

    \516\ EPA-HQ-OAR-2021-0317-2336, -2428, -2298, and -2326.
    \517\ EPA-HQ-OAR-2021-0317-2428.
    \518\ https://www.epa.gov/sites/default/files/2020-08/documents/alt082.pdf.
    \519\ EPA-HQ-OAR-2021-0317-2336 and -2428.
---------------------------------------------------------------------------

    Response: The EPA agrees that camera systems that monitor for 
visible emissions are a viable alternative to monthly EPA Method 22 
observations for this sector, and there is already precedent for use of 
such systems in refineries under 40 CFR part 63, subpart CC. Therefore, 
the EPA has added the option to use a camera system for visible 
emissions observations to the final rule. In order for an owner or 
operator to use this option, the owner or operator must provide real-
time, high-definition video surveillance camera output to the nearest 
control room or other continuously manned location where the camera 
images may be viewed at any time, with the output recorded 
continuously. The camera must be located at a reasonable distance above 
the flare flame and no further than 400 meters from the emissions 
source, at an angle suitable for visual emissions observations with the 
sun not in the field of view. With this option, observation via the 
video camera feed can be conducted readily throughout the day and will 
allow the operators of the flare to watch for visible emissions more 
frequently. The operator must document that they observed the camera 
feed for at least one minute each day. We note that this option is not 
the same as the digital opacity camera alternative outlined in ALT-082 
which is not applicable in this rulemaking, as there is no opacity 
limit in the rule.
    The EPA has not added an option that allows for automated viewing 
of the camera feed with artificial intelligence or machine learning, 
because we have no information demonstrating that these systems work 
effectively or under what circumstances these systems may encounter 
problems with adequately identifying visible emissions. Owners or 
operators are welcome to use such systems in addition to the 
requirements of the rule.
4. Measurement of NHV
    Comment: Several commenters \520\ were concerned with the proposed 
NHV monitoring provisions for flares, which would require continuous 
monitoring of the NHV unless the initial NHV sampling demonstration 
(hourly sampling for 10 days) shows that the NHV is consistently above 
the applicable NHV value, which is dependent on the flare type. 
Commenters stated that the initial NHV sampling demonstration to show 
that the NHV of a gas stream is always above the required NHV in 40 CFR 
60.18(b) is unnecessarily burdensome and is even more burdensome than 
what is required for refineries.\521\ Commenters suggest that the 
proposed initial NHV sampling demonstration as an alternative to 
continuous NHV monitoring should be simplified, because the NHV of vent 
streams from affected facilities is typically fixed or well above the 
minimum NHV requirements, as these vent streams consist of mostly 
hydrocarbons and the simplest hydrocarbon has a NHV of approximately 
900 British thermal units per standard cubic foot (Btu/scf), which is 
well above the minimum NHV requirement proposed by the EPA. One 
commenter \522\ provided data collected from laboratories that analyze 
samples of associated gas and flared gas in North Dakota. Out of 7,774 
gas samples collected and analyzed from 2020 through 2022, the average 
NHV was 1,459 Btu/scf, while the maximum and minimum values were 1,007 
and 2,846 Btu/scf.
---------------------------------------------------------------------------

    \520\ EPA-HQ-OAR-2021-0317-2248, -2305, -2326, -2353, -2399, and 
-2428.
    \521\ The commenter pointed to 40 CFR 63.670(j)(6)(D).
    \522\ EPA-HQ-OAR-2021-0317-2248.
---------------------------------------------------------------------------

    One commenter \523\ stated that since the vent streams from 
affected facilities are expected to have sufficient heating value, both 
the proposed continuous NHV monitoring and the initial NHV sampling 
demonstration are economically unreasonable. For the minimum NHV 
demonstration alternative, the commenter reports that the cost is 
expected to be $250,000 or more per demonstration. The commenter 
summarizes that the cost of a vendor-conducted 10-day continuous 
monitoring campaign for the initial NHV sampling demonstration is 
estimated at a minimum of $250,000 to $275,000 while the cost of 200 
hourly samples is estimated at a total of $300,000 to $400,000 with an 
average cost per sample of $1,500 to $2,000 including shipping and 
analysis.
---------------------------------------------------------------------------

    \523\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    One commenter \524\ suggested that the EPA require a 10-day test 
period with one sample every 6 hours, for a total of 40 sample 
analyses. Another commenter \525\ proposed a simplified sampling 
protocol for samples to be taken twice a day for 7 days. A third 
commenter \526\ stated that the 10-day initial NHV sampling 
demonstration should be simplified to a single sample including the use 
of an appropriate, representative sample or an initial flare compliance 
assessment under 40 CFR 60.18, with the operator documenting why the 
sample is characteristic of the vent stream composition. After the 
initial NHV sampling demonstration, continuous compliance would be 
demonstrated through subsequent samples once every 3 years. The 
commenters also stated that neither the continuous NHV monitoring nor 
the initial NHV sampling demonstration alternative should be required 
if operators can demonstrate that the NHV is never expected to be below 
the minimum required value using a design evaluation or applicable 
engineering calculations including process simulation software and 
pressurized liquids sampling. One commenter \527\ stated that 
continuous monitoring of NHV presents inaccuracy issues associated with 
low or intermittent gas streams due to technological limits. While the 
commenter agrees with the availability of the initial NHV sampling 
demonstration in lieu of continuous monitoring, the commenter requested 
that the EPA allow operators to periodically (i.e., quarterly) sample 
representative inlet gas streams to demonstrate compliance with any 
applicable heating value requirement for control devices used to 
control affected facilities with intermittent or low flow gas streams 
under this rule.
---------------------------------------------------------------------------

    \524\ EPA-HQ-OAR-2021-0317-2305.
    \525\ EPA-HQ-OAR-2021-0317-2399.
    \526\ EPA-HQ-OAR-2021-0317-2428.
    \527\ EPA-HQ-OAR-2021-0317-2298.
---------------------------------------------------------------------------

    A different commenter \528\ stated that the EPA must require direct 
NHV monitoring at all oil and gas flares and combustion devices on a 
continuous basis. The commenter states the NSPS general provisions 
mandate that the Agency establish monitoring for the general 
provisions' NHV operating limits, especially since the general 
provisions themselves contain no monitoring requirements for this 
limit. The commenter also stated that the EPA correctly concludes that 
the current operating and monitoring practices and

[[Page 16966]]

requirements for well sites and centralized production facilities are 
not adequate to ensure that flare control systems are operated 
efficiently. The commenter was concerned with the proposed alternative 
initial NHV sampling demonstration. The commenter suggested that 10 
days of sampling cannot capture the variability of gas streams at oil 
and gas facilities, due in part to compositional variability, inert 
gases, and impurities in gas streams, and that it may not capture the 
lowest NHV streams, giving the false impression that these facilities 
are meeting the NHV operating limit when in fact they are not. The 
commenter also stated that the alternative to continuous monitoring is 
contradicted by findings the EPA has made regarding the great 
variability of gas compositions over short periods of time and the 
resulting dramatic effects on combustion efficiencies.\529\ The 
commenter contends that this alternative cannot ensure that flares and 
other control devices destroy 95 percent of VOCs and methane and that 
this alternative does not fulfill the requirements of 40 CFR 60.18(d).
---------------------------------------------------------------------------

    \528\ EPA-HQ-OAR-2021-0317-2362.
    \529\ The commenter cited to the proposed CAA section 112(d)(6) 
review for Miscellaneous Organic Chemical Manufacturing. See 84 FR 
69203 (December 17, 2019).
---------------------------------------------------------------------------

    Response: The EPA disagrees with the comments that neither 
continuous monitoring nor the initial NHV sampling demonstration (which 
the EPA proposed as an alternative to continuous monitoring) is 
unnecessarily burdensome or its cost unreasonable because the NHV value 
will always (or is expected to always) be above the NHV values that we 
proposed and are finalizing in this action. Specifically, we disagree 
with the commenters' assumption that the NHV value will always (or is 
expected to always) be above the minimum NHV values. As noted by a 
commenter, the variability of gas compositions can have a dramatic 
effect on the combustion efficiency of flares. This is especially true 
for streams that may contain large amounts of inert materials. 
Additionally, the EPA does not have data to support the assertion made 
by the commenter that continuous sampling systems have technological 
issues with sampling low and intermittent gas streams.
    Nevertheless, in response to the comments received, the EPA has 
reevaluated the proposed alternative initial NHV sampling demonstration 
to see whether the burden can be reduced without compromising its 
adequacy. We do not think it is appropriate to allow quarterly sampling 
or a one-time sample, as suggested by some commenters, since there is 
some variability in the streams that are sent to flares and enclosed 
combustion devices which will likely be missed by not sampling daily. 
However, we are reducing the number of daily samples associated with 
the initial NHV sampling demonstration. Specifically, we are finalizing 
a requirement to conduct twice daily sampling for 14 days, reducing the 
total number of samples from 240 to 28. However, due to the significant 
reduction in the initial sampling, we need to confirm that the vent gas 
NHV remains above the required minimum value. Therefore, we are adding 
to the NHV demonstration alternative an ongoing compliance 
demonstration requirement to sample the vent gas to confirm that the 
NHV remains above the required minimum value. We are requiring three 
samples to be taken every 5 years. This ongoing demonstration timeline 
aligns with the timeline for conducting periodic performance tests of 
enclosed combustion devices, which is required every 5 years, so owners 
and operators who are using enclosed combustion devices to meet the 
applicable emission standards in this rule will be able to combine the 
NHV vent gas sampling with the performance test, which will help to 
reduce the burden associated with the ongoing compliance demonstration. 
Additionally, where associated gas from a well affected facility is the 
only inlet stream to the enclosed combustion device or flare, we are 
not requiring owners and operators to conduct continuous monitoring of 
the NHV or the alternative NHV sampling demonstration. In this case, 
because associated gas is high in methane content and similar in 
quality to sales grade gas, the NHV of the inlet stream to the enclosed 
combustion device or flare is considered to be sufficiently above the 
minimum required NHV for the inlet gas, and sampling is not needed to 
confirm the NHV of the inlet stream. With the changes discussed above, 
we believe that the burden of the NHV demonstration alternative in the 
final rule is much reduced since proposal.
    While the EPA agrees with the comment that the variability of gas 
compositions can have a dramatic effect on the combustion efficiency of 
flares, the EPA disagrees with the commenter's contention that the 
alternative initial NHV demonstration is somehow contradicted by the 
EPA's prior statements in the proposed CAA section 112(d)(6) review for 
Miscellaneous Organic Chemical Manufacturing (84 FR 69203 (December 17, 
2019)). The EPA notes that the great variability of gas compositions 
over short periods of time and the resulting dramatic effects on 
combustion efficiencies is especially true for streams that may contain 
large amounts of inert materials, such as nitrogen padding from storage 
vessels, which is common in the refining and chemical sectors. However, 
in general, we do not expect to see those situations in the upstream 
oil and gas sector, where most vent gas streams consist of high 
percentages of methane, which has an NHV well above the required 
minimum flare gas NHV. We also note that, in the preamble for the 
Miscellaneous Organic Chemical Manufacturing risk and technology review 
cited by the commenter, the flare discussion focused on flares that 
burn ethylene oxide and olefins/polyolefins.\530\ Olefins and 
polyolefins are more difficult to combust than the small, straight-
chain hydrocarbons generally found in the upstream oil and gas sector. 
Therefore, the EPA does not believe that the alternative provided in 
the final rule is contradicted by the findings in the Miscellaneous 
Organic Chemical Manufacturing risk and technology review.
---------------------------------------------------------------------------

    \530\ See 84 FR 69198-69199 (December 17, 2019).
---------------------------------------------------------------------------

    Comment: One commenter \531\ stated that some vent streams from 
affected facilities could potentially be below the minimum NHV 
requirement, including compressors in acid gas service or those at 
enhanced oil recovery facilities. The commenter notes that either 
situation could have high CO<INF>2</INF> content which would lower the 
NHV, so operators typically add assist gas or another vent stream with 
sufficient heating value to facilitate proper control device operation. 
In these limited situations, the commenter proposed that flow 
monitoring of the assist gas and vent streams should be allowed as an 
alternative to the continuous monitoring of NHV.
---------------------------------------------------------------------------

    \531\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA disagrees that monitoring assist gas flow rates 
is an appropriate measure for ensuring proper combustion of inerts, as 
assist gas does not contain any heating value. Therefore, the 
introduction of assist gas will further reduce the heating value of the 
gas, possibly to a point where proper combustion cannot be sustained. 
Therefore, while monitoring or limiting assist gas is an important part 
of ensuring proper flare operation, the EPA does not believe that 
monitoring assist gas on its own can compensate for the drop in vent 
gas NHV caused by inerts or provide enough information for the

[[Page 16967]]

owner or operator to ensure that proper combustion is occurring.
    The introduction of inerts can greatly affect the NHV of the vent 
stream sent to a flare. While the EPA agrees that most flare gas 
streams at upstream oil and gas facilities will have no issue meeting 
the required minimum NHV on a continuous basis, we are concerned about 
situations where inerts may be introduced into the vent gas stream. To 
guard against the possibility of unacceptable flare gas NHV in these 
situations, we are including as part of the alternative NHV 
demonstration a requirement that owners and operators consider sources 
of inerts that may be sent to the flare, and that sampling must occur 
when the highest percentage of inerts are sent to the flare to ensure 
that NHV remains above the required minimum. If an owner or operator 
cannot ensure that the NHV remains above the required minimum due to 
the introduction of inerts, the owner or operator must continuously 
monitor the NHV of the vent stream.
5. Assisted Flares
    Comment: A commenter \532\ urged the EPA to require any assisted 
flares in the oil and gas sector to meet an operating limit for the NHV 
in the combustion zone (NHVcz), as the EPA has done for flares at 
refineries and petrochemical sources. The commenter stated that, as the 
EPA found in its 2014-15 refinery NESHAP rulemaking, many studies have 
shown that the flare requirements in the general provisions cannot 
ensure that flares achieve 98 percent destruction efficiency, which is 
required under the refinery NESHAP.\533\ The commenter also referenced 
an Enforcement Alert \534\ the EPA distributed regarding flaring 
violations, in which the Agency recognized that certain needed 
parameters affecting the efficiency of flares are not captured within 
the general provisions, including maintaining the appropriate steam-to-
vent-gas ratio and ensuring that the NHVcz is high enough to maximize 
combustion efficiency. The commenter explained that the EPA noted that 
reliance on the NHV of the vent gas--the parameter that the NSPS and 
NESHAP general provisions flare requirements use as an indicator of 
good combustion--ignores any effect of steaming. Therefore, the 
commenter stated that to incorporate steaming, a NHVcz is calculated to 
include the assist steam.\535\ The commenter stated that because 
complying with an operating limit for the heating value of the vent gas 
cannot ensure 95 percent or greater destruction efficiency of VOCs and 
methane by assisted flares, it is appropriate to update the flare 
requirements for any assisted flares to ensure proper destruction 
efficiencies. The commenter stated that the EPA must require owners and 
operators to comply with an operating limit for NHVcz and must 
promulgate monitoring requirements to ensure compliance with that 
limit.
---------------------------------------------------------------------------

    \532\ EPA-HQ-OAR-2021-0317-2362.
    \533\ The commenter cited 79 FR 36905 and 80 FR 75189.
    \534\ The commenter cited to EPA, EPA Enforcement Targets 
Flaring Efficiency Violations, Enforcement Alert (August 2012).
    \535\ EPA (U.S. Environmental Protection Agency). 2012. 
Parameters for Properly Designed and Operated Flares. Prepared for 
U.S. Environmental Protection Agency, Office of Air Quality Planning 
and Standards, Research Triangle Park, NC. April 2012. Available at: 
https://www3.epa.gov/airtoxics/flare/2012flaretechreport.pdf. See p. 
3-32.
---------------------------------------------------------------------------

    Response: The EPA is aware that some companies are installing air-
assisted flares to improve combustion efficiency, reduce smoking 
incidence of flares, and facilitate operation when inerts are added to 
the vent gas stream.\536\ We are still not aware of a prevalence of 
steam-assisted flares in this sector, but it is possible to over-assist 
an air-assisted flare. Therefore, in the final NSPS OOOOb, we are 
adding requirements to ensure that these flares are operated in a 
manner that will ensure good combustion efficiency, by adding operating 
parameters for NHVcz and the NHV dilution parameter (NHVdil). 
Specifically, the final rule includes the operating parameter values of 
270 Btu/scf for NHVcz and 22 Btu/sqft for NHVdil that the EPA 
established for the petroleum refineries sector (40 CFR part 63, 
subpart CC).\537\ We recognize that these limits were intended to 
demonstrate compliance with a destruction efficiency of 98 percent and 
therefore are conservatively high for demonstrating compliance with the 
applicable standards in NSPS OOOOb. We have added provisions similar to 
those in 40 CFR 63.670(j)(6) which allow reduced monitoring for owners 
and operators with flare gas streams that have a consistent composition 
or a fixed minimum NHV. As stated above, we expect many flares in the 
upstream oil and gas sector to burn high NHV streams and anticipate 
that most owners and operators would be able to use these provisions. 
Additionally, for air-assisted flares, we have added provisions that 
allow a demonstration that based on the highest fixed or highest air-
assist rate used, the device will meet or exceed NHVdil in lieu of 
continuously monitoring the air-assist rate.
---------------------------------------------------------------------------

    \536\ See, e.g., EPA-HQ-OAR-2021-0317-2409 and -2428.
    \537\ See discussion in EPA-HQ-OAR-2010-0682-0206.
---------------------------------------------------------------------------

    We are not adding these requirements to the final EG OOOOc because 
we are concerned about the ability of existing sites to retrofit flares 
in order to meet these requirements. While we do expect that most 
owners and operators will be able to demonstrate compliance through 
flare assessments, those who cannot demonstrate compliance through an 
assessment will have to conduct continuous sampling of flare vent 
streams and flowrate monitoring of both the flare vent stream and the 
air assist stream. These accommodations can easily be made for a new 
flare. For an existing flare at an existing site, these retrofits 
require taking the flare out of service and may require adding ports to 
set up these monitoring systems. Additionally, there is no guarantee 
that ports can be placed at an appropriate location. Without additional 
information on assisted flares at existing sites and the ability of 
owners and operators to retrofit these flares, we are reluctant to 
place these requirements on existing sources, and as such, we are not 
adding these requirements to the final EG OOOOc.
6. Alternative Flare Monitoring
    Comment: A commenter \538\ recommended that the EPA consider adding 
an alternative approach for monitoring flares that is more cost-
effective and will achieve the same objective. The commenter pointed 
out that there have been significant advancements in the field of flare 
performance monitoring technology in recent years, including the Video 
Imaging Spectral Radiometry (VISR) technology which has been developed 
to remotely and directly monitor flare combustion efficiency and the 
Simplified VISR technology which has been developed to remotely monitor 
NHVcz for steam-assisted flares and NHVdil for air-assisted 
flares.\539\ The commenter noted that in November 2022 the EPA funded 
additional testing with focus on the Simplified VISR technology on both 
steam-assisted and air-assisted flares at the John Zink flare testing 
facility in Tulsa, Oklahoma. The commenter summarized the test results 
in exhibit 3 of their letter and stated that, based on these results, 
Simplified VISR technology can be easily deployed for a short-term 
study or long-term continuous monitoring of NHVcz for steam-assisted 
flares or NHVdil for air-assisted flares at a cost comparable to an OGI 
camera. The commenter requested

[[Page 16968]]

that the EPA allow operators to use the Simplified VISR method to 
demonstrate compliance and give operators a choice between a 
calorimeter and the Simplified VISR. Additionally, if an operator 
chooses to do the 10-day initial NHV sampling demonstration instead of 
continuous monitoring of NHV, the Simplified VISR device could be 
installed to monitor the flare for 10 days and could operate 
autonomously and continuously--a significant advantage over manually 
collecting 200 hourly samples.
---------------------------------------------------------------------------

    \538\ EPA-HQ-OAR-2021-0317-2457.
    \539\ See EPA-HQ-OAR-2021-0317-0604.
---------------------------------------------------------------------------

    To facilitate the described alternative approach, the commenter 
stated, the flare NHV standard needs to be supplemented. The current 
NHV limit is based on the heat content in the gas stream that is fed to 
the flare, but the Simplified VISR measures NHVcz, which the commenter 
stated represents a better surrogate parameter for flare performance 
than vent gas NHV. To facilitate the Simplified VISR as an alternative 
to the proposed NHV limit, the commenter recommended that the final 
rule allow the operator to comply with the NHVcz and NHVdil limits 
promulgated in other rules.\540\ The commenter points out that these 
standards correspond to a combustion efficiency of 96.5 percent and a 
destruction efficiency of 98 percent, which is higher than the control 
efficiency required in the December 2022 Supplemental Proposal, 
representing a 60 percent methane emissions reduction (from 5 percent 
of the flared process stream down to 2 percent).
---------------------------------------------------------------------------

    \540\ The referenced limits are 270 Btu/scf NHVcz for steam-
assisted flares and of 22 Btu/sqft NHVdil for air-assisted flares. 
These standards were first promulgated in 40 CFR part 60, subpart 
CC, at 40 CFR 63.670.
---------------------------------------------------------------------------

    Response: The EPA notes that it has been reviewing the development 
of VISR to monitor flare combustion efficiency for several years. While 
we are not including it as an alternative in the final rule, as we have 
not yet developed a standard method for its use, the final rule 
provides a pathway to allow for the use of VISR, Simplified VISR, or 
other similar technology. In this pathway, an owner or operator could 
request an alternative test method to use a technology such as VISR 
that continuously monitors combustion efficiency or a technology such 
as Simplified VISR that continuously monitors NHVcz and NHVdil. The 
approval of such a request may be site-specific or may instead become 
broadly applicable, approved for a class of combustion devices, and 
listed on the EPA's website as an alternative test method.
    To facilitate the pathway for potentially allowing these 
alternatives, the EPA is finalizing limits of 270 Btu/scf for NHVcz and 
22 Btu/sqft for NHVdil. Destruction efficiency is a measure of how much 
of the hydrocarbon is destroyed, and combustion efficiency is a measure 
of how much of the hydrocarbon burns completely to yield CO<INF>2</INF> 
and water vapor. As such, combustion efficiency will always be less 
than or equal to the destruction efficiency. In the EPA's report \541\ 
on the development of parameters for properly operated flares, we 
stated that the relationship between destruction and combustion 
efficiency is not constant and changes with different compounds, but 
that we considered that a flare with a combustion efficiency of 96.5 
percent achieved a destruction efficiency of 98 percent. We are 
uncertain if the relationship continues to hold at the same level as 
combustion efficiency continues to decrease. Therefore, in this final 
rule, which includes 95 percent emissions reduction standards, we are 
taking a conservative approach. If an owner or operator uses an 
alternative test method, such as VISR, to demonstrate compliance with 
the emissions reduction standards for a combustion control device and 
uses a test method that continuously monitors the combustion 
efficiency, we are requiring that the combustion device used to meet 
such standard have at least 95 percent combustion efficiency, as this 
will ensure a destruction efficiency of at least 95 percent.
---------------------------------------------------------------------------

    \541\ EPA (U.S. Environmental Protection Agency). 2012. 
Parameters for Properly Designed and Operated Flares. Prepared for 
U.S. Environmental Protection Agency, Office of Air Quality Planning 
and Standards, Research Triangle Park, NC. April 2012. Available at: 
https://www3.epa.gov/airtoxics/flare/2012flaretechreport.pdf.
---------------------------------------------------------------------------

    In this final rule, owners and operators approved for an 
alternative test method that uses a technology that continuously 
monitors combustion efficiency or NHVcz and NHVdil would not be 
required to monitor flare vent gas flow rate or vent gas NHV. If the 
alternative test method uses a technology that continuously monitors 
combustion efficiency, the owner or operator would not be required to 
continuously monitor for the presence of a pilot flame or have an alert 
to the control room for the pilot flame. If the alternative test method 
uses a technology that can identify periods of visible emissions, the 
owner or operator would not be required to perform monthly EPA Method 
22 observations. The EPA has also added a pathway to use an alternative 
test method to demonstrate continuous compliance with 95 percent 
combustion efficiency as part of the NHV initial sampling 
demonstration. In lieu of conducting vent gas NHV sampling during the 
initial demonstration period, the owner or operator would demonstrate 
that the combustion control device continuously achieves at least 95 
percent combustion control, thus demonstrating that the heating values 
of the streams sent to the flare are consistently above the minimum 
level necessary to achieve proper combustion.
7. Other Changes to Control Device Requirements
    Additionally, the EPA has made a number of clarifications and minor 
adjustments to the regulatory text in response to comments received:
    <bullet> Revised 40 CFR 60.5412b(a)(1)(ii) and (f)(1)(vii)(D)(1) to 
allow owners and operators to set the minimum temperature limit for 
combustion devices based on operation during the performance test.
    <bullet> Revised 40 CFR 60.5412b(a)(1)(viii), 60.5412b(a)(3)(viii), 
60.5413b(e)(2), 60.5415b(f)(1)(vii)(A)(1), and 60.5417b(d)(8)(i) to add 
a requirement that an alert be sent to the control room when a pilot 
flame is no longer lit.
    <bullet> Revised 40 CFR 60.5412b(a)(1)(ix), 60.5413b(e)(3), 
60.5415b(f)(1)(vii)(A)(2), and 60.5417b(d)(8)(v) to allow the duration 
of the visible emissions observation to be less than 15 minutes if the 
observer sees visible emissions for at least 1 minute prior to the end 
of the 15-minute period.
    <bullet> Revised 40 CFR 60.5412b(a)(3)(vi) and 60.5417b(d)(8)(iv) 
and added 40 CFR 60.5415b(f)(1)(vii)(A)(6) to clarify that the minimum 
flow rate requirement applies to both enclosed combustion devices and 
flares.
    <bullet> Revised 40 CFR 60.5413b(b)(5)(ii) to allow control devices 
to be tested 30 days after returning to service if the control device 
is not operational at the time that a performance test is due.
    <bullet> Revised 40 CFR 60.5413b(b)(5)(ii) to remove the conflict 
with 40 CFR 60.5413b(a) as to whether enclosed combustion devices must 
be periodically tested.
    <bullet> Revised 40 CFR 60.5413b(d)(11)(iii) to indicate that when 
the manufacturer meets the testing requirements outlined for an 
enclosed combustion device, the control device will meet the 
requirement for 95.0 percent destruction of both VOC and methane.
    <bullet> Revised 40 CFR 60.5413b(d)(12) to update submittal 
addresses.
    <bullet> Revised 40 CFR 60.5413b(e), 60.5417b(d)(7), and 
60.5417b(g)(6) to align the monitoring requirements for

[[Page 16969]]

all enclosed combustion devices, regardless of whether they are tested 
by the manufacturer or the owner or operator.
    <bullet> Revised 40 CFR 60.5417b(c) to clarify that monitoring 
systems that check for the presence of a pilot flame must record a 
reading at least once every 5 minutes and to clarify how to average 
monitored parameters.
    <bullet> Revised 40 CFR 60.5417b(c)(2) through (4) to change site-
specific monitoring plan to a company-defined area monitoring plan, to 
align the terminology with the terminology used for fugitive emissions 
monitoring.
    <bullet> Revised 40 CFR 60.5417b(d)(8)(ii) to allow owners and 
operators the option to use gas chromatographs, mass spectrometers, and 
grab sampling systems to monitor NHV.
    <bullet> Revised 40 CFR 60.5417b(d)(8)(ii) to exempt operators from 
conducting monitoring of NHV for associated gas routed to an enclosed 
combustion device or flare if the device or flare is receiving only 
associated gas (as defined in 40 CFR 60.5430b).
    <bullet> Revised 40 CFR 60.5417b(d)(8)(iv) to change the required 
flow meter accuracy requirement from 2 percent to 10 percent in order 
to allow owners and operators additional metering device options and to 
reduce burden, considering the large range of flows that may be 
encountered in some control devices.
    <bullet> Revised 40 CFR 60.5417b(d)(8)(iv) to clarify ``line 
pressure'' to ``inlet line pressure.''
    <bullet> Revised 40 CFR 60.5417b(d)(8)(iv) to change the 
terminology ``backpressure preventer'' to backpressure regulator valve 
and to add continuing operational and maintenance requirements for the 
backpressure regulator valve.
    <bullet> Deleted 40 CFR 60.5417b(e)(2) in order to change the 
averaging time for gas flow rate from 1 hour to 3 hours to align with 
other operating parameters.
    <bullet> Clarified the requirements for carbon adsorption systems 
in 40 CFR 60.5417b(f)(1).

I. Reciprocating Compressors

    In section X.I of this document, the final NSPS OOOOb and EG OOOOc 
requirements for reciprocating compressors are summarized. The BSER 
analysis is unchanged from what was presented in the November 2021 
Proposal (see 86 FR 63214-20, section XII.E. Proposed Standards for 
Reciprocating Compressors). However, significant comments were received 
on the December 2022 Supplemental Proposal on the following topics: (1) 
the EPA's proposal to format the performance-based volumetric flow rate 
standard of performance as a numeric standard, (2) scheduled-based 
packing replacement approach, (3) need to clarify that the standard is 
on a per-cylinder basis, (4) request that the EPA allow the alternative 
compliance option of routing to a control device in addition to routing 
to the process, and (5) the EPA's extension of requirements to 
reciprocating compressors located at centralized production facilities. 
For each of these topics, a summary of the proposed rule (where 
relevant), the comments, the EPA responses, and changes made in the 
final rule (if applicable), are discussed here. These comments and the 
EPA's responses to these comments generally apply to the standards 
proposed in both the NSPS OOOOb and EG OOOOc as the standards proposed 
under the NSPS OOOOb and EG OOOOc were the same. The EPA's full 
response to comments on the November 2021 Proposal and December 2022 
Supplemental Proposal, including any comments not discussed in this 
preamble, can be found in the EPA's RTC document for the final 
rule.\542\
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    \542\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

1. Numeric Standard Versus Work Practice Standard
    In reconsidering the BSER determination and standards for 
reciprocating compressors proposed in November 2021, the EPA recognized 
that it is feasible to prescribe a standard of performance, rather than 
a work practice standard,\543\ for reciprocating compressors. 
Accordingly, the EPA proposed a numeric emissions limit requirement in 
the December 2022 Supplemental Proposal. The major difference between 
that proposed standard and what the EPA proposed in November 2021 was 
that under the supplemental proposal, owners and operators would be 
required to maintain emissions at or below the emissions limit 
(emissions flow rate of 2 scfm) whereas under the November 2021 
Proposal, owners or operators would have been required to replace rod 
packing only after discovering an exceedance of 2 scfm. The BSER was 
therefore proposed to be the replacement of the rod packing and/or 
other necessary repair and maintenance activities to maintain emissions 
at or below 2 scfm.
---------------------------------------------------------------------------

    \543\ 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.''
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    Comment: The EPA received several comments from industry \544\ that 
asserted that a numeric emissions standard in lieu of a work practice 
standard is unsupported and unworkable. One commenter \545\ stated that 
in the November 2021 Proposal, the EPA described a work practice 
standard that would require yearly monitoring and replacement of the 
rod packing when the measured emissions exceed 2 scfm. The commenter 
noted that the EPA cited the Natural Gas STAR document in the November 
2021 Proposal that described a work practice approach for rod packing 
replacement. The commenter added that the work practice approach, 
including a 2 scfm threshold for triggering rod packing replacement, 
was further demonstrated at the EPA's November 2019 Natural Gas STAR 
and Methane Challenge Workshop.\546\ The commenter added that the 
California regulation \547\ cited by the EPA in the December 2022 
Supplemental Proposal TSD is also a work practice standard with a 2 
scfm threshold. The commenter stated that the December 2022 
Supplemental Background TSD does not include any information to support 
an emissions standard rather than a work practice--and the November 
2021 Proposal TSD \548\ envisioned a work practice standard. Thus, the 
commenter stated that if the EPA intended to propose an emissions 
limitation standard, the EPA gave no justification for, or analysis of, 
the change, which the commenter believed is arbitrary and capricious. 
The

[[Page 16970]]

commenter believed that based on the two TSDs, it appeared that the EPA 
intended to propose a work practice standard that triggers rod packing 
maintenance when the threshold is exceeded. The commenter expressed 
that the extensive and case-by-case nature of rod packing replacement 
makes it particularly unsuitable for an emissions limitation standard.
---------------------------------------------------------------------------

    \544\ EPA-HQ-OAR-2021-0317-2305, -2326, -2399, -2428, and -2483.
    \545\ EPA-HQ-OAR-2021-0317-2483.
    \546\ ``DTE Energy Rod Packing Evaluation and Replacement 
Program,'' U.S. EPA 2019 Natural Gas STAR & Methane Challenge 
Workshop (November 2019).
    \547\ CARB. ``[Regulation for Greenhouse Gas Emission Standards 
for Crude Oil and Natural Gas Facilities.]'' Oil and Gas Final 
Regulation Order (ca.gov).
    \548\ EPA, Oil and Natural Gas Sector: Emission Standards for 
New, Reconstructed, and Modified Sources and Emissions Guidelines 
for Existing Sources: Oil and Natural Gas Sector Climate Review, 
Background TSD for the Proposed New Source Performance Standards 
(NSPS) and Emissions Guidelines (EG) (October 2021), Document ID 
No.-HQ-OAR-2021-0317-0166 (hereinafter ``2021 Background TSD'').
---------------------------------------------------------------------------

    Several commenters \549\ expressed concern that, as an emissions 
standard, the proposed rod packing requirements are unworkable. They 
explained that operators would be forced to decide between continuing 
to operate out of compliance until a maintenance shutdown can be 
scheduled or shutting down the compressor immediately to conduct the 
repair and venting or flaring gas that can no longer be compressed and 
transported during the unscheduled shutdown. The commenters added that 
a forced shutdown would likely result in significantly more emissions 
than continuing to operate until the next scheduled maintenance 
shutdown. For systems that are at capacity, shifting the incoming gas 
to another station is not a feasible or reliable option, resulting in 
additional flaring and venting, which is magnified given the time it 
takes to have producers shut in wells. According to one of the 
commenters,\550\ the December 2022 Supplemental Proposal made an 
incorrect assumption that the gas can simply be rerouted to other 
natural gas compression facilities, but the commenter explained that 
often that is not a possibility as piping is not in place to bypass a 
facility, or there may not be an alternative facility available. 
Another commenter \551\ added that while it is true that flow can be 
measured, it is not technically or economically practicable to install 
measurement systems that would assure compliance with a numeric 
emissions limitation. See CAA section 111(h)(2)(B).
---------------------------------------------------------------------------

    \549\ EPA-HQ-OAR-2021-0317-2305, -2399, and -2428.
    \550\ EPA-HQ-OAR-2021-0317-2305.
    \551\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    A couple of commenters \552\ suggested that under a work practice 
framework (which they state to be the only supported option), companies 
be required to complete a corrective action within 720 hours of 
operation (equivalent to 30 days) and allow for delay of repair, 
similar to that for leak monitoring programs, of up to 2 years if 
repair goes beyond the replacement of rod packing. The commenters noted 
that exceeding the vent rate threshold after the time for corrective 
action would be a deviation, but exceeding the vent rate within the 
time allotted to correct would not.
---------------------------------------------------------------------------

    \552\ EPA-HQ-OAR-2021-0317-2305 and -2399.
---------------------------------------------------------------------------

    One commenter \553\ stated that the EPA proposed to establish the 2 
scfm flowrate as a not-to-exceed standard of performance, such that a 
violation occurs if flow rate exceeds that value (87 FR 74797). In 
doing so, the commenter suggested, the EPA fundamentally misconstrued 
the manufacturers' recommendations (on which the flow rate is based). 
In practice, the commenter explained, exceeding a manufacturer-
recommended flow rate is an indication that a repair should be made. 
Exceeding that rate does not necessarily compromise operability of the 
unit and, in fact, the values are selected to allow continued operation 
for the period necessary to arrange for needed repairs to be made. 
According to the commenter, the EPA without explanation proposed to 
transform what in practice constitutes an action level into a 
regulatory cap that cannot be exceeded without the prospect of 
incurring a violation. The commenter argued that the EPA's proposal is 
at odds with the facts and is an unreasonable reinterpretation of 
standard maintenance practices.
---------------------------------------------------------------------------

    \553\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    The commenter \554\ argued that, if the EPA is intent on setting a 
numeric standard of performance, the value must be well above the 2 
scfm that the EPA believes to be the standard manufacturer 
recommendations. They asserted that the value must accommodate 
operations for a reasonable and potentially significant period of time 
that may be needed to accomplish needed repairs. If the EPA takes this 
path, the commenter contended that a reproposal would be necessary so 
that commenters would know the newly proposed value, understand the 
EPA's rationale, and have an opportunity to submit comments on the 
record.
---------------------------------------------------------------------------

    \554\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA acknowledges that the record for the 2 scfm 
performance volumetric flow rate standard supports a work practice 
standard and not a numeric standard. The EPA has determined that, for 
reciprocating compressors, the application of a measurement methodology 
to reciprocating compressors is not always practicable due to 
technological or economic limitations. It is not practicable here for 
an exceedance of the 2 scfm per cylinder volumetric flow rate to be a 
violation when the annual performance-based flow rate reflects whether 
there are performance issues with the rod packing that need to be 
addressed in order to take action to minimize the emissions/leak. This 
is similar to the basis and monitoring established for fugitive 
emissions component requirements, where a leak based on periodic 
monitoring triggers requirements to minimize the emissions/leak.
    In the final rule, therefore, the 2 scfm performance-based 
volumetric flow rate standard will be implemented as a work practice 
standard and not as a numeric limit where an exceedance would be 
considered a violation. As such, the volumetric flow rate of 2 scfm is 
an action level that, if exceeded, triggers the action of repairing or 
replacing the rod packing and is not a numerical limit. Specifically, 
the final rule for reducing GHGs and VOC from new reciprocating 
compressors requires repair or replacement of the rod packing where, 
based on the required monitoring, the performance-based volumetric flow 
rate standard is exceeded. If the volumetric emissions measurement of 
the reciprocating compressor rod packing has a flow rate greater than 2 
scfm (in operating or standby pressurized mode) or a combined rod 
packing flow rate greater than the number of compressor cylinders 
multiplied by 2 scfm, an owner or operator must repair or replace the 
reciprocating compressor rod packing within 30 calendar days after the 
date of the volumetric emissions measurement. Delay-of-repair 
provisions under a work practice standard appropriately recognize that 
the unit must be shut down to effect any such repair and replacement 
and that parts availability and supply chain disruptions may be 
relevant to how quickly the repair or replacement can be made. As such, 
the final rule allows for a delay of repair if the repair or 
replacement would require a vent blowdown, or it would otherwise be 
infeasible or unsafe, until the next process unit shutdown--
specifically, if the repair or replacement (1) is technically 
infeasible, (2) would require a vent blowdown, (3) would require a 
process unit or facility shutdown, (4) needs to be delayed because 
parts or materials are unavailable, or (5) would be unsafe to repair 
during operation of the unit. In cases where there is a need for delay 
of repair, the repair must be completed during the next scheduled 
process unit or facility shutdown for maintenance, after a scheduled 
vent blowdown, or within 2 years, whichever is earliest.

[[Page 16971]]

2. Rod Packing Changeout Schedule-Based Approach
    Comment: Several commenters \555\ expressed concern over the EPA's 
changing in the proposed NSPS OOOOb and EG OOOOc the requirements that 
the commenters have been meeting under NSPS OOOOa to replace rod 
packing on a fixed schedule. The commenters noted that given the 
uncertainties of the assumptions underlying the BSER evaluations for 
the two options (the rod packing changeout schedule-based approach and 
monitoring limit approach) and given that the cost effectiveness values 
of the two options are very close, they urged the EPA to provide 
flexibility to affected facilities by adopting both standards as BSER 
alternatives with the operator selecting their preferred approach.
---------------------------------------------------------------------------

    \555\ EPA-HQ-OAR-2021-0317-2227, -2258, -2282, -2298, -2326, -
2366, -2399, -2428, and -2483.
---------------------------------------------------------------------------

    According to one commenter,\556\ retaining the schedule-based 
approach is warranted because that compliance option has been 
implemented not only at NSPS OOOOa facilities but also through state 
regulations and voluntary actions by companies. The commenter added 
that the prescribed maintenance schedule is also an EPA-approved best 
management practice for the voluntary Methane Challenge program. Due to 
these EPA decisions, the commenter reported, many companies have 
``built out'' reciprocating compressors rod packing maintenance 
programs using scheduled maintenance, including existing compressors 
not subject to the Federal mandate or state rules. The commenter 
expressed that it is critical that these existing and successful 
company programs not be supplanted by different requirements in NSPS 
OOOOb and EG OOOOc.
---------------------------------------------------------------------------

    \556\ EPA-HQ-OAR-2021-0317-2366.
---------------------------------------------------------------------------

    Several commenters noted specific suggestions with respect to a 
fixed schedule:
    <bullet> Several commenters \557\ requested that the EPA allow rod 
packing replacement every 8,760 operating hours.
---------------------------------------------------------------------------

    \557\ EPA-HQ-OAR-2021-0317-2258, -2298, and -2326.
---------------------------------------------------------------------------

    <bullet> One commenter \558\ requested that the EPA allow 
replacement annually or 8,760 hours (whichever comes first), which is 
similar in approach but more frequent than the current requirements in 
NSPS OOOO and NSPS OOOOa.
---------------------------------------------------------------------------

    \558\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    <bullet> Another commenter \559\ requested retaining the NSPS OOOOa 
approach, requiring the replacement of rod packing every 3 years or 
26,000 hours of operation (if operating hours are monitored).
---------------------------------------------------------------------------

    \559\ EPA-HQ-OAR-2021-0317-2366.
---------------------------------------------------------------------------

    Several commenters \560\ requested that the EPA specify that where 
operators choose to replace rod packing on a fixed schedule, they are 
not required to measure volumetric flow rates.
---------------------------------------------------------------------------

    \560\ EPA-HQ-OAR-2021-0317-2227, -2298, -2326, -2399, and -2428.
---------------------------------------------------------------------------

    Response: The contention by commenters that requiring the 
performance-based volumetric flow rate monitoring would result in 
owners or operators having to do more rod packing changeouts on 
reciprocating compressors and/or would lead to an increase in baseline 
maintenance/piston rod replacement to ensure proper operation of the 
compressor further supports requiring the performance-based volumetric 
flow rate monitoring standard over a fixed-schedule rod packing 
changeout every 26,000 hours to mitigate emissions. This is also 
consistent with the EPA's BSER determination that greater and more-
efficient emissions reductions would be achieved by implementing an 
annual performance-based 2 scfm volumetric flow rate monitoring 
standard. For these reasons, the EPA is not including the 26,000-hour, 
fixed-schedule rod packing replacement as an alternative option to the 
condition-based 2 scfm volumetric flow rate monitoring option. However, 
under the final rule, the EPA has clarified that an owner or operator 
would be allowed to replace rod packing on or before 8,760 hours of 
operation after last rod packing replacement or monitoring and forgo 
the need to conduct the required performance-based volumetric flow rate 
monitoring. The final rule also specifies that owners or operators are 
allowed to forgo volumetric flow rate measurements if they replace the 
rod packing at or before 8,760 hours of operation after the last rod 
packing replacement or flow rate measurement.
    The final rule has also been revised to state that the first 
volumetric flow rate measurements from a reciprocating compressor 
affected facility are to be conducted at or before 8,760 hours of 
operation after the effective date of the final rule (i.e., 60 days 
after publication of the final rule in the Federal Register), or at or 
before 8,760 hours of operation after the last rod packing replacement, 
or at or before 8,760 hours of operation after startup, whichever is 
later. Subsequent volumetric flow rate measurements from your 
reciprocating compressor are to be conducted at or before 8,760 hours 
of operation after the previous measurement that demonstrates 
compliance with the 2 scfm volumetric flow rate, or at or before 8,760 
hours of operation after the last rod packing replacement, whichever is 
later. As an alternative to conducting required volumetric flow rate 
measurements, the final rule allows an owner or operator the option to 
comply by replacing the rod packing at or before 8,760 hours of 
operation after the effective date of the final rule, at or before 
8,760 hours of operation after the previous flow rate measurement, or 
at or before 8,760 hours of operation after the date of the most recent 
compressor rod packing replacement, whichever is later.
3. Clarification That the Standard Is Based on a Per-Cylinder Basis
    Comment: Several commenters \561\ requested clarification that the 
volumetric standard applies to each rod packing (or throw) or set of 
packing and not to the entire compressor and that the rule text clearly 
addresses manifolded vents on a combined basis. The commenters cite the 
precedent set by the CARB where reciprocating compressors in California 
are restricted to 2 scfm per rod packing, and not per compressor, as 
set forth in 17 CCR section 95668(c)(4)(D), Greenhouse Gas Emission 
Standards for Crude Oil and Natural Gas Facilities (allowing for ``a 
combined rod packing or seal emission flow rate greater than the number 
of compression cylinders multiplied by two (2) scfm'') which states:
---------------------------------------------------------------------------

    \561\ EPA-HQ-OAR-2021-0317-2258, -2282, -2305, -2326, -2366, -
2391, -2399, -2428, and -2483.

    (6) with a rod packing or seal with a measured emission flow 
rate greater than two (2) standard cubic feet per minute (scfm), or 
a combined rod packing or seal emission flow rate greater than the 
---------------------------------------------------------------------------
number of compression cylinders multiplied by two (2) scfm.

    These commenters generally stated that this approach makes sense 
and is consistent with the proposed BSER from the November 2021 
Proposal. In addition, the EPA based its proposal to measure the flow 
rate of each cylinder on volumetric emission factors used in the 1996 
EPA/GRI report quantifying methane emissions from the U.S. natural gas 
industry--which the EPA notes are per cylinder. The commenters 
elaborated on why they believed that this was the EPA's intent and 
several commenters provided in-line regulatory text changes where they 
believed the clarification was needed.
    Response: The EPA agrees that the basis and intent of the standard 
is that it be applied on a per-cylinder basis and that clarity was 
needed in both the

[[Page 16972]]

NSPS OOOOb and EG OOOOc regulatory text. The final rule regulatory text 
has been revised to make this clear as suggested by the commenters. 
Specifically, clarifying changes have been made to: 40 CFR 60.5385b, 
paragraphs (a) through (c) of NSPS OOOOb; and 40 CFR 60.5393c, 
paragraphs (a) through (c) of EG OOOOc.
4. Routing to Process or Control Device
    In the December 2022 Supplemental Proposal, the EPA proposed to 
allow an alternative reciprocating compliance option of routing rod 
packing emissions to a process via a CVS. Several commenters \562\ 
requested that they also have the option to use proven add-on controls, 
such as an existing combustor or flare, in addition to routing to a 
process. A commenter explained that such options may be key for 
existing units and units that are modified or reconstructed.
---------------------------------------------------------------------------

    \562\ EPA-HQ-OAR-2021-0317-2258, -2305, -2399, and -2428.
---------------------------------------------------------------------------

    Comment: A few commenters \563\ provided several reasons for why it 
may not always be feasible to route rod packing vents back to the 
process:
---------------------------------------------------------------------------

    \563\ EPA-HQ-OAR-2021-0317-2305, -2399, and -2428.
---------------------------------------------------------------------------

    <bullet> Depending on the pressure differential between nearly 
ambient rod packing vents and pressurized piping, substantial 
horsepower may be required to achieve capture.
    <bullet> Recompression designs require substantial horsepower and 
could require gas engines of variable horsepower to achieve the 
recompression, negating some of the emissions reductions this rule 
seeks to achieve.
    <bullet> Currently available rod packing capture systems attempted 
by Williams and others in the industry have performed poorly or are 
ineffective in certain applications or configurations.
    <bullet> Rod packing vents are essentially at ambient pressure, 
creating a situation where oxygen (O<INF>2</INF>) could be introduced 
into the process gas, leading to safety concerns.
    <bullet> The gas quality in the rod packing vents may not be 
compatible with the only technically feasible location in the process, 
based on pressure differentials, for the gas to be routed. For example, 
if the gas in the compressor is sour gas, but the only technically 
feasible place for the gas to be absorbed in the process is the fuel 
gas system, the sour gas is often not a good candidate for fuel gas use 
due to the detrimental effect on components.
    According to one commenter,\564\ currently available rod packing 
capture systems that have been attempted by the commenter and their 
members have not performed as intended and, in some applications, have 
not worked at all. They explained that even if these systems were as 
effective as advertised, timing is a significant concern as the supply 
is not currently available to meet demand. The commenter recommended 
that where rod packing vents are routed to a control device, the EPA 
could require that the flow be measured every 26,000 hours of 
operation. The commenter noted that this would ensure that rod packing 
is appropriately maintained while overall emissions are greatly 
reduced.
---------------------------------------------------------------------------

    \564\ EPA-HQ-OAR-2021-0317-2399.
---------------------------------------------------------------------------

    Another commenter \565\ provided that the incremental benefit 
achieved between monitoring and subsequent repair (if applicable) 
versus capturing and venting to a control device that achieves 95 
percent destruction efficiency has not been substantiated by the EPA 
within its BSER analysis. This, according to the commenter, is 
especially true for any compressor that already is designed and 
configured to route rod packing emissions to a flare or other 
combustion device.
---------------------------------------------------------------------------

    \565\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA evaluated allowing the alternative option of 
routing to a control device that achieves 95 percent control of 
emissions and has determined that it would be acceptable as an 
alternative control option. The volumetric 2 scfm performance-based 
volumetric flow rate standard is estimated to reduce VOC and methane 
emissions by approximately 92 percent, and a flow rate of 40 scfm 
reduced by 95 percent would meet a 2 scfm flow rate. As a result, we 
have concluded that allowing for routing to a control device achieving 
a 95 percent reduction in VOC and methane emissions has merit and would 
provide equivalent or better emissions reduction compared to BSER. 
Accordingly, we have included this measure as an alternative option for 
compliance in the final rule.
5. Applicability of Requirements to Compressors Located at Centralized 
Production Facilities
    The EPA proposed (86 FR 63184-85, November 15, 2021) to define 
centralized production facilities separately from well sites because 
the numbers and sizes of equipment, particularly reciprocating and 
centrifugal compressors, are larger than for standalone well sites, 
which would not be included in the proposed definition of ``centralized 
production facilities.'' In the 2016 NSPS OOOOa, the EPA exempted 
reciprocating and centrifugal compressors located at well sites from 
the applicable compressor standards. Reciprocating compressors that are 
located at well sites are not affected facilities under the 2016 NSPS 
OOOOa. The EPA previously excluded them because the EPA found the cost 
of control to be unreasonable. 81 FR 35878. However, we believed the 
definition of ``well site'' in NSPS OOOOa may have caused confusion 
regarding whether reciprocating compressors located at centralized 
production facilities were also exempt from the standards, which was 
not our intent.
    To clarify our intent, we proposed to define centralized production 
facility as follows in the December 2022 Supplemental Proposal:

    Centralized production facility means one or more storage 
vessels and all equipment at a single surface site used to gather, 
for the purpose of sale or processing to sell, crude oil, 
condensate, produced water, or intermediate hydrocarbon liquid from 
one or more offsite natural gas or oil production wells. This 
equipment includes, but is not limited to, equipment used for 
storage, separation, treating, dehydration, artificial lift, 
combustion, compression, pumping, metering, monitoring, and 
flowline. Process vessels and process tanks are not considered 
storage vessels or storage tanks. A centralized production facility 
is located upstream of the natural gas processing plant or the crude 
oil pipeline breakout station and is a part of producing operations.
    Additionally, we proposed to define the affected facility as:
    (c) Each reciprocating compressor affected facility, which is a 
single reciprocating compressor. A reciprocating compressor located 
at a well site is not an affected facility under this subpart. A 
reciprocating compressor located at a centralized production 
facility is an affected facility under this subpart.

    For purposes of analyses, we proposed to determine that it was 
appropriate to apply the same emission factors to reciprocating 
compressors located at centralized production facilities as those used 
for reciprocating compressors at gathering and boosting compressor 
stations. Given the results of that analysis, the EPA proposed to apply 
the proposed NSPS OOOOb requirements to reciprocating compressors 
located at centralized production facilities. At that time, the EPA 
proposed a new definition for centralized production facilities to 
distinguish compressors at standalone well sites where the EPA has 
determined that the standard should not apply.

[[Page 16973]]

    Comment: One commenter \566\ requested that the EPA clarify the 
applicability of compressor standards to well sites. The commenter 
stated that the definition proposed for ``centralized production 
facility'' may extend applicability to compressors located at well 
sites, which have historically been exempt from the compressor 
standards. The commenter noted that the EPA had not updated its cost 
analyses with new information with respect to well sites and believed 
that extending applicability to well sites was not the EPA's intent.
---------------------------------------------------------------------------

    \566\ EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    Another commenter \567\ urged the EPA to keep the current 
compressor exemptions shown in both subparts NSPS OOOO and NSPS OOOOa. 
The commenter specifically requests that the EPA maintain that each 
compressor ``located at a well site, or an adjacent well site and 
servicing more than one well site, is not an affected facility.''
---------------------------------------------------------------------------

    \567\ EPA-HQ-OAR-2021-0317-0923.
---------------------------------------------------------------------------

    Conversely, another commenter \568\ supported the EPA's proposed 
definition of a centralized production facility and supported the 
extension of compressor standards to these sites. While the GHGI does 
not contain data on the number of compressors in the production 
segment, the commenter reported that they analyzed data submitted in 
response to the EPA's 2016 ICR to assess the number of compressors 
across different facility types in the production segment. While the 
ICR data are not a full inventory, the commenter contended that the ICR 
illustrates that there are a significant number of compressors utilized 
in the production segment, with most reciprocating compressors located 
at centralized production facilities.
---------------------------------------------------------------------------

    \568\ EPA-HQ-OAR-2021-0317-0844.
---------------------------------------------------------------------------

    A couple of commenters \569\ recommended that the EPA continue the 
exemption of each centrifugal and reciprocating compressor ``located at 
a well site, or an adjacent well site and servicing more than one well 
site'' as provided in both 40 CFR part 60, subpart OOOO, and 40 CFR 
part 60, subpart OOOOa. The commenters explained that well operators 
visit and service these wells and associated compressors daily to 
inspect for proper operation, to inspect for leaks, and to conduct 
maintenance and repairs activities. Any necessary repairs are 
implemented as soon as possible to avoid product loss and to maximize 
profit returns. If the EPA wishes to propose monitoring for well site 
compressors, the commenters recommended that the EPA allow the more 
feasible and cost-effective monthly AVO inspection and documentation, 
similar to the requirements allowed under 40 CFR 60.5416a.
---------------------------------------------------------------------------

    \569\ EPA-HQ-OAR-2021-0317-0465 and -0946.
---------------------------------------------------------------------------

    Some commenters \570\ expressed that applying the proposed 
monitoring requirements to reciprocating compressors located at 
``centralized production facilities'' may be beneficial in certain 
operations and where larger oil and gas operators may have the 
resources and equipment to monitor those emissions. However, they 
suggested that it should be an option/alternative and not a mandatory 
requirement, as it may unnecessarily create additional burdens and 
costs for smaller operators that send production from several marginal/
low production wells to a ``centralized production facility.'' These 
commenters reported that, for marginal/low production well operators, 
centralized production facilities may be more cost-efficient than 
having equipment at each well site and this practice reduces overall 
the environmental footprint of the operation. The commenters suggested 
that it would be an unnecessary additional cost on small businesses and 
that it disincentivizes the use of centralized production facilities in 
this scenario. The commenters requested that the EPA remove this 
requirement for marginal/low production wells that send production to 
centralized production facilities.
---------------------------------------------------------------------------

    \570\ EPA-HQ-OAR-2021-0317-0810 and -0814.
---------------------------------------------------------------------------

    Response: Most of these comments were based on the November 2021 
Proposal prior to the EPA's December 2022 Supplemental Proposal 
definitions cited earlier in this document for a reciprocating 
compressor affected facility and centralized production facility. The 
EPA has finalized the December 2022 Supplemental Proposal's proposed 
requirements related to the definitions of the reciprocating compressor 
affected facility and centralized production facility. Some of the 
commenters suggested that, by extending requirements to apply to 
centralized production facilities, the EPA was extending requirements 
to well sites where reciprocating compressors were not previously 
regulated. That interpretation confirms that clarity was needed. Based 
on the proposed definition of the reciprocating compressor affected 
facility, in addition to the proposed definition for centralized 
production facility as proposed in the December 2022 Supplemental 
Proposal, we believe that we clarified our intent. That intent is that 
reciprocating compressors located at well sites are not subject to 
requirements. However, reciprocating compressors located at centralized 
production facilities that consist of equipment at a single surface 
site used to gather, for the purpose of sale or processing to sell, 
crude oil, condensate, produced water, or intermediate hydrocarbon 
liquid from one or more offsite natural gas or oil production wells 
(including reciprocating compressors) are subject to reciprocating 
compressor requirements.
    In response to the commenters that noted that small operators of 
marginal/low production wells often send production from several 
marginal/low production wells to a ``centralized production facility'' 
because it is uneconomic to have equipment at each well site, the EPA 
does not understand why they would no longer be incentivized not to 
have equipment at each well site. The commenters did not provide 
sufficient information as to why an owner or operator of reciprocating 
compressors at centralized production facilities would not continue 
having reciprocating compressors at centralized production facilities 
because they would be subject to requirements in lieu of having 
equipment at each well site.

J. Storage Vessels

    In section X.J of this document the final NSPS OOOOb and EG OOOOc 
requirements for storage vessels are summarized. In the November 2021 
Proposal, the EPA proposed that for NSPS OOOOb, a storage vessel 
affected facility is a tank battery, which can be a single tank, with 
the potential to emit equal to or greater 6 tpy VOC or 20 tpy methane. 
The EPA proposed that an owner or operator of a tank battery must 
determine the potential for VOC and methane emissions using a 
``generally acceptable model or calculation methodology'' that accounts 
for flashing, working, and breathing losses. The EPA proposed that the 
determination may take into account requirements under a ``legally and 
practicably enforceable limit'' in an operating permit or other 
requirement established under a Federal, state, local, or Tribal 
authority and proposed specific elements as to what constitutes a 
``legally and practicably enforceable limit.'' The elements included: a 
quantitative production limit and quantitative operational limit(s) for 
the equipment, or quantitative operational limits for the equipment; an 
averaging time period for the production limit, if a production-based 
limit is used, that is equal to or less than 30 days; established 
parametric limits for the

[[Page 16974]]

production and/or operational limit(s), and where a control device is 
used to achieve an operational limit, an initial compliance 
demonstration (i.e., performance test) for the control device that 
establishes the parametric limits; ongoing monitoring of the parametric 
limits that demonstrates continuous compliance with the production and/
or operational limit(s); and recordkeeping and reporting by the owner 
or operator that demonstrates continuous compliance with the limit(s). 
In the November 2021 Proposal, the EPA proposed that a tank battery is 
a group of storage vessels which are physically adjacent and that 
receive fluids from the same source or that are manifolded together for 
liquid or vapor transfer. Regarding BSER, the EPA proposed that storage 
vessel affected facilities must reduce emissions by 95 percent or 
greater. The BSER analysis is unchanged from what was presented in the 
November 2021 Proposal (see 86 FR 63199-201, section XII.B. Proposed 
Standards for Storage Vessels). The EPA proposed similar requirements 
for designated facilities under EG OOOOc, which have the potential to 
emit greater than or equal to 20 tpy methane.
    In the November 2021 Proposal, the EPA proposed specific actions 
that would constitute ``modification'' of an existing tank battery for 
purposes of determining whether NSPS OOOOb is triggered (if the 
potential methane or VOC emissions are determined to be above the 
applicability threshold). Some of the actions that could trigger 
modification are actions that occur at the well site, such as 
refracturing a well or adding a new well that sends these liquids to 
the tank battery. The EPA did not propose specific provisions for 
reconstruction in the November 2021 Proposal.
    In the December 2022 Supplemental Proposal, the EPA proposed a 
revised definition of storage vessel affected facility. In response to 
comments on the November 2021 Proposal, the EPA removed the criterion 
that the storage vessels in the tank battery are physically adjacent 
and the criterion that the vapor lines are manifolded together.
    In the December 2022 Supplemental Proposal, the EPA retained the 
same provisions for ``legally and practicably enforceable'' criteria 
which were proposed in the November 2021 Proposal. Regarding 
modification and reconstruction, to address the resultant emissions at 
a compressor station or onshore natural gas processing plant receiving 
those liquids, where the emissions have already been accounted for in 
the permit, in the December 2022 Supplemental Proposal, the EPA 
proposed that for compressor stations or onshore natural gas processing 
plants, the modification trigger occurs when the tank battery receives 
additional fluids which cumulatively exceed the throughput used in the 
most recent determination for VOC or methane emissions (e.g., permit) 
based on the design capacity of such tank battery. In addition, the 
December 2022 Supplemental Proposal retained the November 2021 criteria 
that a modification is also triggered when a storage vessel is added to 
an existing tank battery and/or one or more storage vessels are 
replaced such that the cumulative storage capacity of the existing tank 
battery increases. In the December 2022 Supplemental Proposal, the EPA 
proposed two actions which constitute reconstruction: over half of the 
storage tanks are replaced in an existing tank battery that consists of 
more than one storage vessel; or the provisions of 40 CFR 60.15 are met 
for the existing tank battery that consists of a single storage vessel.
    The EPA received significant comments on the definition of legally 
and practicably enforceable limits, modification, and reconstruction. 
This section of this preamble presents a summary of those significant 
comments and the EPA's response to those comments. These comments and 
the EPA's responses to these comments apply to the standards proposed 
in both the NSPS OOOOb and EG OOOOc. The EPA's full response to 
comments on the November 2021 Proposal and December 2022 Supplemental 
Proposal, including any comments not discussed in this preamble, can be 
found in the EPA's RTC document for the final rule.\571\
---------------------------------------------------------------------------

    \571\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

1. Legally and Practicably Enforceable Limits
    As explained in the preamble to the November 2021 Proposal (86 FR 
63201), from its years of experience of reviewing permits of legally 
and practicably enforceable limits, the EPA has long been aware that 
many owners and operators claim that storage vessels are not affected 
facilities under 40 CFR 60.5365(e) and 40 CFR 60.5365a(e) by alleging 
that the VOC emissions are less than 6 tpy. Since promulgation of NSPS 
OOOO in 2012, the EPA has expended extensive resources in enforcement 
actions nationwide to review permits, general permits, and permits-by-
rule for storage vessels and found that, in nearly in all cases, across 
nearly 400 storage vessels, these permits or other requirements are not 
legally and practicably enforceable. In nationwide ongoing enforcement 
actions, the EPA continues to find permits or permits-by-rule that are 
not legally and practicably enforceable. The EPA has repeatedly 
expressed this concern in prior rulemaking actions. See, e.g., 83 FR 
52085 and 85 FR 57425. The EPA believes that the new criteria being 
finalized in this action will help to ensure that storage tank 
batteries that rely on legally and practicably enforceable limits to 
claim nonapplicability of NSPS OOOOb or EG OOOOc indeed have potential 
emissions below the relevant applicability threshold(s).
    As discussed in this section, several commenters failed to 
acknowledge the EPA's concern, claiming that it does not exist; some 
commenters insist that the criteria are unnecessary but do not offer 
any alternative to address the EPA's concern. The EPA has provided 
examples of limits that are not legally and practicably enforceable 
\572\ later in this section and is finalizing the criteria as proposed 
to ensure that, where an owner and operator is taking into account a 
legally and practicably enforceable limit in determining the 
applicability of the storage vessels standards under OOOOb or EG OOOOc, 
those limits actually limit and maintain potential emissions below the 
rule's applicability thresholds under NSPS OOOOb or designated 
facilities under EG OOOOc. The EPA further notes that including legally 
and practicably enforceable limits is an option, not a requirement, in 
determining storage vessel affected facility/designated facility status 
under NSPS OOOOb and EG OOOOc. The EPA will continue to evaluate the 
use of permit limits in determining the applicability of the standards 
for storage vessels pursuant to the criteria finalized in this action 
to see whether the EPA's concern is fully addressed. If concerns about 
the enforceability of the applicability criteria for the storage vessel 
standards remain upon implementation of the revised regulatory 
provision, the EPA may initiate further rulemaking in the future.
---------------------------------------------------------------------------

    \572\ See the RTC, volume 2, chapter 13, in EPA-HQ-OAR-2021-
0317.

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

[[Page 16975]]

a. Need for a National Rulemaking To Address LPE Across CAA Programs
    Comment: Several commenters \573\ urged the EPA to defer final 
action on the proposed definition of legally and practicably 
enforceable limits until such time as the Agency undertakes a national 
rulemaking. A few of the commenters \574\ pointed out the potential for 
inconsistencies among the various CAA programs that similarly require 
legally and practicably enforceable limits to determine applicability 
(e.g., an effective emissions limit used to avoid major NSR permitting 
might, at the same time, not be effective for purposes of the NSPS 
OOOOb and/or EG OOOOc storage vessel standards). One commenter \575\ 
opined that what constitutes an acceptable and effective ``legally and 
practicably enforceable limit'' has been an open question since the 
mid-l990s, when the prior ``Federal enforceability'' requirement was 
remanded or vacated across the EPA's programs.\576\ Similarly the 
commenter \577\ believed that these proposed provisions of the NSPS 
OOOOb and EG OOOOc were driven by a July 2021 report from the EPA 
Inspector General that criticized the EPA for not responding to these 
judicial decisions.\578\ The commenter stated that the EPA's announced 
plan to establish national rules for effective limits on PTE and to do 
so in the relative near future \579\ lends strong additional support to 
the view that the EPA should not address these issues in a premature 
and piecemeal fashion. Another commenter \580\ stated that a national 
rulemaking would avoid many potential inconsistencies and uncertainties 
across CAA programs and would allow the EPA to establish reasonable 
transition rules so that affected sources and states have time to 
revise existing emissions limitations as needed to meet the new 
effectiveness criteria.
---------------------------------------------------------------------------

    \573\ EPA-HQ-OAR-2021-0317-2298, -2301, -2326, and -2428.
    \574\ EPA-HQ-OAR-2021-0317-2428, -2326, and -2298.
    \575\ EPA-HQ-OAR-2021-0317-2298.
    \576\ National Mining Ass 'n v. EPA, 59 F.3d 1351 (D.C. Cir. 
1995); Chemical Mfrs. Ass 'n v. EPA, 70 F.3d 637 (D.C. Cir. 1995); 
Clean Air Implementation Project v. EPA, 1996 WL 393118 (D.C. Cir. 
1996).
    \577\ EPA-HQ-OAR-2021-0317-2428.
    \578\ EPA Should Conduct More Oversight of Synthetic-Minor-
Source Permitting to Assure Permits Adhere to EPA Guidance, Report 
No. 21-P-0175, memorandum from Sean W. O'Donnell to Joseph Goffman 
(July 8, 2021) at 17.
    \579\ The commenter stated that the EPA intends to issue 
national guidance by October 2023.
    \580\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    Response: The final rule includes ``legally and practicably 
enforceable'' criteria specific to oil and gas storage vessels. The EPA 
is choosing to add regulatory certainty to describe legally and 
practicably enforceable emissions limitations to address a common 
problem that the EPA has observed over the past decade through 
implementation of NSPS OOOO and OOOOa. Specifically, the EPA has 
identified problems with permits that states and owners and operators 
have characterized as legally and practicably enforceable. As discussed 
in the November 2021 Proposal (see 86 FR 63201) and elaborated in 
section XI.J.1 of this document, when the EPA has reviewed the limits 
considered by facilities as legally and practicably enforceable, the 
limits are often of such a general nature as to be unenforceable or 
otherwise lack measures to ensure the required emissions reduction. 
Unless the compliance with the permit limit can be determined, and the 
permit limit achieves the desired emissions reductions, they are not 
meaningful requirements. Excerpts of specific permits \581\ that the 
EPA has reviewed and determined to be lacking legally and practicably 
enforceable limits include:
---------------------------------------------------------------------------

    \581\ The EPA is not able to identify the permittees due to 
ongoing investigations or enforcement actions.
---------------------------------------------------------------------------

Permit 1--Applicable Emissions Limitations or Control Measures
    <bullet> In order to comply with the tons-per-month emissions 
limit, utilize one or more of the following controls: Use of add-on 
control (vapor recovery, flare, or equivalent) to control emissions 
from storage vessels as needed to comply with the annual VOC emissions 
limitations.
    <bullet> The permittee accepts a voluntarily limit to restrict the 
potential VOC emissions from each storage vessel to less than 6 tpy.
    In Permit 1, the control device is not specified and the permit 
terms do not specify a destruction rate efficiency, combustion rate, or 
availability for a VRU. The provision also does not specify emissions 
testing, operational parameter monitoring, inspection requirements, or 
recordkeeping or reporting requirements for the add-on control. 
Additionally, the terms ``voluntarily limit'' in the second provision 
indicate that controlling emissions below 6 tpy of VOCs is not a 
requirement.
Permit 2--Combustor/Flare Requirements
    <bullet> All exhaust gas/vapors from the oil storage tanks must be 
routed to the operating combustor/flare.
    <bullet> The combustor/flare shall operate with no visible 
emissions.
    <bullet> Visual determination of smoke emissions from flares shall 
be conducted according to 40 CFR 60, appendix A, EPA Method 22.
    In Permit 2, a destruction rate efficiency of 95 percent or greater 
is not specified. There is no testing requirement for the control 
device, no continuous pilot light monitoring or inspection requirement, 
no indication of how frequently EPA Method 22 inspections must be 
conducted, and no recordkeeping or reporting requirements. Both Permit 
1 and Permit 2 demonstrate provisions from permits that do not have 
operational or parametric limits and therefore that the EPA has 
determined not to be legally and practicably enforceable and thus 
adequate to ensure that the storage vessels are below the applicability 
thresholds for the applicable standards.
    The EPA disagrees that it should delay establishing the criteria 
for legally and practicably enforceable limits for purposes of 
determining storage vessel affected facility/designated facility status 
under NSPS OOOOb and EG OOOOc until such time as the Agency undertakes 
a national rulemaking on legally and practicably enforceable limits for 
other CAA provisions. The criteria in this final rule are unique and 
specifically tailored toward their intended purpose, which is to ensure 
that limits that are being taken into account in determining NSPS OOOOb 
and EG OOOOc applicability do in fact cap the potential emissions of a 
tank battery below the relevant applicability threshold and are 
enforceable. There is no reason why the EPA needs to wait to address 
this long-observed issue with respect to this emission source. 
Moreover, general criteria for legally and practicably enforceable 
limits would not necessarily provide the clarity and certainty that is 
necessary to ensure that the issue observed in the implementation of 
NSPS OOOO and OOOOa does not continue in the future in the 
implementation of NSPS OOOOb and EG OOOOc. Nor would such general 
criteria be timely, given the NSPS OOOOb standards will apply upon the 
effective date of this action and states will need to begin developing 
state plans pursuant to EG OOOOc. Finalizing the criteria now will 
provide states and sources specificity and certainty as to what the EPA 
considers legally and practicably enforceable for purposes of 
determining potential tank battery emissions under NSSP OOOOb or a 
state or Federal plan implementing EG OOOOc. The EPA believes that this 
level of specificity and certainty will

[[Page 16976]]

serve to guide states and sources in establishing permit limits for 
tank batteries that could be used in determining NSPS OOOOb/EG OOOOc 
applicability.
b. LPE and Delegated Authorities
    Comment: The EPA received multiple comments \582\ regarding the 
interplay with delegated authorities other than the EPA, such as 
concern that existing permits may not comply with the criteria proposed 
by the EPA, how the criteria align with permit-by-rule or permits, and 
the fact that many existing state permits lack methane limits.
---------------------------------------------------------------------------

    \582\ EPA-HQ-OAR-2021-0317-2298, -2301, -2221, -2254, -2428, -
2423, -2399, -2254, -2483, -2227, -2208, -2298, -2292, and -2202.
---------------------------------------------------------------------------

    Some commenters \583\ expressed concern with the proposed 
definition for the term ``legally and practicably enforceable'' as it 
relates to state emissions limits for ``storage vessel affected 
facilities'' that limit their potential for VOC emissions below 6 tpy. 
One commenter \584\ believed that in effect, if the EPA deems 
applicable state standards not ``legally and practically enforceable,'' 
it would disregard the state limits and treat the storage vessels as 
uncontrolled for purposes of Federal regulation.\585\ The commenter was 
concerned that this proposal thus has the potential to create 
substantial friction between the EPA and the states and could result in 
many more facilities becoming subject to Federal emissions standards.
---------------------------------------------------------------------------

    \583\ EPA-HQ-OAR-2021-0317-2298, -2301, -2221, -2254, -2428, -
2423, -2399, -2254, -2483, -2227, and -2208.
    \584\ EPA-HQ-OAR-2021-0317-2301.
    \585\ See 86 FR at 63202 (``Only those limits that include the 
elements described [in the proposed definition] will be considered 
`legally and practicably enforceable' for purposes of determining 
the potential for VOC emissions from a single storage vessel or tank 
battery, and thus applicability (or nonapplicability) of each single 
storage vessel or tank battery as an affected facility under the 
rule.'').
---------------------------------------------------------------------------

    Another commenter \586\ opined that where a rule contains an 
emissions threshold under which a given piece of equipment is not 
subject to the rule's requirements, it is fair and logical that the 
equipment be considered outside of rule coverage where emissions 
controls or limitations are in place to keep emissions below the 
threshold, even though in an uncontrolled state the equipment is 
capable of producing emissions above threshold levels. The commenter 
was concerned that that an owner or operator would be unable to claim 
the existence of legally and practicably enforceable limits or 
throughput limitations keeping a storage vessel below the applicability 
threshold if they are unable to coordinate with the applicable permit 
authority to work out specific limits, monitoring requirements, and 
recordkeeping that will ensure that any permitted emissions limit is 
achieved. The commenter also pointed out that some programs do not have 
minor source permitting programs allowing for inclusion of GHG 
emissions. The commenter summarized that a permit limit is a permit 
limit, and it is inconceivable that there is any Federal, state, or 
local permit that does not carry with it the ability of the issuing 
authority to ensure and enforce compliance if permit limits are 
exceeded. The commenter stated that they recognize that reporting, 
recordkeeping, and monitoring requirements will vary from permit to 
permit, but that all permits ultimately must be complied with or 
enforcement consequences from the issuing authority may follow. To the 
commenter's knowledge, they stated, there is no permit that does not 
contain consequences for violations.
---------------------------------------------------------------------------

    \586\ EPA-HQ-OAR-2021-0317-2221.
---------------------------------------------------------------------------

    Another commenter \587\ likewise was concerned that existing 
permits in many states may not meet the criteria that the EPA is 
proposing for legally and practicably enforceable permit terms and 
believes that the proposed changes will require states to review and 
revise countless permits and also may require states to engage in 
rulemakings over and above the efforts states will be required to 
initiate to implement these rules. The commenter stated that the EPA 
has neither explained nor justified this policy change, as it must, and 
should retract it. Another commenter \588\ stated that the proposed 
criteria for legally and practicably enforceable limits provide no 
additional benefit and pose several permitting problems.
---------------------------------------------------------------------------

    \587\ EPA-HQ-OAR-2021-0317-2423.
    \588\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Similarly, another commenter \589\ believed that states are much 
better equipped to determine the appropriate methods for the specific 
circumstances facing industries within their state and that process is 
required under the EPA's regulations (when the states meet certain 
conditions). The commenter was concerned that the proposed requirements 
conflict with the approach used in both the title V and NSR/PSD 
permitting programs. Under these programs, the commenter explained, 
operators may rely on control requirements to limit their PTE that 
would no longer be available under the proposed rule. In effect, the 
commenter was concerned, the proposed rule would arbitrarily require 
operators to have two different PTE calculations--one for title V and 
NSR permitting and another for NSPS/EG under this rule. The commenter 
stated that the definitions of ``potential to emit'' and ``federally 
enforceable'' show that the EPA's own regulations provide states with 
substantial latitude to establish ``legally enforceable procedures.'' 
The commenter cited to 40 CFR part 51 for the definition of ``potential 
to emit'' \590\ and ``federally enforceable'' \591\ and concluded that 
the TCEQ (Texas Commission on Environmental Quality) emissions limits, 
established under its EPA-approved SIP, are by the EPA's own part 51 
definitions, federally enforceable. The commenter further noted that 
the EPA previously determined that the regulations and permits issued 
by both the TCEQ and the NMED (New Mexico Environment Department) were 
legally and practicably enforceable. The commenter also stated that in 
the preamble to the proposed 2013 amendments to NSPS OOOO, the EPA 
reviewed the regulations in several states to determine which states 
already had storage tank control requirements for calculating PTE. 
Based on its evaluation of these regulations, the commenter stated, the 
EPA determined that several states already had legally and practicably 
enforceable regulations, including both Texas and New Mexico, such that 
the EPA could subtract the storage vessels in these states ``from the 
overall count of storage vessels that would be subject to the final 
rule.'' The commenter believed that the EPA's proposal to require a new 
definition of ``legally and practicably enforceable'' substitutes its 
own judgment as to what is legally and practicably enforceable when its 
own regulations say that determination should be left to the states, 
subject to the EPA review. This commenter \592\ and another commenter 
\593\ suggested that the SIP review process is the appropriate 
mechanism as opposed to attempting to

[[Page 16977]]

make changes in this regulation. The commenter \594\ believed that, 
when given the opportunity to review the regulations of Texas and New 
Mexico with regard to calculating PTE, the EPA already has determined 
that those regulations were federally enforceable.
---------------------------------------------------------------------------

    \589\ EPA-HQ-OAR-2021-0317-2254.
    \590\ ``Potential to emit is the maximum capacity of a 
stationary source to emit a pollutant under its physical and 
operational design. Any physical or operational limitation on the 
capacity of the source to emit a pollutant, including air pollution 
control equipment and restrictions on hours of operation or on the 
type or amount of material combusted, stored, or processed, shall be 
treated as part of its design only if the limitation or the effect 
it would have on emissions is federally enforceable.'' See, e.g., 40 
CFR 51.165(a)(1)(iii).
    \591\ ``. . . all limitations and conditions which are 
enforceable by the Administrator . . . [and] requirements within any 
applicable State implementation plan . . .''. Id. at 40 CFR 
51.165(a)(1)(xiv).
    \592\ EPA-HQ-OAR-2021-0317-2254.
    \593\ EPA-HQ-OAR-2021-0317-2399.
    \594\ EPA-HQ-OAR-2021-0317-2254.
---------------------------------------------------------------------------

    Among other concerns, some commenters \595\ noted that sources do 
not have methane limits in permits and that prohibiting the use of 
permits-by-rule and general permits would impose enormous burdens on 
sources and delegated state authorities, for which the proposal makes 
no provision. One commenter \596\ was concerned that this prohibition 
would have a cascading effect on title V determinations across numerous 
sources, imposing substantial additional burdens and complexities on 
sources and states. The commenter stated that if the EPA decides to 
finalize the text, the EPA should recognize that sources in good faith 
went to the regulator and obtained a permit under the applicable state 
minor source program and thus, at a minimum, the commenter stated, the 
EPA should provide flexibility by phasing in the requirement and 
applying the new definition only when a source needs to apply for a new 
or revised permit or a permit renewal. Moreover, crucially, for all 
existing sources, the commenter stated that the EPA should be clear 
that existing permits authorizing a source to operate remain fully 
effective, pending state processing of new permits.
---------------------------------------------------------------------------

    \595\ EPA-HQ-OAR-2021-0317-2399 and -2428.
    \596\ EPA-HQ-OAR-2021-0317-2399.
---------------------------------------------------------------------------

    Another commenter \597\ similarly believed that the proposed 
revisions are inconsistent with the EPA's reliance on states to 
administer the CAA with regard to title V and PSD. That is, the 
commenter stated, the EPA allows states to establish emissions limits 
for sites to keep their emissions below title V and PSD permitting 
thresholds. Monitoring, recordkeeping, and reporting requirements in a 
permit should be tailored to align with the level of authorization, 
with minor sources having fewer requirements than major sources, 
according to the commenter. The commenter recommended that for 
streamlined permitting mechanisms, such as Permits by Rule in Texas, 
the state agency would have to engage in rulemaking before operators 
could rely on such permits for determining storage vessel and tank 
battery PTE. Such rulemaking could take months to years, meaning that 
operators cannot rely on legally and practicably enforceable limits 
until those rule updates are finalized and effective, according to the 
commenter.
---------------------------------------------------------------------------

    \597\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA recognizes that current permits for NSPS OOOO and 
OOOOa sources may not entirely meet the criteria that the EPA is 
finalizing for legally and practicably enforceable limits for purposes 
of NSPS OOOOb and EG OOOOc. The EPA disagrees, however, that the final 
rule necessitates that all existing permits be rewritten. These 
specific criteria do not retroactively apply to permit limits or other 
requirements that owners and operators had previously relied upon in 
determining NSPS OOOO or OOOOa applicability to their storage vessels. 
The criteria will apply when determining NSPS OOOOb applicability to 
new storage vessels, i.e., those for which construction, 
reconstruction, or modification commenced after December 6, 2022, and 
when determining applicability for existing storage vessels covered by 
the yet-to-be-developed state plans implementing EG OOOOc. For new 
storage vessels constructed, reconstructed, or modified before the 
effective date of this final rule, to the extent their owners or 
operators decided to obtain legally and practicably enforceable limits 
to cap the potential emissions from their storage vessels below the 
proposed NSPS OOOOb applicability thresholds, those owners or operators 
were on notice of the EPA's proposed LPE criteria when obtaining such 
limits. Accordingly, the EPA does not agree that it is necessary to 
provide a transitional period for sources to obtain or revise permits 
before applying the new LPE criteria for determining applicability of 
the storage vessel standards under NSPS OOOOb or under future state 
and/or Federal plans implementing EG OOOOc.
    With regard to existing sources, the EPA notes that existing 
permits for designated facilities will need to be reopened to include 
legally and practicably enforceable methane emission limits to the 
extent facilities want to take into account such limits in determining 
storage vessel standards applicability. States that use permit-by-rule 
or general permits have the discretion to evaluate at any time 
(including now or as they develop their state plans to implement EG 
OOOOc) whether to modify those rules to incorporate the new criteria 
for legally and practicably enforceable limitations.
    The EPA notes that for both new and existing sources, it is a 
voluntary decision on the part of an owner or operator to obtain a 
permit with ``legally and practicably enforceable'' criteria in order 
to avoid having to comply with the applicable standard in NSPS OOOOb or 
a state or Federal plan pursuant to EG OOOOc. A source may opt to 
comply with the underlying rule when the potential for VOC or methane 
emissions exceeds the relevant applicability thresholds. In the future, 
the EPA may initiate further rulemaking to address this provision if 
its implementation merits further regulatory action.
    The EPA disagrees that the criteria the EPA is promulgating 
conflict with other CAA programs, such as title V and NSR programs. The 
EPA cannot understand how more specific criteria for a specific purpose 
within NSPS OOOOb can undermine compliance with title V and NSR 
permits, and the commenter did not provide specific examples that the 
EPA could review. Further, while the LPE criteria being finalized here 
may be more stringent than what states are currently using for other 
contexts, the commenter has not identified any direct conflict that 
would prevent the commenter from meeting the criteria in other 
programs, as more stringent criteria can be used to demonstrate 
compliance with less stringent requirements.
    In response to the comment that approved SIP rules are federally 
enforceable, the EPA agrees. The EPA's promulgation of NSPS OOOOb and 
EG OOOOc does not affect previously approved SIP actions that 
incorporate NSPS OOOO or OOOOa. The EPA is establishing requirements 
for sources subject to NSPS OOOOb and EG OOOOc to show ongoing 
compliance with the NSPS, and if the revised NSPS subparts are adopted 
and approved as part of a SIP, the LPE criteria provisions will be 
federally enforceable for permits issued within the state. The EPA 
routinely revises such standards to address the next generation of 
sources. In this instance EPA is adding a pollutant and further 
defining how legally and practicably enforceable limits must be 
supported by site-specific information that supports an operator's 
claim to be operating within those limits, in compliance with the rule.
    As the commenters note, in 2013,\598\ the EPA found that 11 states 
already required control devices for storage vessels, including both 
Texas and New Mexico, such that the EPA could subtract the storage 
vessels in these states ``from the overall count of storage vessels 
that would be subject to the final rule.'' \599\ However, the purpose 
of referring to those state regulations was in order to estimate the 
total number of storage vessels that would need to be

[[Page 16978]]

controlled nationwide and evaluate whether there were enough control 
devices available to owners and operators of storage vessels for 
implementation of the rule in the process of considering a petition for 
reconsideration. The EPA disagrees with the commenter's assertion that 
the EPA made a ``determination'' as to the adequacy of the state 
permitting regulations for purposes of determining applicability of the 
NSPS. In particular, the EPA did not make any determination as to the 
legal and practicable enforceability of the state permitting 
regulations, including for Texas or New Mexico.
---------------------------------------------------------------------------

    \598\ 78 FR 22126 (April 12, 2013).
    \599\ 78 FR 22130.
---------------------------------------------------------------------------

    Regarding the concern that existing sources do not have methane 
limits in permits now, CAA section 111(d) and the EPA's implementing 
regulations in 40 CFR part 60, subpart Ba, mandate that states adopt 
plans to set performance standards for designated pollutants; for 
purposes of EG OOOOc, the designated pollutant is GHGs, and the 
presumptive standards in EG OOOOc are expressed in the form of methane. 
Therefore, only permit limits on methane emissions can be included in 
determining applicability of the methane standards for storage vessels 
in the applicable state or Federal plan implementing EG OOOOc. The EPA 
agrees with the commenter that a reasonable period of time may be 
required to adopt state plans consistent with EG OOOOc, including to 
revise permit limits for storage vessels that choose to be subject to a 
legally and practicably enforceable limit below the methane 
applicability threshold. For that reason, as discussed in section 
XIII.E.2, the EPA has allowed states 24 months to carry out state 
rulemaking activity to adopt the appropriate standards. In addition to 
the 24 months, the EPA requires that states establish compliance 
deadlines that require compliance with the final state plan within 36 
months following the state plan submittal deadline, providing up to 5 
years for existing sources to adapt their systems to new Federal and 
state standards before compliance would be required. Further, because 
permits for existing sources will need to be reopened to include the 
final state plan criteria implementing the EG, the EPA does not believe 
that there is a substantial additional burden in ensuring that the 
``legally and practicably enforceable'' criteria are met.
    Commenters are correct that, consistent with the finalization of 
the ``legally and practicably enforceable'' criteria, the EPA may 
determine that some permit limits do not meet the criteria and the tank 
battery cannot use those limits when determining the potential for VOC 
and methane emissions; however, the EPA always has the authority to 
independently assess claims of nonapplicability. Regarding friction 
with states, as stated previously, the EPA believes finalizing the 
criteria will provide states with the needed level of specificity and 
certainty to issue permits that meet the ``legally and practicably 
enforceable'' criteria.
c. LPE Criteria
    Comment: Several commenters \600\ were concerned with the specific 
criteria provided for LPE. One commenter \601\ stated that permits have 
proposed annual or rolling 12-month limits on emissions and production 
because the tank PTE thresholds and NSR permitting thresholds are based 
on annual emissions. The commenter believed that the EPA should clarify 
that such annual limits meet the proposed 30-day averaging time for 
production limits especially since facilities are typically permitted 
for a worst-case scenario. Another criterion likely not in existing 
permits is ``periodic reporting that demonstrates continuous 
compliance,'' according to the commenter. Historically, the commenter 
pointed out, periodic reporting has applied to major sources under 
title V and affected facilities regulated under a NSPS or NESHAP, which 
the commenter stated is a small fraction of the sites that will be 
regulated under NSPS OOOOb and EG OOOOc.
---------------------------------------------------------------------------

    \600\ EPA-HQ-OAR-2021-0317-2222, -2483, -2399, and -2428.
    \601\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Another commenter \602\ stated that the requirements for legally 
and practicably limiting the ``potential for methane emissions'' are 
unclear and conflict with the definition of ``potential to emit.'' 
Specifically, the commenter stated:
---------------------------------------------------------------------------

    \602\ EPA-HQ-OAR-2021-0317-2222.
---------------------------------------------------------------------------

    <bullet> It is unclear why the EPA has proposed that production 
limits must be accompanied by operational limits in order to be legally 
and practicably enforceable. 40 CFR 60.5386c(e)(2)(i)(A).
    <bullet> It is unclear how a source would establish parametric 
limits for production and/or operational limits. 40 CFR 
60.5386c(e)(2)(i)(C).
    <bullet> It is unclear how a source would use a control device to 
meet an operational limit. 40 CFR 60.5386c(e)(2)(i)(C).
    The same commenter stated that the EPA should refer to the 
available caselaw and guidance on limiting ``potential to emit'' to 
ensure that the use of terms such as ``production limit,'' 
``operational limit,'' and ``parametric limit'' in the proposed rules 
are consistent with the widely accepted use of those terms in air 
permitting programs. One commenter \603\ expressed concern that 
proposed 40 CFR 60.5365b(e)(2)(i)(A), which requires a ``quantitative 
production limit and quantitative operational limit(s) for the 
equipment, or quantitative operational limits for the equipment,'' is 
inconsistent with longstanding EPA policy. The commenter believed that 
production and/or operational factors can be used as part of a 
parametric calculation of emissions, but they need not be 
standalone.\604\ Next, the commenter stated that proposed 40 CFR 
60.5365b(e)(2)(i)(B) requires an averaging period of less than 30 days 
when a production-based limit is used, but the commenter believed that 
is arbitrary and capricious, as well as inconsistent with EPA policy 
where the overall standard that the limit is intended to enforce is a 
tpy (i.e., annual) standard. In such a case, as here, a 12-month 
rolling limit, as long as it is well-defined in how it is calculated, 
is more than adequate, according to the commenter.\605\ Finally, the 
commenter stated that it takes issue with proposed 40 CFR 
60.5365b(e)(2)(i)(C) which requires that ``where a control device is 
used to achieve an operational limit, an initial compliance 
demonstration (i.e., performance test) for the control device [ ] 
establishes the parametric limits.'' While the commenter agreed that 
the regulations should certainly allow the use of a compliance 
demonstration, presumably in the form of a test, there is no reason for 
the EPA to preclude other means of estimating the control device 
efficiency, such as AP-42 factors or vendor-provided factors, 
especially when these factors are known to be conservative.
---------------------------------------------------------------------------

    \603\ EPA-HQ-OAR-2021-0317-2483.
    \604\ See, e.g., In re. Salt River Project Agua Fria Generating 
Station], Petition No. IX-2022-4, at 12-13 (Adm'r July 28, 2022), 
available at https://www.epa.gov/system/files/documents/2022-08/SRP%20Agua%20Fria%20Order_7-28-22.pdf, (``EPA does not interpret the 
Federal regulations to require production and/or operating limits in 
all situations.'').
    \605\ See, e.g., Memorandum from John S. Seitz, Director, EPA 
Office of Air Quality Planning and Standards, to EPA Regional Air 
Division Directors, Options for Limiting the PTE of a Stationary 
Source Under Section 112 and title V of the Clean Air Act, at 6 
(January 25, 1995), available at https://www.epa.gov/sites/default/files/documents/limit-pte-rpt.pdf (explaining that ``annual limits 
such as rolling annual limits'' are appropriate to practically 
enforce an annual emission limitation).
---------------------------------------------------------------------------

    Response: With respect to the proposed 30-days-or-less averaging 
time period for a production-based limit, the EPA agrees that a rolling 
12-month

[[Page 16979]]

average is an acceptable alternative to a month-by-month determination, 
where the rolling 12-month average is supported by 30-day subtotals, 
beginning in the first 30 days, and redetermined every month. This is 
consistent with the EPA's longstanding guidance, which expresses the 
Agency's ``preference toward short term limits, generally daily but not 
to exceed a month.'' \606\ The 30-day averaging time is particularly 
needed here because determination of potential emissions (and in turn 
storage vessel standards applicability) is required within the first 30 
days after startup of production for tank batteries at well sites and 
centralized production facilities; an averaging period longer than 30 
days would mean there will not be sufficient data to estimate potential 
emissions by the 30-day deadline whether the production limit 
effectively caps a tank battery's potential emissions below the 
applicable threshold(s) under NSPS OOOOb or EG OOOOc. Therefore, when 
establishing permit limits on production or operation, the EPA believes 
that such limits should not exceed 30 days. The EPA also points out 
that a violation of a 12-month standard without any prior interval to 
verify compliance has the potential to create a full year of 
noncompliance and associated penalties for failure to demonstrate 
ongoing compliance.
---------------------------------------------------------------------------

    \606\ See memorandum, Options for Limiting the Potential to Emit 
(PTE) of a Stationary Sources under Section 112 and Title V of the 
Clean Air Act (Act). https://www.epa.gov/sites/default/files/2015-07/documents/ptememo.pdf.
---------------------------------------------------------------------------

    Regarding production limits and operational limits, the final rule 
provides that if a production limit is used, it must be accompanied by 
operational limits to be legally and practicably enforceable because in 
that situation, potential VOC and methane emissions from a storage 
vessel are a function of both the facility's operational conditions and 
production rates. Therefore, both are inputs to the storage vessel 
emissions calculations. Also, because changes in either may result in 
an increase in vessel emissions, monitoring is required for both the 
operational conditions and the production rates used to establish 
emissions from the storage vessel.
    The EPA does not believe, and the commenter did not explain how, 
the usage of ``production limit,'' ``operational limit,'' and 
``parametric limit'' in the proposed rules is inconsistent with the 
widely accepted use of those terms in air permitting programs. The EPA 
clarifies that an operational limit on a control device is typically 
the claimed reduction efficiency of the control system, such as the 
destruction efficiency of a flare or availability of the VRU to route 
vapors to process. To demonstrate compliance with such operational 
limits, parametric limits for a control device are established during 
manufacturer or source-specific performance testing of the device. The 
EPA clarifies that ``parametric limits'' refer to limits on a parameter 
that can act as a reliable indicator of an emissions-producing (or 
emissions-reducing) activity or process. Parametric limits for control 
devices can include flow rate, inlet pressure, residence time, 
combustion zone temperature, or similar metrics.
    Regarding the comment on the use of AP-42 and vendor-provided 
emission factors for estimating control efficiency of control devices, 
the EPA clarifies that the proposed LPE criteria do not preclude such 
use of emission factors. Rather, the criteria require an initial 
compliance demonstration (i.e., performance testing) for a control 
device to establish parametric limits where a control device is used to 
achieve an operational limit. It is not clear, and the commenter did 
not explain how, AP-42 or vendor-provided emission factors could be 
used to establish parametric limits. The EPA is therefore finalizing 
the LPE criteria as proposed.
2. Modification
    Comment: Several commenters \607\ expressed concern that the EPA 
has departed from the definition of modification found at 40 CFR 60.14. 
One commenter \608\ recommended that the EPA limit modifications to 
where the operator increases emissions from the tank battery by 
increasing the capacity of the tank battery. The commenter explained 
that as proposed, subparagraphs (A) and (B)of 60 CFR 60.5365b(e)(3)(ii) 
would trigger a potential modification even where the increase in 
capacity of the tank battery is not accompanied by an increase in the 
tank battery's emissions rate. The commenter stated that operators may 
readily track and document the addition or replacement of storage 
vessels within a tank battery. The commenter cautioned that if the EPA 
does not define modification to require an increase in the emissions 
rate of the tank battery, perverse outcomes may occur. By way of 
example, the commenter explained that an operator may increase the size 
of tank battery without increasing the emissions from the tank battery, 
and if the emissions (which have not changed) exceed the applicability 
threshold, the tank battery would become an affected facility. The 
commenter explained that this possibility is real given that the EPA 
now proposes to apply the 6 tpy VOC and 20 tpy methane applicability 
thresholds to the entire tank battery, where it previously under NSPS 
OOOO and NSPS OOOOa used the same VOC threshold but on an individual 
storage vessel basis, which effectively reduces the NSPS applicability 
threshold proportionally by the number of individual storage vessels in 
a tank battery.
---------------------------------------------------------------------------

    \607\ EPA-HQ-OAR-2021-0317-2326, -2428, and -2399.
    \608\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    Regarding subparagraphs (C) and (D) of 40 CFR 60.5365b(e)(3)(ii), 
the same commenter \609\ explained that per 40 CFR 60.14(e)(2), an 
increase in throughput for a storage vessel, accomplished without a 
capital expenditure on that storage vessel, is not considered a 
modification and the EPA has not fully explained why it is proposing to 
deviate from the historical legal understanding of modification which 
requires both an increase in throughput and a capital expenditure on 
the storage vessel or tank battery. Other commenters \610\ expressed 
similar concerns regarding capital expenditure. Two commenters \611\ 
noted that increases in liquid throughput at well sites, central 
production facilities, and compressor stations are difficult to track, 
as operators typically track liquid throughput using tank gauging 
rather than flow meters. Further, one commenter \612\ explained, the 
modification criteria for tank batteries at well sites and centralized 
production sites serve as a disincentive to the centralization of 
facilities, as the addition of production from a new well to an 
existing centralized production facility would trigger a modification 
under 40 CFR 60.5395b(e)(3)(ii)(C). The commenter urged the EPA to 
consider that if the EPA does not remove the criteria at 40 CFR 
60.5395b(e)(3)(ii)(C), the increase in liquid throughput also must be 
accompanied by a capital expenditure on the tank battery itself. The 
commenter explained that some actions, such as drilling a new well or 
fracturing or refracturing an existing well, could increase liquid 
throughput and require capital expenditure but not necessarily on the 
tank battery itself.
---------------------------------------------------------------------------

    \609\ EPA-HQ-OAR-2021-0317-2326.
    \610\ EPA-HQ-OAR-2021-0317-2428 and -2399.
    \611\ EPA-HQ-OAR-2021-0317-2326 and -2428.
    \612\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    The same commenter \613\ recommended other clarifications to

[[Page 16980]]

subparagraph 40 CFR 60.5395b(e)(3)(ii)(C). First, the commenter 
believed that the EPA should remove the reference to ``process unit'' 
in subparagraph (C), because ``process unit'' is defined in the rule 
within the context of facilities that process natural gas, not well 
sites and centralized production facilities, and that the reference to 
process unit in the context of well sites and centralized production 
facilities is confusing and misplaced. Second, the commenter stated 
that the EPA should limit the scope of subparagraph (C) to ``actions 
taken with respect to equipment that directly, or through a series of 
equipment, provides crude oil, condensate, intermediate hydrocarbons, 
or produced water throughput to the tank battery, including the 
addition of, or change to, a production well (including hydraulic 
fracturing or refracturing of the well).'' By way of example, the 
commenter explained that hydraulic fracturing activities occurring in 
the vicinity of a well that delivers produced liquids to a storage tank 
battery may temporarily increase production of the well, which would, 
in turn, increase throughput of the tank battery, but as drafted, it is 
unclear whether this increase in production is an ``action'' that 
modified the tank battery if it resulted in exceedance of the potential 
for emissions threshold. The commenter believed the increase in 
production should not be considered an action, as operators cannot plan 
for or anticipate increases in production from activities occurring 
offsite that are outside the scope of operations associated with the 
tank battery. Further, in this example, the commenter explained that 
the cause of a temporary increase in production may be unknown to the 
operator and considering ``actions'' having no direct relationship to 
equipment in the definition of modification would be a far and extreme 
departure from longstanding NSPS modification principles. If the EPA 
retains these modification triggers, the commenter requested that well 
sites and centralized production facilities also be allowed to compare 
liquid throughputs to limits in a legally and practicably enforceable 
permit as is allowed for compressor stations and natural gas processing 
plants. The commenter believed this recommendation would also make 
modification criteria consistent for all sites and clearly define what 
an increase in liquid throughput is.
---------------------------------------------------------------------------

    \613\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    Similarly, one commenter \614\ stated that the December 2022 
Supplemental Proposal is not only inconsistent with the statutory 
definition of ``modification'' but also inconsistent with the EPA's 
prior interpretation that a ``modification'' requires some physical 
change to a tank. See Letter from Valdus Adamkus, EPA Region 5, to 
Bradley Miller, Hamilton County Environmental Services (March 25, 1996) 
\615\ (increase in vapor pressure resulting in increased tank emissions 
was not a ``modification'' under 40 CFR part 60, subpart Kb because 
there were no physical changes to the tank). The commenter was 
concerned that, unless the proposed definition of ``modification'' is 
revised to require a physical change or change in the method of 
operations, midstream owners and operators could find their equipment 
``modified'' solely based on the decisions of upstream third parties 
and without taking any action themselves.
---------------------------------------------------------------------------

    \614\ EPA-HQ-OAR-2021-0317-2399.
    \615\ See https://cfpub.epa.gov/adi/index.cfm?fuseaction=home.dsp_show_file_contents&CFID=1949573&CFTOKEN=fb4fc82ba0b35cd4-2102140A-E016-B8E6-76946EF822FC87A4&id=9600032.
---------------------------------------------------------------------------

    Another commenter \616\ provided some specific recommendations, if 
the EPA decides to include increases in liquid throughput as a 
criterion for modification:
---------------------------------------------------------------------------

    \616\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    <bullet> The increase in liquid throughput must also be accompanied 
by a capital expenditure on the tank battery itself. Actions, such as 
drilling a new well or fracturing or refracturing an existing well, 
could increase liquid throughput and require capital expenditure but 
not necessarily on the tank battery itself. These actions would not be 
considered modifications to the tank battery unless there is capital 
expenditure on the tank battery itself. This recommendation would make 
NSPS OOOOb consistent with the general provisions in 40 CFR 60 subpart 
A.
    <bullet> Reference to process unit in 40 CFR 60.5365(e)(ii)(C) 
should be removed since process unit is defined such that they should 
not exist at well sites and centralized production facilities. Process 
unit is a term specific to natural gas processing plants and does not 
apply to well sites and centralized production facilities.
    <bullet> Well sites and centralized production facilities should 
also be allowed to compare liquid throughputs to limits in a legally 
and practicably enforceable permit like compressor stations and natural 
gas processing plants. The EPA should be consistent and allow well 
sites and centralized production facilities to compare liquid 
throughputs to limits in a legally and practicably enforceable permit 
since such a permit can be relied upon for the PTE determination for 
all sites.
    <bullet> In the absence of a legally and practicably enforceable 
limit, all sites should be allowed to compare liquid throughputs to 
those used to design the existing cover and closed vent system in 
operation when a potential modification action occurs. These 
recommendations would also make modification criteria consistent for 
all sites and clearly define what an increase in liquid throughput is.
    The same commenter \617\ offered suggested edits to 40 CFR 
60.5365b(e)(3)(ii) consistent with their recommendations.
---------------------------------------------------------------------------

    \617\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA is finalizing the provisions regarding 
modification as proposed, except for minor edits to the regulatory text 
at 40 CFR 60.5365b(e)(3)(ii) to replace ``result in'' with ``occurs'' 
such that the provision is as follows: `` `Modification' of a tank 
battery occurs when any of the actions in paragraphs (e)(3)(ii)(A) 
through (D) of this section occur and the potential for VOC or methane 
emissions meets or exceeds either of the thresholds specified in 
paragraphs (e)(1)(i) or (ii) of this section.'' The EPA is making this 
change because the EPA already has determined that the actions 
described in 40 CFR 60.5365b(e)(3)(ii)(A) through (D) result in an 
emissions increase, and the term ``result in'' may be incorrectly 
interpreted to suggest otherwise.
    CAA section 111(a)(4) defines ``modification'' as ``any physical 
change or operational change in a stationary source which increases the 
amount of any air pollutant emitted by such source . . . .'' While the 
general provisions at 40 CFR 60.14 provide a definition of 
modification, 40 CFR 60.14(f) specifically authorizes the EPA to 
provide subpart-specific definition for ``modification'' that would 
supersede any conflicting provision in 40 CFR 60.14. Pursuant to its 
authority under 40 CFR 60.14(f), the EPA proposed to define 
``modification'' of a tank battery under NSPS OOOOb (40 CFR 
60.5365b(e)(3)(ii)) to mean when the potential emissions of the tank 
battery exceed the 6 tpy VOC or 20 tpy methane threshold following any 
of the following physical or operational changes:
    (A) a storage vessel is added to an existing tank battery;
    (B) one or more storage vessels are replaced such that the 
cumulative storage capacity of the existing tank battery increases;
    (C) for tank batteries at well sites or centralized production 
facilities, an

[[Page 16981]]

existing tank battery receives additional crude oil, condensate, 
intermediate hydrocarbons, or produced water throughput from actions, 
including but not limited to, the addition of operations or a 
production well, or changes to operations or a production well 
(including hydraulic fracturing or refracturing of the well); or
    (D) for tank batteries at compressor stations or onshore natural 
gas processing plants, an existing tank battery receives additional 
fluids which cumulatively exceed the throughput used in the most recent 
(i.e., prior to an action in paragraphs (e)(3)(ii)(A), (B) or (D) of 
this section) determination of the potential for VOC or methane 
emissions.
    The EPA did not propose to require a showing of an emission 
increase, having determined that each of the four scenarios describes a 
physical or operational change that results in an emission increase. 
With respect to scenarios (A) and (B) above, the EPA explained in the 
November 2021 Proposal that even if the type and quantity of fluid 
processed remain the same, the increased storage capacity will lead to 
higher breathing losses and thereby increase emissions from the tank 
battery. See 86 FR 63198. With respect to scenario (C), as the EPA 
explained in the November 2021 Proposal (86 FR 63199) and reiterated in 
the December 2022 Supplemental Proposal (87 FR 74802), ``actions 
occurring at a well site, such as refracturing a well or adding a new 
well that sends these liquids to the tank battery at the well site or 
centralized production facility, would result in an increase in VOC and 
methane emissions based on an increase in volumetric throughput to the 
tank battery.'' With respect to scenario (D), which addresses storage 
vessels at compressor stations and gas processing plants, the EPA 
acknowledges that ``storage vessels at these locations are designed to 
receive liquids from multiple well sites that may startup production 
over a longer period of time''; the EPA therefore ``agrees that when a 
tank battery at a compressor station or onshore natural gas processing 
plant receives additional throughput which has already been accounted 
for in the design capacity of that tank battery and included as a 
legally and practically enforceable limit in a permit for the tank 
battery, that additional throughput does not result in an emission 
increase from the tank battery because those emissions have already 
been accounted for in the permit.'' (87 FR 74802). In other words, 
there is emission increase under scenario (D) when the emissions from 
the additional throughput is not accounted for in the design capacity 
of the tank battery.
    While the EPA has determined that an emissions increase results 
from each of the four scenarios described in 40 CFR 60.5365b(e)(3)(ii), 
none of them automatically result in the potential for VOC or methane 
emissions to be at or above the VOC or methane emissions thresholds in 
NSPS OOOOb; each of the scenarios would trigger the need to complete 
the ``potential for VOC or methane emissions'' determination under 40 
CFR 60.5365b(e)(1)(ii).
    The EPA disagrees with the comment that modification based on an 
increase in the tank battery's capacity (i.e., scenarios (A) and (B)) 
must be accompanied by an increase in the tank battery's emission rate 
and that modification based on increased throughput (i.e., scenarios 
(C) and (D)) must be accompanied by a capital expenditure. As mentioned 
above, CAA section 111(a)(4) defines ``modification'' as ``any physical 
change or operational change in a stationary source which increases the 
amount of any air pollutant emitted by such source . . . .'' The 
statutory definition does not require that there be an increase in an 
``emission rate,'' and it makes no reference to ``capital 
expenditure''; therefore, neither is requisite to determining 
modification. Further, 40 CFR 60.14(f) authorizes the EPA to set forth 
``[s]pecial provisions . . . under an applicable subpart of this part 
[that] shall supersede any conflicting provisions of this section.''
    With respect to scenarios (A) and (B), as explained above, the EPA 
determined that an increase in tank battery capacity (scenarios (A) and 
(B)) will always increase the emissions from that tank battery. The 
commenters do not mention, much less disagree with or question, the 
EPA's rationale. Having already determined that scenarios (A) and (B) 
increase emissions, there is no need to require emission rate 
calculation for purposes of determining whether there is an emission 
increase under these scenarios. The EPA therefore declines the 
suggestion to require that scenarios (A) and (B) be accompanied by an 
increase in the tank battery's emission rate.
    With respect to scenarios (C) and (D), the commenters did not 
explain why these scenarios must be accompanied by a capital 
expenditure other than pointing to 40 CFR part 60, General Provisions, 
40 CFR 60.14(e)(2), which exempts from ``modification'' a facility that 
increases its production rate (and thus emissions) but without a 
capital expenditure on that facility. The EPA notes that this exemption 
was promulgated in 1975, at the early stage of the EPA's CAA section 
111 rulemaking. The EPA had just promulgated NSPS for the first five 
listed source categories (steam generators, portland cement plants, 
incinerators, nitric acid plants, and sulfuric acid plants) a few years 
earlier in 1971.\618\ All of these facilities were traditional 
industrial plants; there is no indication that in those earlier years 
of CAA section 111 rulemakings, the EPA had the occasion to evaluate 
more complex and unique source categories such as the crude oil and 
natural gas source category, where a physical or operational change at 
one affected facility (e.g., fracking of a well) causes physical/
operational change and emission increase at another affected facility 
(a tank battery). What is clear is that 40 CFR 60.14(f), which the EPA 
promulgated concurrently with 40 CFR 60.14(e), authorizes the EPA to 
establish in individual rule subparts provisions that supersede any 
conflicting provisions in 40 CFR 60.14(e). As explained earlier, under 
scenarios (C) and (D), there is always a physical/operational change 
and emission increase at a tank battery when receiving additional 
throughput; this is the case whether or not there is capital 
expenditure on the tank battery. However, 40 CFR 60.14(e) would exempt 
tank batteries under scenarios (C) and (D) from regulation if there is 
no capital expenditure, even if they have potential emissions above the 
thresholds established in this rule. The EPA does not believe, and the 
commenters do not explain why, such exemption is justified. Therefore, 
the EPA declines to include a requirement that there be a capital 
expenditure under scenarios (C) and (D).
---------------------------------------------------------------------------

    \618\ 36 FR 24876 (December 23, 1971).
---------------------------------------------------------------------------

    With respect to the comment claiming that the EPA previously 
interpreted ``modification'' to require physical change to a tank, the 
1996 EPA letter that the commenter cited as support made no such 
pronouncement. Further, the letter addressed applicability of a storage 
tank regulated under the New Source Performance Standard, subpart Kb, 
and the exemption at issue was 40 CFR 60.14(e)(4) (use of an 
alternative fuel or raw material that the existing facility was 
designed to accommodate). It is not clear, and the commenter did not 
elaborate, how that determination applies here, not to mention that the 
EPA has since taken a different

[[Page 16982]]

position.\619\ The EPA therefore made no change in response to this 
comment.
---------------------------------------------------------------------------

    \619\ See ``New Source Performance Standards Review for Volatile 
Organic Liquid Storage Vessels (Including Petroleum Liquid Storage 
Vessels); Proposed Rule,'' 88 FR 63535 (October 3, 2023) (proposing 
to reinterpret the applicability of 40 CFR 60.14(e)(4) to not apply 
to changes in the organic liquid stored in a storage vessel).
---------------------------------------------------------------------------

    We agree with a commenter's suggestion of removing the term 
``process unit'' from proposed 40 CFR 60.5365b(e)(3)(ii)(C), which in 
the December 2022 Supplemental Proposal defined ``modification'' of 
tank batteries at well sites or centralized production facilities as 
when ``an existing tank battery receives additional crude oil, 
condensate, intermediate hydrocarbons, or produced water throughput 
from actions, including but not limited to, the addition of a process 
unit or production well, or changes to a process unit or production 
well (including hydraulic fracturing or refracturing of the well). We 
agree with the commenter that the term ``process unit,'' as defined in 
the proposed NSPS OOOOb and EG OOOOc, relates specifically to natural 
gas processing plants. In the final rule, the EPA has substituted the 
term ``process unit'' with ``operations,'' a more generic term to cover 
activity that could result in additional product throughput to a tank 
battery at a well site or centralized production facility.
    Regarding the comment that in the absence of a legally and 
practicably enforceable limit, all sites should be allowed to compare 
liquid throughputs to those used to design the existing cover and 
closed vent system in operation when a potential modification action 
occurs, the EPA disagrees because the throughput used in the design 
analysis for the cover and closed vent system itself is not a legally 
and practicably enforceable limit on throughput. The design analysis 
also may include emissions from other than a storage vessel affected 
facility, making it difficult to extract the contribution from the tank 
battery. Finally, if the prior determination (i.e., before one of the 
potential modification actions) was that the tank battery was not a 
storage vessel affected facility, then the requirements to control the 
tank battery and design and operate a cover and closed vent system 
would not apply and no record of the cover and closed vent system 
design would exist.
    The EPA must defer to a case-by-case determination on the comment 
asking that the EPA determine whether an action ``. . . from activities 
occurring off-site that are outside the scope of operations associated 
with the tank battery'' is not an action that results in a modification 
because of the seemingly site-specific circumstances of the example. 
The commenter seems to be citing an example of hydraulic fracturing at 
a nearby well that induces a change in throughput to tanks at another 
unrelated well site or centralized production facility. Regarding 
temporary increases in throughput, the modification actions do not have 
a temporal element. For the reasons discussed in the November 2021 
Proposal, the EPA believes the actions will result in emissions 
increase to the atmosphere. See 86 FR 63198. Limitations on throughput 
may be accounted for in a legally and practicably enforceable limit 
when determining the potential for VOC and methane emissions, which 
determination is conducted after one of the actions occurs.
    Regarding the comment that an owner or operator has difficulty 
tracking liquid throughput because operators typically track liquid 
throughput using tank gauging rather than flow meters, the EPA 
clarifies that the final rule does not require any specific equipment 
for tracking throughput and, therefore, throughput can be tracked using 
gauging.
    Regarding the comment that the owner or operator of midstream tank 
batteries at compressor stations or natural gas processing plants has 
no control over the receipt of fluids from upstream production 
facilities owned by third parties, as explained above, as long as the 
additional throughput is accounted for in the design capacity of the 
tank battery, the additional throughput does not result in an emissions 
increase from the tank battery because those emissions have already 
been accounted for in the permit. See 87 FR 74802. The EPA proposed 
language to that effect at 40 CFR 60.5365b(e)(3)(ii)(D) and 
60.5365b(e)(2)(iii)(A) and (B). The EPA therefore is finalizing, as 
proposed, the requirements regarding modification actions at natural 
gas processing plants and compressor stations. In summary, a tank 
battery at a natural gas processing plant and compressor station is 
considered to be modified if one of the actions (adding a storage 
vessel to an existing tank battery, replacing one or more storage 
vessels such that the cumulative capacity of the tank battery 
increases, or the existing tank battery receives additional fluids 
which cumulatively exceed the throughput used in most recent 
determination of the potential for VOC or methane emissions) occurs and 
the potential for VOC or methane emissions meets or exceeds the 
thresholds.
    Regarding the comment that the modification criteria create a 
disincentive to the centralization of facilities, the EPA is not 
persuaded that operators locate and design their tank batteries to 
avoid modification determinations because at some point in the future a 
well may be added to route product to the tank battery, and the EPA 
believes the decisions are based on the economics of well production. 
The EPA notes that our BSER analysis has determined that it is cost-
effective to control emissions of VOC and methane at 6 tpy and 20 tpy, 
respectively, regardless of the number or the location of the tank 
batteries.
    The EPA here reiterates that modification requires two conditions--
that (1) one of the actions in 40 CFR 60.5365b(e)(3)(ii) (A) through 
(D) occurs, and (2) the potential for emissions from the tank battery 
meets or exceeds 6 tpy VOC or 20 tpy methane (applicability 
determination). With regard to the comment that an increase in the size 
of a tank battery alone would trigger applicability, that is not the 
case. The applicability determination must be performed within 30 days 
under 40 CFR 60.5365b(e)(2)(ii) after adding the storage vessel or 
replacing a storage vessel with another storage vessel of greater 
capacity, and where the applicability determination indicates that 
emissions are less than 6 tpy VOC or 20 tpy methane, the storage vessel 
would remain an unaffected facility under NSPS OOOOb.
    Comment: Several commenters \620\ were concerned about the 
modification provisions related to replacement of a storage tank. One 
commenter \621\ stated that an operator of an unregulated tank or tank 
in a battery that reaches the end of its safe operational life and must 
be replaced should not be required to have to prove that the tank or 
tank battery should still be unregulated. The commenter explained that 
many oil and gas wells typical of legacy production are limited in 
their productive life only by the life of the tubulars in them (as 
exhibited by the many 100-year-old-plus wells still producing in the 
Appalachian Basin of east Kentucky). The commenter believed that 
operators should be permitted to replace equipment in kind (e.g., akin 
to a ``standard set'' for the refining industry) and should not be 
burdened with potentially expensive compliance activities for replacing 
equipment that has reached the end of its useful life. The commenter 
expressed that they believed that if the EPA

[[Page 16983]]

finalizes the modification provisions as proposed, many operators will 
not replace equipment and that those modification provisions would 
result in more emissions from equipment not being replaced to avoid the 
EPA's compliance requirements. Another commenter \622\ recommended that 
replacement of a tank that only increases battery capacity should not 
trigger a modification because, the commenter states, an increase in 
tank capacity does not equal an increase in emissions and, therefore, 
should not be considered a modification under any rule.
---------------------------------------------------------------------------

    \620\ EPA-HQ-OAR-2021-0317-2172, -2298, and -2248.
    \621\ EPA-HQ-OAR-2021-0317-2172.
    \622\ EPA-HQ-OAR-2021-0317-2298.
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    One of the commenters \623\ expressed concern about the 
modification provisions related to relocation of a storage vessel. The 
commenter stated that certain activities the EPA is proposing which 
potentially trigger a modification include activities that are not a 
``physical change in, or change in the method of operation of, a 
stationary source'' as required by CAA section 111(a)(3). By way of 
example, the commenter pointed out that the definition of modification 
in the proposed rule could include the relocation or replacement of a 
storage vessel. The commenter also stated that they do not believe that 
the EPA has demonstrated the necessity of this change or how its 
implementation will benefit the environment.
---------------------------------------------------------------------------

    \623\ EPA-HQ-OAR-2021-0317-2248.
---------------------------------------------------------------------------

    Response: The EPA believes that scenarios regarding the relocation 
of an existing tank battery or replacement ``in like kind'' (i.e., the 
cumulative throughput capacity is not increased) are not governed by 
the modification provisions, but are akin to relocation and 
reconstruction provisions, respectively. See discussion below which 
clarifies which provisions (i.e., construction, reconstruction, 
modification, or return to service) would need to be evaluated under 
different tank replacement or relocation scenarios. On the other hand, 
replacement of a tank that adds capacity to the tank battery 
constitutes a modification. The EPA assumes that a facility adding 
storage capacity anticipates an increase in production, which will lead 
to higher emissions from the tank battery (86 FR 63199). Further, as 
mentioned earlier, even if the type and quantity of fluid processed 
remain the same, the increased storage capacity will lead to higher 
breathing losses and thereby increase emissions from the tank battery. 
See 86 FR 63198. The commenter does not dispute that, much less 
providing a reason why, either of these rationales is incorrect. 
Therefore, the definition of ``modification'' in the final rule, 
specifically 60.5365b(e)(3)(ii)(A) and (B), is unchanged.
    Regarding the comment on relocation, the EPA wishes to clarify 
which provisions (i.e., construction, reconstruction, modification, or 
return to service) would need to be evaluated under different tank 
replacement or relocation scenarios. When one or more tanks in an 
existing tank battery are replaced, but the cumulative storage capacity 
does not increase nor are tanks added to the total number, the 
replacement is not a ``modification'' as defined in 40 CFR 
60.5365b(e)(3)(ii)(A) and (B); however, if more than half of tanks in 
an existing tank battery are replaced, such replacement is 
``reconstruction'' under 40 CFR 60.5365b(e)(3)(i) if, after such 
replacement, the tank battery has the potential for 6 tpy or more of 
VOC emissions or 20 tpy or more of methane emissions (see comments and 
responses related to reconstruction in section XI.J.3 of the preamble). 
If a storage vessel affected (or designated) facility or portion of a 
storage vessel affected (or designated) facility that had been taken 
out of service is later returned to service (i.e., reconnected to the 
original source of liquids), it remains a storage vessel affected 
facility subject to the same requirements that applied before its being 
removed from service (see 40 CFR 60.5365b(e)(6) (or 60.5386c(e)(5)). If 
an existing tank battery is relocated, with no actions described in the 
modification provisions at 40 CFR 60.5365b(e)(3)(ii) taking place, and 
without replacement of any tanks or other components in the tank 
battery, then there is no modification or reconstruction of the 
relocated tank battery. Further, if this existing tank battery was 
determined not to be a designated facility under EG OOOOc (i.e., the 
potential methane emissions are less than 20 tpy), relocation of the 
existing tank battery does not change that status. Additional examples 
of the outcomes of certain actions regarding modification may be found 
in the December 2022 Supplemental Proposal. See 87 FR 74802.
3. Reconstruction
    Comment: One commenter \624\ believes that the proposed definition 
of reconstruction is internally inconsistent. The commenter cites to 
the EPA's rationale in the proposal that for a tank battery consisting 
of more than one storage vessel, reconstruction is based on replacing 
at least half of the storage vessels based on the assumption that ``the 
cost of replacing storage vessel components such as thief hatches and 
pressure relief devices, in comparison to the cost of constructing an 
entirely new storage vessel affected facility, will not exceed 50 
percent of the cost of constructing a comparable new storage vessel 
affected facility.'' However, the commenter points out, for a tank 
battery consisting of a single storage vessel, the existing provisions 
of 40 CFR 60.15 apply on the chance that the cost of replacement 
storage vessel components could be 50 percent or more of the cost to 
construct a comparable new storage vessel. The commenter explains that 
the cost of depreciable components on a storage vessel other than the 
tank itself either could be or could not be 50 percent or more of the 
cost of a new comparable tank. The commenter is concerned that this 
inconsistency means that operators would have to track the cost of 
storage vessel component replacements for single storage vessel tank 
batteries, but not for multi-vessel tank batteries. For both single- 
and multi-vessel tank batteries, the commenter believes that operators 
should have the option to track either storage vessel replacements or 
all depreciable components and provided suggested regulatory changes 
reflecting their recommendations.
---------------------------------------------------------------------------

    \624\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA agrees that there appeared to be an inconsistency 
in the discussion in the December 2022 Supplemental Proposal with 
respect to why the EPA proposed to define ``reconstruction'' 
differently for a tank battery with more than one storage vessel and a 
tank battery with a single storage vessel. For the former, the EPA 
proposed to simplify and streamline the reconstruction determination 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 was based on the EPA's expectation that when an 
affected facility is replacing one or more storage vessels in a tank 
battery, the capital costs for the individual storage vessel 
replacement would be comparable or similar. The EPA received support 
for this proposal. One commenter agrees that ``[b]ecause individual 
tanks 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 tanks being replaced at a site and the percentage of the 
fixed capital cost that would be required to

[[Page 16984]]

construct a comparable entirely new facility.'' \625\
---------------------------------------------------------------------------

    \625\ Cite to EDF 02/13/23 comment at 126.
---------------------------------------------------------------------------

    The preamble to the December 2022 Supplemental Proposal also states 
that ``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 an entirely new storage vessel affected facility, 
will not exceed 50 percent of the cost of constructing a comparable new 
storage vessel affected facility'' (87 FR 74801-02) (emphasis added). 
This statement about replacing components appears to cover replacements 
not addressed by the proposal above, i.e., it is addressing 
replacements other than one-to-one storage vessel replacement in a tank 
battery with more than one storage vessel. However, the preamble does 
not provide a rationale for this statement; more importantly, the 
statement contradicts the EPA's proposal to apply 40 CFR 60.15 \626\ to 
reconstruction of a tank battery with a single storage vessel based on 
the contrary belief that ``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.'' (87 FR 74801) (emphasis added). The EPA solicited 
comment on this issue; one commenter responded that the cost of 
replacing the thief hatch, pressure relief device, or other depreciable 
components would not exceed 50 percent of the cost of an entirely new 
comparable tank battery, but the commenter did not provide any 
supporting information for its comment. Although this statement could 
be true where only some fraction of depreciable components (and perhaps 
for some fraction of the total storage vessels) in the tank battery 
were replaced, it remains possible that the cost of replacing the thief 
hatch, pressure relief device, or other depreciable components could 
exceed 50 percent of the cost of a comparable entirely new facility. 
Further, we are concerned that if we were to apply the proposed 
reconstruction definition for a tank battery with more than one storage 
vessel (i.e., replacing more than 50 percent of the storage vessels in 
a tank battery constitutes reconstruction) and to replacements that are 
not one-to-one storage vessel replacement, it could potentially have an 
unintended effect of disincentivizing owners and operators from 
replacing old storage vessels.
---------------------------------------------------------------------------

    \626\ 40 CFR 60.15, which defines ``reconstruction'' as when the 
cost of replacing components of an existing facility exceeds 50 
percent of the cost of constructing a comparable tank battery 
affected facility, would require keeping accounting of the 
replacement costs for the ``reconstruction'' determination.
---------------------------------------------------------------------------

    In light of the above, while the EPA continues to believe that it 
is appropriate to simplify and streamline the ``reconstruction'' 
determination where there is one-to-one storage vessel replacement in a 
tank battery, the EPA cannot definitively conclude that other 
replacements to a tank battery with more than one storage vessel would 
never exceed 50 percent of the cost of an entirely new storage vessel; 
in that respect, there is no difference between a tank battery with a 
single storage vessel and a tank battery with more than one storage 
vessel. Therefore, in the final rule, the EPA is defining 
``reconstruction'' of a tank battery as follows:
    ``Reconstruction'' of a tank battery occurs when the potential for 
VOC or methane emissions from the tank battery meets or exceeds [either 
the 6 tpy VOC or 20 tpy methane threshold] and either:
    (A) at least half of the storage vessels are replaced in the 
existing tank battery that consists of more than one storage vessel; or
    (B) the provisions of Sec.  60.15 are met for the existing tank 
battery.
    Comment: Two commenters \627\ provided input on the timeframe for 
determining whether a reconstruction of a tank battery had occurred. 
The commenter agrees that a 2-year time frame is reasonable and will 
provide operators with a clear way to determine if reconstruction has 
been triggered. Another commenter \628\ believes that a 2-year rolling 
period provides a reasonable method of determining whether an owner of 
an oil and natural gas site with storage tanks is actually pursuing an 
extensive tank replacement program, within the EPA's original intent in 
promulgating 40 CFR 60.15.
---------------------------------------------------------------------------

    \627\ EPA-HQ-OAR-2021-0317-2403 and -2305.
    \628\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------

    Response: The EPA requested comment in the December 2022 
Supplemental Proposal regarding the specific timeframe within which 
replaced storage vessels in an existing tank battery will be aggregated 
towards determining whether the 50 percent replacement threshold has 
been exceeded. As summarized above, all of the commenters consider 2 
years to be a reasonable period, and one commenter specifically 
recommends a 2-year rolling period. The EPA is therefore finalizing a 
2-year rolling period.

K. Covers and Closed Vent Systems

    In section X.K of this document the final NSPS OOOOb and EG OOOOc 
requirements for covers and closed vent systems are summarized. 
Significant comments were received on the December 2022 Supplemental 
Proposal regarding the NIE standard. This topic, a summary of the 
proposed rule, the comments, the EPA responses, and changes made in the 
final rule (if applicable), are discussed here. These comments and the 
EPA's responses to these comments generally apply to the standards 
proposed in both NSPS OOOOb and EG OOOOc. The instances where the 
comment and/or response only applies to NSPS OOOOb or EG OOOOc are 
noted. Comments and changes relevant to appendix K are discussed in 
section XIV of this preamble. The EPA's full response to comments on 
the November 2021 Proposal and December 2022 Supplemental Proposal, 
including any comments not discussed in this preamble, can be found in 
the EPA's RTC document for the final rule.\629\
---------------------------------------------------------------------------

    \629\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

    In the December 2022 Supplemental Proposal, the EPA proposed a 95 
percent emission reduction performance standard for a number of 
affected/designated facilities, including centrifugal compressor, 
pneumatic pump, process controller, and tank battery affected/
designated facilities. This numeric standard reflects the emission 
reduction from capturing and routing the affected/designated facility's 
emissions through a CVS to a control device with a 95 percent control 
efficiency, which the EPA has identified as either the BSER or a 
control option for these affected/designated facilities. To ensure 
compliance with the 95 percent emission reduction standard when using a 
control device,\630\ the EPA proposed that the control device must 
reduce the emissions routed to the control device by 95 percent or 
greater.\631\ This would in turn require that covers and CVS be 
designed and operated to capture and route all emissions to the control 
device. To that end, the EPA proposed a NIE standard

[[Page 16985]]

for the covers and CVS associated with affected/designated facilities 
complying with the 95 percent emission reduction standard by routing 
emissions through a CVS to a control device.\632\ Therefore, compliance 
with the 95 percent emission reduction standard when using a control 
device would require compliance with both the control device standard 
and the NIE standard for the associated cover and CVS. To ensure 
compliance with the NIE standard (which in turn would ensure compliance 
with the 95 percent emission reduction standard), the EPA proposed that 
inspections of covers and closed vent systems (except when associated 
with gas plants) would be conducted using AVO and either OGI or EPA 
Method 21, at the same frequency as inspections conducted for fugitive 
emissions at well sites and compressor stations. For closed vent 
systems at gas plants, AVO inspections would be conducted annually and 
OGI inspections would be conducted bimonthly in accordance with 
appendix K (or alternatively, quarterly using EPA Method 21).
---------------------------------------------------------------------------

    \630\ The EPA cannot require the installation of any specific 
control device to meet performance standards that are in the form of 
numeric limitation, such as the 95 percent emission reduction 
standard. See CAA section 111(b)(5).
    \631\ See proposed 40 CFR 60.5412b(a)(1)(i) and 40 CFR 
60.5412c(a)(1)(i).
    \632\ See proposed 40 CFR 60.5411b(a)(3), 40 CFR 60.5416b(b), 40 
CFR 60.5411c(a)(3), and 40 CFR 5416c(b).
---------------------------------------------------------------------------

    As explained in the December 2022 Supplemental Proposal (87 FR 
74805), the EPA used the term NDE in the November 2021 Proposal to 
describe this design and operational requirement for CVS and covers; 
however, in light of comments that the term NDE is closely linked with 
EPA Method 21 and is defined based on an instrument reading in ppmv 
(the proposed OGI and AVO inspections would not result in an instrument 
reading in ppmv), the EPA proposed renaming the standard to NIE, which 
is more appropriate for the methods (i.e., OGI and AVO) required to 
demonstrate compliance. The EPA, however, emphasized that the NIE 
standard is an emission limitation, not a work practice standard, that 
any identified emissions would be a deviation of this emissions 
limitation, and that ``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 [now NIE] emission 
limit as quickly as possible.'' (Id.) Provided below is a summary of 
significant comments on this topic and the EPA's response thereto.
    Comment: Commenters \633\ had concerns both with the term NIE and 
with the EPA's position that the NIE standard is a numeric limit. One 
commenter \634\ contends that there is a major difference between the 
terms NDE and NIE for operators, because NDE recognizes that there will 
be unavoidable de minimis leaks (i.e., less than 500 ppmv) even in the 
best managed operations. Another commenter \635\ questioned the EPA's 
position that the NDE standard (the term used in the November 2021 
Proposal) always has been an emissions limit and that the detection of 
emissions above a certain threshold results in both a violation of the 
standard and an obligation to undertake a repair within a specified 
time period. The commenter explains that they are unaware of the EPA's 
ever taking this position.
---------------------------------------------------------------------------

    \633\ EPA-HQ-OAR-2021-0317-2202, -2227, -2248, -2326, -2391, -
2403, and -2428.
    \634\ EPA-HQ-OAR-2021-0317-2391.
    \635\ EPA-HQ-OAR-2021-0317-2202.
---------------------------------------------------------------------------

    Regarding the numeric limit of NIE, commenters \636\ stated that 
the reality of engineering a ``zero-emissions'' standard can never be 
perfectly achieved. One commenter \637\ pointed out that mechanical 
components and seals are prone to some de minimis level of leaking 
despite compliance with all other requirements, and because very small 
leaks are unavoidable and no LDAR program can prevent leaks 100 percent 
of the time, operators will not be able to comply with a NIE standard. 
Several commenters \638\ believed that a zero-emissions standard is not 
realistic for equipment located outside, because the equipment is 
subject to harsh conditions and undergoes continuous wear and tear, 
including intrusion of foreign objects preventing reseating of seal 
surfaces. Commenters believed emissions from such scenarios should not 
be an indication of inadequate CVS design. One of these commenters 
\639\ added that such leaks are not within the control of the operator, 
unlike the possibility of improperly operating a cover or CVS (e.g., 
forgetting to close a thief hatch), and asked that the EPA clearly 
differentiate leaks beyond the control of the operator from leaks 
within the control of the operator.
---------------------------------------------------------------------------

    \636\ EPA-HQ-OAR-2021-0317-2202, -2248, and -2326.
    \637\ EPA-HQ-OAR-2021-0317-2391.
    \638\ EPA-HQ-OAR-2021-0317-2248, -2403, and -2428.
    \639\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    These same commenters offered that because the components that make 
up covers and CVS are exposed to the elements just as other components 
included in the fugitives monitoring program, it makes sense to treat 
them the same way, by allowing LDAR work practice standards. These 
commenters also questioned why a leak in a CVS pipe is considered a 
violation, but a leak in a gas pipeline 10 feet away is not; the 
commenters believed that a leak should not be handled differently just 
because it occurs on a cover or CVS. From a practical standpoint, the 
commenters stated, leaks from these components have little to do with 
inadequate design or operation. One commenter \640\ explained that 
pressure and vacuum relief devices are present for safety reasons to 
prevent the tank from over-pressurization as wells as under-pressure 
(i.e., vacuum). The commenter noted that temperatures in North Dakota 
can vary 60 [deg]F or more in a 24-hour period. This variation causes 
the content of the tanks to expand and shrink, and without these 
control devices, the commenter contended, the tanks would fail. The 
commenter explained that the vacuum side for the pressure relief device 
is especially susceptible to sucking in dust and sometimes even bugs 
that prevent the device from sealing, but these are all taken care of 
as part of the LDAR program. Finally, the commenter noted that design 
issues, if any, will show up as repeat offenders in the LDAR program 
and will be corrected as part of that program.
---------------------------------------------------------------------------

    \640\ EPA-HQ-OAR-2021-0317-2248.
---------------------------------------------------------------------------

    Another commenter \641\ stated that the EPA does not provide 
anything in the rulemaking record that indicates any system capable of 
achieving a zero-emissions standard has been ``adequately 
demonstrated.'' The commenter contended that on its face, such a 
standard is therefore inconsistent with CAA section 111(a)'s plain 
terms and cannot be BSER. Similarly, another commenter \642\ stated 
that the EPA long ago rejected the idea that numeric emissions 
limitations can or should be applied to fugitive emissions components 
and that the EPA has presented no reason in the proposal to depart from 
its historical approach regarding fugitive emissions from CVS. To this 
end, the commenter maintained that an NIE or NDE standard cannot 
constitute a numeric emissions limitation, because BSER must be 
achievable. The commenter further stated that CAA section 111(h)(2) 
provides that a work practice standard should be prescribed in lieu of 
a standard of performance (i.e., numeric emissions limitation) when ``a 
pollutant or pollutants cannot be emitted through a conveyance designed 
and constructed to emit or capture such pollutant.'' The commenter 
contended that this is precisely the case with the EPA's proposed NIE 
standards because the NIE standards do not apply to emissions

[[Page 16986]]

from the storage vessel or equipment on which the CVS is installed. 
Rather, the proposed NIE standard applies to the CVS itself. In this 
case, the commenter maintained, it is obvious that there is no 
``conveyance'' through which the regulated pollutants would be emitted 
or captured. To accomplish such an outcome, the CVS to which the NIE 
standard applies would have to be enclosed within another CVS or 
similar permanent total enclosure for the regulated emissions to be 
captured for subsequent control or venting. According to the commenter, 
requiring such a system would be inordinately costly, highly 
impracticable, and likely impossible. The commenter pointed out that 
this is precisely why LDAR standards have been expressed from the 
inception of such programs almost exclusively as work practice 
standards. The commenter concluded that the NIE standard cannot be 
effectively construed as a zero-emissions standard, as the EPA 
proposes, because no ``conveyance'' exists that allows for capture of 
the regulated emissions and application of such a standard to an 
emissions point. The commenter stated that the EPA must make it clear 
that a CVS remains in compliance when a leak is detected, provided the 
associated work practices requiring investigation and repair are 
followed.
---------------------------------------------------------------------------

    \641\ EPA-HQ-OAR-2021-0317-2565.
    \642\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: As an initial matter, the EPA clarifies that CVS and 
covers subject to the NIE standards are not fugitive components or any 
other type of affected/designated facilities under NSPS OOOOb/EG OOOOc; 
rather, they are part of the emission control for an associated 
affected/designated facility (e.g., a wet seal centrifugal compressor, 
a pneumatic pump, process controllers, or a tank battery) that is using 
a control device to meet its performance standard. Accordingly, CAA 
section 111(h), which authorizes the EPA to prescribe work practice and 
other non-numeric standards for an affected/designated facility if it 
is not feasible to prescribe an emission limitation performance 
standard, does not apply to these covers and CVS.
    Second, as explained in the preamble to the December 2022 
Supplemental Proposal and reiterated above in this section, the NIE 
standard that applies to covers and closed vent systems is a numeric 
limitation to ensure that associated affected/designated facilities 
comply with the 95 percent emission reduction standard when using a 
control device. For example, the standard for a wet seal centrifugal 
compressor affected facility is to reduce emissions by 95 percent; if a 
control device is used, the owner or operator must equip the wet seal 
fluid degassing system with a cover that routes emissions through a 
closed vent system to a control device (see 40 CFR 60.5380b). Since the 
rule allows owners and operators to use a control device with 95 
percent control efficiency,\643\ compliance with the 95 percent 
emission reduction standard would require assurance (through 
demonstration) that all emissions are captured and routed via the CVS 
to the control device. The NIE standard reflects this compliance 
assurance and demonstration requirement and, for the reason explained 
above, is an emission limitation of zero emissions, to be demonstrated 
by OGI, EPA Method 21, or AVO inspection. Any identified emissions 
would be a deviation of the NIE standard and must be reported.\644\ In 
addition, the owner or operator must undertake the required 
``corrective actions'' (in the form of the repair provisions) to bring 
the CVS back into compliance with the NIE standard as quickly as 
possible to ensure that the associated affected/designated facility is 
in compliance with the 95 percent emission reduction standard.
---------------------------------------------------------------------------

    \643\ The EPA considered but declined to require the use of 
control devices with higher control efficiency in this rule. See 
discussion in section IV.H.2 of the November 2021 Proposal, 87 FR 
74794 (December 6, 2022).
    \644\ A deviation is defined as a failure to meet any obligation 
of the rule (including emission limits, operating limits, or work 
practice standards). See 40 CFR 60.5430b and 40 CFR 60.5430c.
---------------------------------------------------------------------------

    With respect to the comment that the ``zero-emissions'' NIE 
standard is not realistic for equipment located outside, the EPA notes 
that the requirement to operate the CVS or cover without emissions to 
the atmosphere has previously been required in NSPS OOOO and OOOOa, 
with compliance demonstrated by NDE. The EPA notes that the same 
requirement can be found in other NSPS (see, e.g., NSPS for Volatile 
Organic Liquid Storage Vessel, 40 CFR part 60, subpart Kb). CVS should 
be properly designed to minimize the possibility of leaks; for example, 
owners and operators should consider whether welded piping can be used 
in place of connectors, whether low emission equipment (such as valves) 
is appropriate for the CVS, which gaskets are most suitable for the 
composition of materials in the CVS, and whether pressure setpoints are 
appropriate for relief devices in the system. Owners and operators 
should regularly inspect and perform maintenance on the CVS to prevent 
equipment failure and subsequently prevent leaks from occurring.
    Because the term NDE has historically been associated only with the 
use of EPA Method 21, as we explained in the December 2022 Supplemental 
Proposal, the EPA believes the term ``no identifiable emissions'' is 
more suited for inspections conducted by OGI and AVO.\645\ Contrary to 
the commenter's assertion, the EPA does not believe the NIE standard 
using OGI is more stringent than the NDE standard using EPA Method 21. 
When using EPA Method 21, a leak is considered to not be detected if 
the monitoring instrument returns a reading below 500 ppmv (taking into 
account background concentration). Based on the EPA's experience with 
and understanding of OGI, while it is possible to detect leaks below 
500 ppmv with an OGI camera in a laboratory, it is highly unlikely that 
an OGI camera operator would be able to detect leaks below 500 ppmv in 
the conditions experienced in the field. As such, it is unlikely that 
owners and operators who conduct inspections of CVS and covers with OGI 
will regularly find leaks that would not have been required to be 
addressed had the owner or operator conducted the inspection with EPA 
Method 21. Further, where an owner or operator is concerned about the 
use of OGI for inspecting covers and CVS, the EPA is allowing EPA 
Method 21 as an alternative. Consistent with NSPS OOOO and OOOOa, 
emissions detected by AVO from covers and closed vent systems also are 
identifiable emissions. Regarding the comment that the detection of 
emissions above a certain threshold results in both a violation of the 
standard and an obligation to undertake a repair within a specified 
time period, the EPA believes that the repair obligations are necessary 
to ensure that the CVS or cover is returned to a condition of NIE as 
quickly as possible, which serves to limit deviations from the standard 
for the affected/designated facility that uses the CVS. The EPA 
recognizes that situations beyond the control of the owner or operator 
may occur, but the emission standard applies at all times.
---------------------------------------------------------------------------

    \645\ 87 FR 74805 (December 6, 2022).
---------------------------------------------------------------------------

L. Equipment Leaks at Natural Gas Processing Plants

    In section X.L of this document, the final NSPS OOOOb and EG OOOOc 
requirements for equipment leaks at natural gas processing plants are 
summarized. The BSER analyses for leaks from both new and existing 
process unit equipment at natural gas processing plants are unchanged 
from what was presented in the November 2021 Proposal (see 86 FR 63231-
33, section XII.G: Proposed Standards for Equipment Leaks at Natural 
Gas

[[Page 16987]]

Processing Plants). Specifically, the EPA identified a bimonthly OGI 
LDAR program following appendix K that includes all equipment 
components that have the potential to emit VOC or methane to be BSER 
for both new and existing process unit equipment at natural gas 
processing plants. However, significant comments were received on the 
December 2022 Supplemental Proposal on the following topics: potential 
to emit methane and VOC; and the use of low-E equipment for repair. For 
each of these topics, a summary of the proposed rule, the comments, the 
EPA responses, and changes made in the final rule (if applicable), are 
discussed here. These comments and the EPA's responses to these 
comments generally apply to both NSPS OOOOb and EG OOOOc. The instances 
where the comment and/or response only applies to NSPS OOOOb or EG 
OOOOc are noted. Comments and changes relevant to appendix K are 
discussed in section XIV of this preamble. The EPA's full response to 
comments on the November 2021 Proposal and December 2022 Supplemental 
Proposal, including any comments not discussed in this preamble, can be 
found in the EPA's RTC document for the final rule.\646\
---------------------------------------------------------------------------

    \646\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

1. Potential To Emit Methane and VOC
    In the November 2021 Proposal (86 FR 63181), the EPA proposed not 
to carry over to NSPS OOOOb the VOC concentration threshold in NSPS 
OOOOa that excludes certain equipment within a process unit from the 
LDAR requirements at natural gas processing plants. In NSPS OOOOa, 
while the affected facility included equipment that is in contact with 
a process fluid containing methane or VOCs, the standards only applied 
to equipment ``in VOC service,'' which ``means the piece of equipment 
contains or contacts a process fluid that is at least 10 percent VOC by 
weight.'' The EPA explained in the November 2021 Proposal that because 
a VOC concentration threshold has no relationship to the LDAR for 
methane, it is not an appropriate threshold for determining whether 
LDAR for methane applies. Further, the EPA explained that because there 
was no threshold for requiring LDAR for methane, any equipment not ``in 
VOC service'' still would be required to conduct LDAR for methane, even 
if not for VOC, which made the VOC concentration threshold irrelevant.
    In December 2022, the EPA proposed to apply the LDAR standards to 
process unit equipment that has the potential to emit methane or VOC, 
consistent with the November 2021 Proposal. The EPA also added 
provisions that each piece of equipment is presumed to emit methane or 
VOC unless the owner or operator demonstrates that the piece of 
equipment does not have the potential to emit methane or VOC. The EPA 
provided regulatory provisions for the demonstration, namely, that the 
owner or operator would have to show that the process fluid did not 
contain either methane or VOC.
    Comment: Commenters \647\ on the November 2021 Proposal requested 
that the EPA retain the ``in VOC service'' requirement and 10 percent 
VOC by weight threshold, as well as establish a 1 percent threshold for 
equipment in methane service. The commenters reiterated concerns 
expressed in response to the November 2021 Proposal that some streams, 
such acid and amine gas, ethane product streams, produced water 
streams, and wastewater streams should be excluded and that a 1 percent 
by weight methane concentration threshold would serve to exclude such 
streams. Otherwise, both commenters expressed concern that owners and 
operators would waste substantial resources to conduct LDAR monitoring 
on components that will always result in non-detects.
---------------------------------------------------------------------------

    \647\ EPA-HQ-OAR-2021-0317-2399 and -2428.
---------------------------------------------------------------------------

    One of the commenters \648\ questioned the EPA's analysis in the 
November 2021 Proposal. The commenter states that the EPA appears to 
only consider components in VOC service (defined as defined as 10 
percent by VOC by weight or in wet gas service) or in non-VOC service 
(defined as a component in methane service with at least 10 percent 
methane that is not also in VOC service). The commenter states that the 
EPA then estimates VOC and methane emissions, reductions, and cost 
effectiveness using a limited set of composition ratios,\649\ then 
appears to treat the ``potential to emit methane'' as equivalent to 
``in non-VOC service'' in evaluating control options. Therefore, the 
commenter states, the EPA does not appear to fully consider the cost 
effectiveness of a ``potential to emit'' applicability threshold.
---------------------------------------------------------------------------

    \648\ EPA-HQ-OAR-2021-0317-2428.
    \649\ The commenter (-2428) refers to Table 10-8 of the TSD. See 
EPA-HQ-OAR-2021-0317-0166.
---------------------------------------------------------------------------

    Response: The EPA is not including a VOC or methane threshold in 
the final rule. In response to these comments, the EPA explained in the 
December 2022 Supplemental Proposal that ``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'' (87 FR 74808). In addition, 
no basis is provided for how removing ``in VOC service'' would 
substantially increase costs.
2. Low-E Technology for Repair
    In the November 2021 Proposal, the EPA proposed repair requirements 
for leaking equipment. The EPA proposed that the definition of 
``repaired'' (for equipment) is that the equipment is adjusted, 
replaced, or otherwise altered, in order to eliminate equipment leaks 
and that the equipment is re-monitored to verify that emissions from 
the equipment are below the leak definition. The EPA explained that 
valve repairs can include replacement with low-emissions (low-E) 
valves, valve packing, or drill-and-tap with a low-E injectable (``low-
E equipment'') but did not require replacement with low-E equipment. 
The EPA explained that low-E equipment meets the specifications of API 
622 or API 624 and typically includes a manufacturer written warranty 
or a performance guarantee that it will not emit fugitive emissions at 
a concentration greater than 100 ppmv during the first 5 years. 86 FR 
63182.
    In the December 2022 Supplemental Proposal, the EPA proposed a 
definition of ``repaired'' (for equipment) consistent with that 
discussed in the November 2021 Proposal, and added that pumps subject 
to weekly visual inspections, which are designated as leaking and then 
repaired, are not subject to re-monitoring. The EPA did not propose to 
require the replacement of leaking valves with low-E equipment, noting 
that the technology is not appropriate for all repairs, but reiterated 
the position from the November 2021 Proposal that due to the 
performance expectations, low-E equipment can be a viable option for 
valve repair, as demonstrated by the re-monitoring requirements of the 
rule. 87 FR 74808.
    Comment: Commenters \650\ urged the EPA to require replacement of 
leaking equipment with low-E valves. The commenter cited to a recent 
rulemaking, where Colorado found these options to be similar in cost to 
non-low-E valves and packing and directed operators to

[[Page 16988]]

consider them.\651\ The commenter also referenced claims from some 
manufacturers that their low-E packing can reduce emissions of harmful 
gases by up to 95 percent versus valves with traditional packing, with 
minimal cost impacts.\652\
---------------------------------------------------------------------------

    \650\ EPA-HQ-OAR-2021-0317-2433.
    \651\ See Colorado Air Pollution Control Division, Rebuttal 
Prehearing Statement, Proposed Revisions to Regulation Numbers 7 and 
22 (Dec. 14-17, 2021).
    \652\ Id.
---------------------------------------------------------------------------

    Response: The commenter's understanding of the cost for low-E 
equipment aligns with that of the EPA in that they are similar in cost 
to non-low-E equipment. Therefore, replacing leaking valves with low-E 
equipment would result in lower emissions with no additional cost 
burden (compared to using non-low-E equipment). However, as explained 
in the two proposals and reiterated above, the EPA believes that the 
low-E technology is not appropriate for all valve repairs, and the EPA 
did not receive comments disagreeing or suggesting otherwise. 
Therefore, the final NSPS OOOOb and the presumptive standard in EG 
OOOOc require replacing leaking valves with low-E valves or repacking 
existing valves with low-E packing, except where it is not technically 
feasible. If delay of repair is required to repack or replace the 
valve, you may use delay of repair provisionally, but no later than the 
next process unit shutdown. Technical infeasibility includes situations 
where low-E equipment is not suitable for the existing valves' intended 
use. Other factors that may be considered in determining technical 
infeasibility include: retrofit requirements for installation (e.g., 
re-piping or space limitation), commercial unavailability for valve 
type, or certain instrumentation assemblies. Owners or operators are 
required to report annually on instances where it was infeasible to 
replace leaking valves with low-E valves or repack existing valves with 
low-E packing technology, including the reasoning for why it was 
infeasible.

M. Sweetening Units

    In section X.M of this document the final NSPS OOOOb requirements 
for sweetening units are summarized. In November 2021 and December 
2022, the EPA proposed to retain the standards found in NSPS OOOO and 
NSPS OOOOa for reducing SO<INF>2</INF> emissions from sweetening units. 
No comments were received in opposition to the December 2022 
Supplemental Proposal and the standards are being finalized as 
proposed.

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

    As described in sections IV and VIII of the November 2021 Proposal 
(86 FR 63133-37, 63147-53), the 2020 Policy Rule rescinded all NSPS 
regulating emissions of VOC and methane from sources in the natural gas 
transmission and storage segment of the oil and natural gas industry 
and NSPS regulating methane from sources in the industry's production 
and processing segments. As a result, the 2020 Technical Rule only 
amended the VOC standards for the production and processing segments in 
the 2016 NSPS OOOOa, because those were the only standards that 
remained at the time that the 2020 Technical Rule was finalized.
    Under the CRA, a rule that is subject to a joint resolution of 
disapproval ``shall be treated as though such rule had never taken 
effect.'' 5 U.S.C. 801(f)(2). Thus, because it was disapproved under 
the CRA, the 2020 Policy Rule is treated as never having taken effect. 
As a result, the requirements in the 2012 NSPS OOOO and 2016 NSPS OOOOa 
that the 2020 Policy Rule repealed (i.e., the VOC and methane standards 
for the transmission and storage segment, as well as the methane 
standards for the production and processing segments) must be treated 
as being in effect immediately upon enactment of the joint resolution 
on June 30, 2021. The CRA resolution did not address the 2020 Technical 
Rule; therefore, the amendments made in the 2020 Technical Rule, which 
apply only to the VOC standards for the production and processing 
segments in the 2016 NSPS OOOOa, have remained in effect. As a result, 
sources in the production and processing segments have been subject to 
two different sets of standards: One for methane based on the 2016 NSPS 
OOOOa, and one for VOC that include the amendments to the 2016 NSPS 
OOOOa made in the 2020 Technical Rule. Low production well sites, for 
example, are now subject to semiannual methane leak detection and 
repair requirements under the 2016 NSPS even while they continue to be 
exempt from leak detection and repair for VOC emissions under the 2020 
Technical Rule. Such affected facilities have been able to either 
choose to comply with both sets of standards, which in most cases do 
not conflict, or to comply with the more stringent standards, which are 
those in the 2016 NSPS for methane. In this case, compliance with the 
more stringent 2016 NSPS for methane also results in compliance with 
the 2020 Technical Rule. Sources in the transmission and storage 
segment are subject to the methane and VOC standards as promulgated in 
either the 2012 NSPS OOOO or the 2016 NSPS OOOOa, as applicable. In 
this rulemaking, the EPA updated the NSPS OOOO and NSPS OOOOa 
regulatory text in the CFR to reflect the CRA resolution's disapproval 
of the final 2020 Policy Rule, specifically, the reinstatement of the 
NSPS OOOO and NSPS OOOOa requirements that the 2020 Policy Rule 
repealed but that came back into effect immediately upon enactment of 
the CRA resolution. The proposed regulatory text changes for NSPS OOOO 
and NSPS OOOOa to reflect the CRA resolution were included in the 
rulemaking docket when the EPA issued the November 2021 Proposal and 
are being finalized as proposed.
    In addition to aligning the NSPS OOOO and NSPS OOOOa regulatory 
text in the CFR to reflect the CRA resolution's disapproval of the 
final 2020 Policy Rule, the November 2021 Proposal (at 86 FR 63157-69, 
November 15, 2021) also included a series of proposed amendments to 
2016 NSPS OOOOa for methane to align the 2016 methane standards with 
the current VOC standards (which were modified by the 2020 Technical 
Rule). Those amendments included requirements for well completions, 
pneumatic pumps, closed vent systems, fugitive emissions, AMEL, and 
onshore natural gas processing plants, along with other technical 
clarifications and corrections. The November 2021 Proposal preamble 
described the supporting rationales that were provided in the 2020 
Technical Rule for modifying the requirements applicable to the VOC 
standards and explained why the amendments would also appropriately 
apply to the reinstated methane standards. Most commenters on the 
November 2021 Proposal provided general support for the retention of 
certain aspects of the 2020 Technical Rule, including the corresponding 
regulatory amendments to NSPS OOOOa. No significant comments were 
received in opposition to these proposed regulatory amendments, and 
they are being finalized as proposed.
    Also, in the November 2021 Proposal, the EPA proposed to repeal 
some of the amendments that were part of the 2020 Technical Rule. 
Specifically, the EPA proposed to repeal its amendments in the 2020 
Technical Rule that (1) exempted low production well sites from 
monitoring fugitive emissions and (2) changed quarterly monitoring to 
semiannual monitoring of VOC emissions at gathering and boosting

[[Page 16989]]

compressor stations. The EPA is finalizing the repeal of these 
amendments and subsections XII.A and B of this document discuss the 
comments received on the rescission of these proposed amendments and 
the EPA's response to those comments.
    In addition to the November 2021 proposed amendments, commenters 
also requested changes to NSPS OOOOa that were also recommended to be 
made to NSPS OOOOb and EG OOOOc. These changes include allowing for 
delay of repair for when equipment necessary for repair is unavailable 
and clarifying the source category scope of the rule (e.g., excludes 
facilities located inside and including the Local Distribution Company 
(LDC) custody transfer station). The EPA is making changes based on 
these comments in the final rule. Specifically, the EPA has revised 40 
CFR 60.5397a(h)(3) to allow for a delay of repair due to the lack of 
availability of parts in some circumstances and has revised the 
introductory language at 40 CFR 60.5365a of the final rule to clarify 
that the Crude Oil and Natural Gas Production source category excludes 
facilities located inside and including the LDC custody transfer 
station. Section XII.C discusses the comments received and the EPA's 
response to comments related to delay of repair, and section XII.D 
discusses the comments received and the EPA's response to comments on 
the need to clarify the source category scope of the rule. The EPA's 
full response to comments on the November 2021 Proposal and December 
2022 Supplemental Proposal, including any comments not discussed in 
this preamble, can be found in the EPA's RTC document for the final 
rule.\653\
---------------------------------------------------------------------------

    \653\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

A. Low Production Well Site Exemption Rescission

    The EPA proposed (86 FR 63158-59) to remove the exemption of low 
production well sites from fugitive VOC emissions monitoring, thereby 
restoring the semiannual monitoring requirement established in the 2016 
NSPS OOOOa.
    Comment: Several commenters \654\ objected to the proposal to 
repeal the amendments in the 2020 Technical Rule that exempted low 
production well sites from monitoring fugitive VOC emissions under the 
NSPS (86 FR 63118). These commenters urged the EPA to retain the 
exemption, citing concerns about the cost impacts of removing the 
exemption as well as objections to the EPA's emissions baseline 
analysis.
---------------------------------------------------------------------------

    \654\ EPA-HQ-OAR-2021-0317-0577, -0803, -0824, and -0464.
---------------------------------------------------------------------------

    Commenters \655\ stated that the repeal of the exemption for low 
production well sites from monitoring fugitive emissions would result 
in adverse impacts to owners and operators, especially owners and 
operators of small-scale, independent well site operations. One of the 
commenters stated that the repeals of the exemption for low production 
well sites from monitoring fugitive emissions would affect many 
stripper wells in Wyoming (defined by the Wyoming Oil and Gas 
Conservation Commission (WOGCC) as wells that produce an average of 15 
barrels of crude oil (bbl) or less per day) and some very small-scale, 
independent well site operations that strictly operate on a single 
owner's private property. According to the WOGCC, Wyoming has 
approximately 6,524 stripper wells. The commenter is concerned about 
the potential adverse economic impacts of these proposed regulations 
upon individual operators and the greater economy of the state of 
Wyoming and states that the economic impacts outweigh the indeterminate 
and potentially marginal environmental benefits of the proposal. The 
commenter added that the cost of compliance with these requirements is 
simply unworkable for many smaller operators in Wyoming and some 
operators have already expressed concerns to WDEQ that they will go out 
of business due to the EPA's proposed requirements. The other commenter 
stated that the removal of the low production well exemption would have 
significant detrimental impacts on their operations, costs, overhead, 
reserve recovery, plugging costs, and employment. The commenter noted 
that every increase in cost directly jeopardizes their ability to 
produce marginal wells.
---------------------------------------------------------------------------

    \655\ EPA-HQ-OAR-2021-0317-0464 and -0824.
---------------------------------------------------------------------------

    One commenter \656\ suggested that removing the exemption for low-
producing wells from fugitive emissions monitoring in NSPS OOOOa could 
result in tens of thousands of additional affected facilities and/or 
projects establishing PTE below affected source emissions levels. The 
commenter added that changing this requirement may also result in some 
facilities becoming an affected facility retroactively.
---------------------------------------------------------------------------

    \656\ EPA-HQ-OAR-2021-0317-0763.
---------------------------------------------------------------------------

    Another commenter \657\ recommended that the EPA consider the 
small, low-emitting nature of Pennsylvania and New York conventional 
oil and gas production before imposing any additional requirements in 
the NSPS OOOOa (and NSPS OOOOb and EG OOOOc) revisions.
---------------------------------------------------------------------------

    \657\ EPA-HQ-OAR-2021-0317-1341.
---------------------------------------------------------------------------

    A couple of commenters \658\ also requested that the EPA more 
thoroughly evaluate emissions and costs of control of marginal/low 
production well sites. One of the commenters requested that the EPA 
first determine if marginal well emissions warrant regulation. The 
commenter noted that the DOE was conducting a study to better 
characterize emissions from these types of wells. The commenter stated 
that E.O. 13990 requires the Federal Government, ``. . . be guided by 
the best science and be protected by processes that ensure the 
integrity of Federal decision-making.'' As such, the commenter 
recommended that the EPA defer regulating marginal/low production wells 
until the DOE report was available for review or collect additional 
data to fully determine the emissions profile of these types of wells, 
determine if requirements are needed, and if needed, develop an 
appropriate regulatory program. Similarly, the other commenter 
suggested that they are aware of at least one study underway to 
evaluate methane emissions from marginal wells, and that there may be 
others. The commenter contends that, if the study's findings 
demonstrate that these methane emissions contributions from low 
production well sites do not contribute in any significant manner, the 
commenter expressed that it is imperative that the EPA consider these 
findings and provide appropriate exemptions.
---------------------------------------------------------------------------

    \658\ EPA-HQ-OAR-2021-0317-0810 and -0824.
---------------------------------------------------------------------------

    One commenter \659\ stated that marginal wells are not a 
significant source of methane and that emissions from a well are 
proportionate to the volume of oil and/or gas produced. As a result, 
the commenter stated that marginal wells produce significantly fewer 
emissions because they are marginal producers of oil and gas. According 
to the commenter, emissions from their wells are much lower than those 
emitted from high volume wells produced by larger companies. The 
commenter expressed that it is unfair and unwise to treat small 
operators with marginal wells in the same manner as larger producers. 
The commenter suggested that marginally producing wells be exempt from 
the EPA rules because the emissions are insignificant, and the rules 
would be uneconomic. The commenter further requested that

[[Page 16990]]

there be a regulatory ``off ramp'' for low-producing wells such as 
theirs.
---------------------------------------------------------------------------

    \659\ EPA-HQ-OAR-2021-0317-0464.
---------------------------------------------------------------------------

    Response: As discussed in the December 2022 Supplemental Proposal, 
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. The EPA examined data provided through an 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 expressing that 
emissions from a well are proportionate to the volume of oil and/or gas 
produced.\660\ Commenters also referenced the U.S. DOE marginal well 
study. However, the U.S. DOE marginal well study (now available) 
concludes that the frequency and magnitude of emissions from well sites 
are more strongly correlated with equipment counts, not production 
rates.\661\ 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 lowest-producing sites (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 
(defined in that study as 15 boe/day or less production 
rates).<SUP>662 663</SUP> However, the EPA notes that this study is not 
limited to fugitive emissions, and the overall impacts on emissions 
reductions achieved under NSPS OOOOa (and NSPS OOOOb and EG OOOOc) 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.
---------------------------------------------------------------------------

    \660\ See Document ID No. EPA-HQ-OAR-2021-0317-0464.
    \661\ 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. https://www.osti.gov/biblio/1865859. page 19.
    \662\ 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.
    \663\ 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.
---------------------------------------------------------------------------

    As stated in the November 2021 Proposal, the EPA remains mindful 
about how the fugitive emissions monitoring requirements will affect 
small businesses. The EPA discusses the financial conditions of 
marginal wells in chapter 6 of the final rule TSD. There are many 
factors that might affect the profitability of marginal wells and the 
decision to shut in and plug a well, making it difficult to determine 
the full impact of regulation on the financial status of marginal well 
owners. The EPA has also taken steps to include regulatory flexibility 
and streamline recordkeeping requirements in the fugitive emissions 
standards of NSPS OOOOa.
    The EPA is therefore finalizing the proposed (86 FR 63158-59) 
removal of the exemption of low production well sites from fugitive VOC 
emissions monitoring, thereby restoring the semiannual monitoring 
requirement established in the 2016 NSPS OOOOa.

B. Compressor Station Quarterly Monitoring

    The EPA proposed to repeal its amendment to the VOC monitoring 
frequency for gathering and boosting compressor stations in the 2020 
Technical Rule because the EPA believed that amendment was made in 
error. 86 FR 63159
    Comment: Some commenters \664\ expressed opposition to the proposal 
and requested that fugitive emissions monitoring at compressor stations 
only be required on a semiannual basis. One commenter contended that a 
requirement for more frequent monitoring would be unduly burdensome, 
given that one pipeline system could have numerous compressor stations 
that are often located in remote areas. In addition, the commenter 
stated that the resources (both personnel and equipment) to comply with 
survey requirements may be limited, a concern that the commenter says 
that the EPA itself acknowledged in the preamble for the initial NSPS 
OOOOa Proposal. Moreover, the commenter stated that the leak rate in 
the gathering and boosting industry segment is particularly low. The 
commenter urged the EPA to retain the current requirement of semiannual 
monitoring for fugitive emissions at compressor stations, including 
gathering and boosting compressor stations. Similarly, another 
commenter suggested that it is overly burdensome to require quarterly 
compressor monitoring in respect to surveys and recordkeeping. The 
commenter noted that the value of increased monitoring to reduce small 
amounts of methane and VOC does not offset the associated expense and 
manpower required to fulfill the proposed regulations. The commenter 
suggested that a baseline for compressor stations could be undertaken 
as a similar proposal for less than 3 tpy well sites to determine 
future requirements of a particular site.
---------------------------------------------------------------------------

    \664\ EPA-HQ-OAR-2021-0317-0755 and -0923.
---------------------------------------------------------------------------

    Another commenter \665\ also suggested that changing the monitoring 
frequency for the transmission and storage segments from semiannual to 
quarterly creates confusion with the other actions taken in 2021 
regarding NSPS OOOOa as these facilities have transferred back and 
forth between affected facility status due to policy changes within the 
existing NSPS OOOOa.
---------------------------------------------------------------------------

    \665\ EPA-HQ-OAR-2021-0317-0763.
---------------------------------------------------------------------------

    Response: As stated in the December 2022 Supplemental Proposal, the 
analyses the EPA conducted for NSPS OOOOb and EG OOOOc confirm that 
quarterly monitoring remains both achievable and cost-effective for 
compressor stations, and several state agencies have rules that require 
quarterly monitoring at compressor stations. The cost analysis 
conducted for the November 2021 Proposal was a comprehensive evaluation 
of emissions, reductions, and costs associated with various leak 
detection and repair programs, which firmly established that the cost 
effectiveness of quarterly monitoring for compressor stations is

[[Page 16991]]

reasonable. The November 2021 Proposal established that BSER for 
reducing methane and VOC emissions from all compressor stations, 
including gathering and boosting stations, transmission stations, and 
storage stations was quarterly monitoring. In the December 2022 
Supplemental Proposal, the EPA retained the proposed quarterly OGI (or 
EPA Method 21) monitoring requirement for fugitive emissions components 
affected facilities located at compressor stations. Although some 
commenters oppose quarterly monitoring, they express no disagreement 
with EPA's BSER analysis; rather, they find quarterly monitoring 
unnecessarily burdensome or may cause confusion after allowing semi-
annual monitoring in the 2020 amendment, none of which are reasons for 
the EPA not to restore the monitoring frequency that reflects the BSER. 
Therefore, based on the reasoning provided in the November 2021 
Proposal that the EPA lacked justification and erred in revising the 
VOC monitoring frequency for gathering and boosting compressor stations 
from quarterly to semiannual and that the cost effectiveness of 
quarterly monitoring for compressor stations is reasonable, the EPA is 
finalizing the restoration of the quarterly monitoring requirement for 
gathering and boosting compressor stations, as established in the 2016 
NSPS OOOOa.

C. Delay-of-Repair Provisions

    Comment: Some commenters requested changes to NSPS OOOOa that were 
also recommended to be made to NSPS OOOOb and EG OOOOc. One of those 
requested changes was to allow for a delay of repair when parts are 
unavailable to do the required repairs. One commenter \666\ supported 
reconciling NSPS OOOOa delay-of-repair regulatory text consistent with 
the 2020 Technical Rule. However, the commenter also recommended that 
the delay-of-repair text be amended to address the delay necessary when 
parts are unavailable, an issue that they believe is especially 
important for existing sources. The comments summarized in section 
XI.A.2.b were generally intended for NSPS OOOOa as well as NSPS OOOOb 
and EG OOOOc.
---------------------------------------------------------------------------

    \666\ EPA-HQ-OAR-2021-0317-0782.
---------------------------------------------------------------------------

    Response: Based on these comments, the EPA is amending 40 CFR 
60.5397a(h)(3) to allow the delay of repairs due to the lack of 
availability of parts with provisions identical to those of NSPS OOOOb 
and EG OOOOc. NSPS OOOOa has been revised to allow for delay of repair 
due to unavailability of parts if replacement parts are necessary and 
cannot be acquired within the repair timeline if either replacement 
part supplies had been sufficiently stocked before the supplies were 
depleted or a replacement part requires custom fabrication. Replacement 
parts must be ordered within 10 calendar days after the first attempt 
at repair. The repair must be completed within 30 calendar days after 
receipt of the replacement parts or during the next scheduled shutdown 
for maintenance after the parts are received (if the repair requires a 
shutdown). As the EPA was considering provisions allowing for delay of 
repair due to parts unavailability for sources regulated under NSPS 
OOOOb and EG OOOOc, the EPA found that the supplemental information 
submitted and reasoning for allowing delay of repair due to parts 
unavailability under NSPS OOOOb and EG OOOOc is equally applicable to 
sources regulated under NSPS OOOOa and, for that reason, is also 
including the provision in 40 CFR 60.5397a(h)(3).

D. Applicability/Scope of the Rule

    Comment: As noted above, some commenters requested changes to NSPS 
OOOOa that were also recommended to be made to NSPS OOOOb and EG OOOOc. 
One of those requested changes was to add greater clarity regarding the 
applicability/scope of the rule.
    One commenter \667\ stated that because their members are small 
without access to significant resources to fully analyze complex 
rulemakings, it is important that the scope of the rule be made as 
clear as possible. The commenter requested that the EPA include the 
following underlined text in NSPS OOOOa at 40 CFR 60.5365a and in 
appropriate, corresponding sections of NSPS OOOOb and EG OOOOc 
(underlined text reflects their recommended additions):
---------------------------------------------------------------------------

    \667\ EPA-HQ-OAR-2021-0317-0928.
---------------------------------------------------------------------------

Sec.  60.5365a Am I subject to this subpart?
    You are subject to the applicable provisions of this subpart if 
you are the owner or operator of one or more of the onshore affected 
facilities listed in paragraphs (a) through (j) of this section, 
that is located within the Crude Oil and Natural Gas Production 
source category, as defined in Sec.  60.5430, for which you commence 
construction, modification, or reconstruction.

    Similarly, another commenter \668\ stated that a small gas utility 
or cooperative that does not have an environmental lawyer on staff may 
not understand that the rule applies only to facilities that are 
located within the Crude Oil and Natural Gas Production source category 
as defined in 40 CFR 60.5430a, and that they need to refer to the 
definitions section toward the end of the rule to discover that the 
source category does not include operations inside and including the 
LDC custody transfer station, and that the subpart only applies to 
facilities in the defined source category. The commenter stated that 
clarifying language was added to 40 CFR 60.5365a in the 2020 Policy 
Rule.\669\ At a minimum, the commenter suggested that similar language 
be restored in NSPS OOOOa and included in the new scope provisions of 
NSPS OOOOb and EG OOOOc to clarify that facilities inside and including 
the LDC custody transfer station are not subject to the subpart. The 
commenter urged the EPA to include the following text in 40 CFR 
60.5365a and in the analogous scope sections of NSPS OOOOb and EG 
OOOOc:
---------------------------------------------------------------------------

    \668\ EPA-HQ-OAR-2021-0317-0815.
    \669\ 85 FR 57029-30, September 14, 2020.

    You are subject to the applicable provisions of this subpart if 
you are the owner or operator of one or more of the onshore affected 
facilities listed in paragraphs (a) through (j) of this section, 
that is located within the Crude Oil and Natural Gas Production 
source category, as defined in Sec.  60.5430a. Facilities located 
inside and including the LDC custody transfer station are not 
---------------------------------------------------------------------------
subject to this subpart.

    Response: The EPA considered the comments provided and agrees that, 
while the definitions section clearly defines the boundaries of the 
source category, additional clarification in the applicability section 
of the subpart, with respect to LDC custody transfer, would further 
assist sources in identifying whether they are subject to any of the 
requirements in NSPS OOOOa. Therefore, the final rule includes the 
following introductory language at 40 CFR 60.5365a:

    You are subject to the applicable provisions of this subpart if 
you are the owner or operator of one or more of the onshore affected 
facilities listed in paragraphs (a) through (j) of this section, 
that is located within the Crude Oil and Natural Gas Production 
source category, as defined in Sec.  60.5430a, for which you 
commence construction, modification, or reconstruction after 
September 18, 2015, and on or before December 6, 2022. Facilities 
located inside and including the Local Distribution Company (LDC) 
custody transfer station are not subject to this subpart.

[[Page 16992]]

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

A. Overview

    In the December 2022 Supplemental Proposal, the EPA proposed 
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 of this preamble, in 
the same six-part organizational ordering as the December 2022 
Supplemental Proposal, we summarize significant comments and changes 
since the December 2022 Supplemental Proposal for purposes of the final 
EG. We also discuss the interaction of these final EG with recently 
finalized revisions to the CAA section 111(d) implementing regulations, 
40 CFR part 60 subpart Ba (subpart Ba).\670\ The EPA proposed these EG 
in accordance with the version of subpart Ba that existed at the time 
of proposal. However, since the recent revisions to subpart Ba are now 
final and are therefore applicable to these EG, the final version of 
these EG comports with the revised version of subpart Ba. Further, 
states developing plans in accordance with EG OOOOc must follow the 
recently revised version of subpart Ba, except where these EG expressly 
supersede the requirements of subpart Ba. The EPA discusses the 
importance of these changes in more detail later in this preamble.
---------------------------------------------------------------------------

    \670\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------

    First, we discuss components of the final EG. Second, we discuss 
the requirements for establishing standards of performance in state 
plans. Third, we discuss the components of an approvable state plan 
submission. Fourth, we discuss the final timing for state plan 
submissions, and final timeline for designated facilities to come into 
final compliance with the state plan. Fifth, we discuss the EPA's 
action on state plans and the promulgation of Federal Plans. Sixth, we 
discuss Tribes and the planning process for Tribal plans under CAA 
section 111(d).

B. Components of EG

    As explained in the November 2021 Proposal, CAA sections 111(d)(1) 
and 111(a)(1) collectively establish and define certain roles and 
responsibilities for the EPA and the states. The EPA addresses its 
responsibilities by drafting and publishing EG in accordance with 40 
CFR 60.22a, which ``[contain] information pertinent to control of the 
designated pollutant from designated facilities.'' Mirroring language 
included in CAA section 111(d)(1), the EPA's implementing regulations 
define a designated pollutant as ``any air pollutant, the emissions of 
which are subject to a standard of performance for new stationary 
sources, but for which air quality criteria have not been issued and 
that is not included on a list published under section 108(a) or 
section 112(b)(1)(A) of the Act.'' 40 CFR 60.21a(a). The EPA's 
implementing regulations also define a designated facility as ``any 
existing facility (see Sec.  60.2) which emits a designated pollutant, 
and which would be subject to a standard of performance for that 
pollutant if the existing facility were an affected facility (see Sec.  
60.2).'' Id. at Sec.  60.21a(b). The designated pollutant for purposes 
of the final EG OOOOc included in this rulemaking is GHGs, but the 
presumptive standards in the EG are expressed in terms of limitations 
on methane. A description of each of the designated facilities included 
in the final EG OOOOc can be found in sections X and XI of this 
preamble.
    More specifically, 40 CFR 60.22a(b) lists six components to be 
included in EG to provide information for development of the state 
plans triggered by the promulgation of the EG. Within the November 2021 
Proposal, the EPA explained how the proposed EG OOOOc satisfied these 
regulatory requirements. 86 FR 63110, 63248-49 (November 15, 2021). 
Within the December 2022 Supplemental Proposal, the EPA elaborated on 
several of these components. 87 FR 74702, 74816 and 74834 (December 6, 
2022). The recent revisions to subpart Ba did not alter 60.22a(b) in 
any meaningful way, so the analysis provided in the proposals remains 
relevant and satisfactory. In addition, the EPA has included 
information in this final rulemaking action that updates and 
supplements that analysis. First, the EG must include information 
regarding the ``endangerment of public health or welfare caused, or 
contributed to, by the designated pollutant.'' 40 CFR 60.22a(b)(1). 
Information on the harmful public health and welfare impacts of GHG 
(methane) emissions from the oil and natural gas industry were included 
in the November 2021 Proposal \671\ and are updated above in section 
III of this document. Second, the EG must include a ``description of 
systems of emission reduction which, in the judgment of the 
Administrator, have been adequately demonstrated.'' 40 CFR 
60.22a(b)(2). The EPA has included such a description in the November 
2021 Proposal,\672\ in the November 2021 TSD,\673\ in the December 2022 
Supplemental Proposal,\674\ in the December 2022 TSD,\675\ in sections 
X and XI of this preamble, and in the final TSD located at Docket ID 
No. EPA-HQ-OAR-2021-0317. Third, the EG must include information 
regarding ``the degree of emission limitation'' achievable through 
application of each system, along with information ``on the costs, 
nonair quality health and environmental effects, and energy 
requirements of applying each system to designated facilities.'' Id. at 
60.22a(b)(3). The EPA has included such a description in the November 
2021 Proposal,\676\ in the November 2021 TSD,\677\ in the December 2022 
Supplemental Proposal,\678\ in the December 2022 TSD,\679\ in sections 
X and XI of this preamble, and in the final TSD located at Docket ID 
No. EPA-HQ-OAR-2021-0317. Fourth, the EG must include information 
regarding the amount of time that the EPA believes would be normally 
necessary for designated facilities to design, install, and startup the 
control systems identified in component number three. See Id. at 
60.22a(b)(4). The EPA proposed how to address this component in both 
the November 2021 Proposal and the December 2022 Supplemental Proposal 
and finalizes its explanation of how to address this component in 
section XIII.E of this document. Fifth, and likely most helpful to 
states when developing their plans, the EG must include information 
regarding the ``degree of emission limitation achievable through the 
application of the best system of emission reduction'' that has been 
adequately demonstrated, taking into account the same factors as 
described in component three (cost, nonair quality health and 
environmental impact and energy requirements), ``and the time within 
which compliance with standards of performance can be achieved.'' Id. 
at 60.22a(b)(5). The EPA has included such information in the November 
2021 Proposal; \680\ in the November 2021 TSD; \681\ in the December 
2022 Supplemental Proposal; \682\ in the December 2022

[[Page 16993]]

TSD; \683\ in sections X, XI, and XIII.E of this preamble; and in the 
final TSD located at Docket ID No. EPA-HQ-OAR-2021-0317. In identifying 
the degree of achievable emission limitation, the EPA may 
subcategorize, that is to ``specify different degrees of emission 
limitation or compliance times or both for different sizes, types, and 
classes of designated facilities when costs of control, physical 
limitations, geographical location, or similar factors make 
subcategorization appropriate.'' Id. The EPA has chosen to exercise 
that discretion to subcategorize within the final EG for certain 
designated facilities.\684\ Sixth, and last, the EG is to include any 
other information not contemplated by the five other components that 
the EPA ``determines may contribute to the formulation of State 
plans.'' Id. at 60.22a(b)(6). Section XIII of this preamble includes 
such information and guidance specifically designed to assist states in 
developing and submitting their plans under CAA 111(d) for the final EG 
OOOOc.
---------------------------------------------------------------------------

    \671\ 86 FR 63124 (November 15, 2021).
    \672\ 86 FR 63169-63240 (November 15, 2021).
    \673\ EPA-HQ-OAR-2021-0317-0166.
    \674\ 87 FR 74722-810 (December 6, 2022).
    \675\ EPA-HQ-OAR-2021-0317-1578.
    \676\ 86 FR 63169-240 (November 15, 2021).
    \677\ EPA-HQ-OAR-2021-0317-0166.
    \678\ 87 FR 74722-810 (December 6, 2022).
    \679\ EPA-HQ-OAR-2021-0317-1578.
    \680\ 86 FR 63169-240 (November 15, 2021).
    \681\ EPA-HQ-OAR-2021-0317-0166.
    \682\ 87 FR 74722-810 (December 6, 2022).
    \683\ EPA-HQ-OAR-2021-0317-1578.
    \684\ See sections X and XI of this preamble for detailed 
discussion of the designated facilities for which the EPA is 
including subcategories for.
---------------------------------------------------------------------------

C. Establishing Standards of Performance in State Plans

    After the EPA provides information regarding the BSER in this final 
EG, as described in preamble section XII of the November 2021 Proposal 
and preamble section IV of the December 2022 Supplemental Proposal, 
each state that has a designated facility located within the state must 
develop, adopt, and submit to the EPA its state plan under CAA section 
111(d). The state plan must include standards of performance for all 
designated facilities. Under the 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 TIP implementing the EG. The final 
EG OOOOc addresses two key aspects of implementation, among other 
issues: establishing standards of performance for designated facilities 
and providing measures that implement and enforce such standards. In 
this final EG, based on changes as a result of public comments, the EPA 
finalizes updates to certain presumptive standards included in the 
December 2022 Supplemental Proposal, and finalizes regulations related 
to state flexibilities, certain implementation and enforcement 
measures, and emissions inventories. The EPA is not finalizing in EG 
OOOOc the proposed requirements related to meaningful engagement with 
pertinent stakeholders, and electronic submittal of state plans, nor it 
is finalizing certain proposed requirements related to the application 
of a standard of performance to a particular designated facility that 
is less stringent than otherwise required by the EG when taking into 
consideration the facility's RULOF because such regulations are no 
longer needed in this EG (OOOOc). Via a separate rulemaking process, 
the EPA has finalized revisions to subpart Ba \685\ addressing the 
framework for less stringent standards of performance pursuant to 
RULOF, meaningful engagement with pertinent stakeholders, and 
electronic submittal of state plans which are applicable to states 
developing plans under these EG. Since these issues are addressed in 
the final revisions to subpart Ba, and subpart Ba applies to states 
developing plans under this EG (OOOOc), it would be redundant for the 
EPA to also finalize the same provisions related to these issues within 
EG OOOOc. As such, the EPA is not finalizing provisions specific to 
these issues as proposed in the context of this EG (OOOOc) and is 
instead deferring to subpart Ba on these issues. States should 
carefully review the recent revisions to subpart Ba since subpart Ba 
applies to state plans developed in accordance with this EG, except to 
the extent that this EG supersedes subpart Ba (such as, for emissions 
inventories and the deadline for state plan submittals, discussed in 
later sections).
---------------------------------------------------------------------------

    \685\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------

1. Establish Standards of Performance for Designated Facilities
    As stated in the November 2021 Proposal, and reiterated in the 
December 2022 Supplemental Proposal, the EPA's proposed EG OOOOc 
included information on the degree of emissions limitation achievable 
through application of the BSER in the form of presumptive standards 
for designated facilities.\686\ The EPA described that there is a 
fundamental requirement under CAA section 111(d) that a state's 
standards of performance in its state plan submittal are no less 
stringent than the presumptive standard determined by the EPA, which 
derives from the definition of ``standard of performance'' in CAA 
section 111(a)(1).\687\ The EPA is updating tables 25 and 26 to reflect 
the final presumptive standards in the final EG OOOOc.
---------------------------------------------------------------------------

    \686\ 86 FR 63169-63240 (November 15, 2021) and 87 FR 74722-810 
(December 6, 2022).
    \687\ CAA section 111(d)(1) also provides that states may apply 
less stringent standards of performance to particular sources based 
on consideration of such sources' remaining useful life and other 
factors.

    Table 25--Summary of Final EG Subpart OOOOc Presumptive Numerical
                                Standards
------------------------------------------------------------------------
                                           Final presumptive numerical
          Designated facility               standards in the emissions
                                               guidelines for GHGs
------------------------------------------------------------------------
Storage Vessels: Tank Battery with PTE   95 percent reduction of
 of 20 tpy or more of methane.            methane.
Process Controllers: Natural gas-driven  Methane emissions rate of zero.
Pumps: Natural gas-driven..............  Methane emissions rate of zero.
------------------------------------------------------------------------


  Table 26--Summary of Final EG Subpart OOOOc Presumptive Non-Numerical
                                Standards
------------------------------------------------------------------------
                               Final presumptive non-numerical standards
     Designated facility          in the emissions guidelines for GHGs
                                                 \688\
------------------------------------------------------------------------
Fugitive Emissions: Single     Quarterly AVO monitoring surveys. First
 Wellhead Only Well Sites and   attempt at repair within 15 days after
 Small Well Sites.              detecting fugitive emissions. Final
                                repair within 15 days after 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.

[[Page 16994]]

 
Fugitive Emissions: Multi-     Quarterly AVO monitoring surveys. First
 wellhead only Well Sites (2    attempt at repair within 15 days after
 or more wellheads).            detecting fugitive emissions. Final
                                repair within 15 days after first
                                attempt. Semiannual OGI monitoring
                                (Optional semiannual EPA Method 21
                                monitoring with 500 ppm defined as a
                                leak). First attempt at repair within 30
                                days after detecting fugitive emissions.
                                Final repair within 30 days after 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 monitoring surveys. First
 Sites and Centralized          attempt at repair within 15 days after
 Production Facilities.         detecting fugitive emissions. Final
                                repair within 15 days after first
                                attempt. Quarterly OGI monitoring.
                                (Optional quarterly EPA Method 21
                                monitoring with 500 ppm defined as a
                                leak). First attempt at repair within 30
                                days after detecting fugitive emissions.
                                Final repair within 30 days after 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 monitoring surveys. First
 Compressor Stations.           attempt at repair within 15 days after
                                detecting fugitive emissions. Final
                                repair within 15 days after first
                                attempt. AND Quarterly OGI monitoring.
                                (Optional quarterly EPA Method 21
                                monitoring with 500 ppm defined as a
                                leak). First attempt at repair within 30
                                days after detecting fugitive emissions.
                                Final repair within 30 days after first
                                attempt.
Fugitive Emissions: Well       Annual OGI monitoring. (Optional annual
 Sites and Compressor           EPA Method 21 monitoring with 500 ppm
 Stations on Alaska North       defined as a leak). First attempt at
 Slope.                         repair within 30 days after detecting
                                fugitive emissions. Final repair within
                                30 days after first attempt.
Process Controllers: Alaska    Natural gas bleed rate no greater than 6
 (at sites where onsite power   scfh.
 is not available--continuous
 bleed natural gas-driven).
Process Controllers: Alaska    OGI monitoring and repair of emissions
 (at sites where onsite power   from controller malfunctions.
 is not available--
 intermittent natural gas-
 driven).
Pumps: Natural gas-driven (at  Route pump emissions to a process if VRU
 sites where onsite power is    is onsite, or to control device if
 not available and there are    onsite.
 fewer than 3 diaphragm
 pumps).
Gas Well Liquids Unloading...  Employ best management practices to
                                minimize or eliminate venting of
                                emissions to the maximum extent
                                possible.
Equipment Leaks at Natural     LDAR with OGI following procedures in
 Gas. Processing Plants.        appendix K.
Oil Wells with greater than    Route associated gas to a sales line.
 40 tpy of Associated Methane   Alternatively, the gas can be used as an
 Gas.                           onsite fuel source or used for another
                                useful purpose that a purchased fuel or
                                raw material would serve or be injected
                                into the well or another well. If
                                demonstrated, and annually documented,
                                that a sales line and alternatives 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.
Oil Wells with 40 tpy or less  Route associated gas to a sales line.
 of Associated Methane Gas.     Alternatively, 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, or be injected
                                into the well or another well.
                                Alternatively, the gas can be routed to
                                a flare or other control device that
                                achieves at least 95 percent reduction
                                in methane emissions.
Wet Seal Centrifugal           Monitoring and repair to maintain
 Compressors (except for        volumetric flow rate at or below 3 scfm
 those located at well          per compressor seal.
 sites): Includes self-
 contained wet seal
 centrifugal compressors and
 centrifugal compressors
 equipped with mechanical
 seals.
Wet Seal Centrifugal           Monitoring and repair to maintain
 Compressors (except for        volumetric flow rate at or below 9 scfm
 those located at well          per seal.
 sites): Alaska North Slope
 centrifugal compressors
 equipped with a seal oil
 recovery system.
Dry Seal Centrifugal           Monitoring and repair to maintain
 Compressors (except for        volumetric flow rate at or below 10 scfm
 those located at well sites).  per compressor seal.
Reciprocating Compressors      Monitoring and repair to maintain
 (except for those located at   volumetric flow rate at or below 2 scfm
 well sites).                   per compressor cylinder.
------------------------------------------------------------------------
\1\ Fugitive Emissions: Well Sites, Centralized Production Facilities,
  and Compressor Stations: (Optional) Alternative periodic screening
  with advanced measurement technology instead of OGI monitoring.
\2\ Fugitive Emissions: Well Sites, Centralized Production Facilities,
  and Compressor Stations: (Optional) Alternative continuous monitoring
  system instead of OGI monitoring.

    The EPA received comments regarding the proposed presumptive 
standards. A summary of some comments received and the EPA's response 
to these comments, including any changes made to the final rule, as 
applicable, are provided below. The EPA's full response to comments on 
the November 2021 Proposal and December 2022 Supplemental Proposal, 
including any comments not discussed in this preamble, can be found in 
the EPA's RTC document for the final rule.\689\
---------------------------------------------------------------------------

    \688\ For fugitive emissions at well sites, centralized 
production facilities, and compressor stations, the final EG 
includes an advanced measurement technology compliance option to use 
alternative periodic screening and alternative continuous monitoring 
instead of OGI and AVO monitoring.
    \689\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).

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

[[Page 16995]]

    Comment: The EPA received numerous comments that seem to object to 
the general notion that a presumptive standard included in the EG can 
be the same as a standard of performance under the NSPS. Commenters 
contend that the EPA did not perform an appropriate BSER analysis for 
existing sources and cannot simply apply the new source BSER to 
existing sources without further explanation. Some commenters state 
that EG OOOOc requirements should not be same as NSPS OOOOb 
requirements, and that the cost of regulations for existing sources is 
significantly higher than on new facilities, especially where there is 
significant capital cost.
    Response: In accordance with section 111(d) of the Clean Air Act 
(CAA), states are tasked with developing plans which establish 
standards of performance for existing sources. Further, in accordance 
with CAA 111(d) and the EPA's implementing regulations, the EPA is to 
publish EG for certain sources. Those guidelines are to include certain 
information including ``[t]he degree of emission limitation achievable 
through the application of the best system of emission reduction 
(considering the cost of such achieving reduction and any nonair 
quality health and environmental impact and energy requirements) that 
has been adequately demonstrated for designated facilities.'' 40 CFR 
60.22a(b)(5). The EG must also include: ``[i]nformation on the degree 
of emission limitation which is achievable with each system, together 
with information on the costs, nonair quality health environmental 
effects, and energy requirements of applying each system to designated 
facilities.'' Id. at 60.22a(b)(3).
    The EPA is finalizing EG that translate the degree of emission 
limitation achievable through application of the BSER (i.e., level of 
stringency) into presumptive standards of performance that states may 
use in the development of state plans for specific emission points. The 
EPA's final EG do not impose binding requirements directly on sources, 
but instead provide requirements for states in developing their plans 
and criteria for assisting the EPA when judging the adequacy of such 
plans. The presumptive standards that commenters appear to take issue 
with are a product of the EPA's compliance with the CAA and its own 
regulations, and are intended to assist states with the development of 
their plans.
    Within the EPA's November 2021 Proposal, the Agency explained why 
the EG's proposed presumptive standards were often very similar to, if 
not exactly the same as, the EPA's proposed standards of performance 
under the proposed NSPS OOOOb. Part of that explanation is copied here 
for context:

    As discussed in each of the EG-specific subsections below, the 
EPA's evaluation of BSER in the context of existing sources utilized 
much of the same information as our BSER analysis for the NSPS. This 
is because within the oil and natural gas industry many of the 
control measures that are available to reduce emissions of methane 
from existing sources are the same as those control measures 
available to reduce VOC and methane emissions from new, modified, 
and reconstructed sources. By extension, many of the methane 
emission reductions achieved by the available control options, as 
well as the associated costs, nonair environmental impacts, energy 
impacts, and limitations to their application, are very similar if 
not the same for new and existing sources. Any relevant differences 
between new and existing sources in the context of available control 
measures or any other factors are discussed in the EG-specific 
subsections below.

86 FR 63186.

    The November 2021 Proposal goes on to elaborate on these general 
concepts. Id. The subsections that follow then explain the similarities 
and any differences between new and existing sources for each of the 
designated facilities covered by the EG. The December 2022 Supplemental 
Proposal took the same approach by identifying similarities and 
differences between new and existing sources, when relevant, within the 
sections discussing the different affected and designated facilities.
    Commenters provide no rationale or explanation to support the 
general assertion that the presumptive standards in this EG cannot ever 
be the same as the standards of performance in the corresponding NSPS. 
Nor does any relevant CAA authority prohibit this outcome. The EPA did 
not simply copy the NSPS into the EG. As explained in the November 2021 
Proposal, the analysis that the EPA undertakes for purposes of the EG 
OOOOc is the same as the analysis that the agency undertakes for the 
NSPS; they are both premised on the same categories of criteria or 
``inputs'' (available control options, costs associated with available 
control options, emission reductions associated with available control 
options, nonair quality health and environmental impacts associated 
with available control options, and energy requirements associated with 
available control options). Further, the EPA's methodology for 
assessing the ``inputs'' is the same under the NSPS and the EG. In the 
case of many designated facilities for this EG, the value of the 
``inputs'' happens to be the same, or very similar (i.e., there are no 
meaningful factual differences), such that the outcomes of the analysis 
happen to be the same or very similar. But that is not always the case. 
Where meaningful factual differences exist between new and existing 
sources, the EPA appropriately took those differences into account when 
developing the presumptive standards in the final EG. Take for example 
the criteria of costs. For many designated facilities in this EG, the 
costs of controlling emissions do not include large capital 
expenditures or retrofit costs because there is no additional equipment 
to buy and install.\690\ However, this is not the case for every 
designated facility. For example, the presumptive standards for wells 
with associated gas in the final EG OOOOc, as discussed in section 
XI.F.2 of this preamble, are different than the final standard of 
performance in NSPS OOOOb in part because of cost differences between 
new and existing sources. By way of another example, in the November 
2021 Proposal, the EPA explained relevant cost differences between new 
and existing tank batteries and concluded that ``it is more expensive 
to install controls at an existing tank battery than to install 
controls as part of a new tank battery.'' \691\
---------------------------------------------------------------------------

    \690\ For example, see December 2022 Supplemental Proposal, 87 
FR 74792, regarding dry seal compressors (``[t]he 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''). See also 87 FR 74809 (``[t]he 
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'').
    \691\ 86 FR 63110, at 63200. More specifically, EPA ``applied a 
30 percent retrofit factor to the capital and installation costs to 
account for added costs of manifolding existing storage vessels and 
installing the control system on an existing tank battery.'' Id. 
After considering the costs for existing sources, EPA found ``the 
cost effectiveness for achieving 95 percent emission reduction of 
methane from [an existing] tank battery with potential methane 
emissions of 20 tpy is reasonable for methane.'' Id. at 63201.
---------------------------------------------------------------------------

    To the extent that commenters raised particular issues (factual 
differences) that they thought warranted a different presumptive 
standard because of some difference between new and existing sources, 
those comments are addressed separately in the context of the 
appropriate designated facility. Specifically with regard to costs, the 
EPA recognizes the general possibility that the costs associated with 
utilizing various available control options could

[[Page 16996]]

vary between new and existing sources. It is also possible that the 
costs are exactly the same; it depends on various facts that are 
specific to the individual analysis for each type of designated 
facility. To the extent that the EPA or commenters identified 
meaningful cost differences between new and existing sources, those 
differences are addressed in the context of the discussion about the 
particular affected and designated facilities.
2. State Flexibilities
a. Leveraging State Programs
    As first acknowledged in the November 2021 Proposal, the EPA 
recognizes that some states already have existing programs they may 
want to leverage for purposes of satisfying their CAA section 111(d) 
state plan obligations (86 FR 63252). As stated in the December 2022 
Supplemental Proposal,\692\ 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 whether 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 
such that the integrity of the EG is not undermined. In the December 
2022 Supplemental Proposal, the EPA specifically proposed a source-by-
source evaluation methodology which consists of five basic criteria to 
determine whether a source-by-source (or designated facility-by-
designated facility) evaluation can be considered for equivalency 
should any state choose to leverage a state program for purposes of 
satisfying their CAA section 111(d) state plan obligations. The 
proposed criteria were: (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). The EPA further 
proposed 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. The 
step-by-step approach the EPA proposed in the December 2022 
Supplemental Proposal is outlined below. The EPA is, in large part, 
finalizing this approach as proposed. Any differences between the 
December 2022 Supplemental Proposal and the final EG with respect to 
this approach are explained below.
---------------------------------------------------------------------------

    \692\ 87 FR 74812.
---------------------------------------------------------------------------

    i. Step One: Are the state rule designated facility definition, 
pollutant, and format the same?
    The first question that a state needs to answer is whether its 
program relied upon for purposes of the CAA 111(d) state plan defines 
the regulated emissions sources substantially similar to how the EPA 
defines a designated facility. The state should also address whether 
the state's program requirements in the state plan for the designated 
facility regulate the same pollutant (GHGs with standards expressed as 
limitations on methane), and whether 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 three 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 unless the state 
program is altered to address the inconsistency. If the answer is yes 
to all of these questions, a state could proceed to Step Two.
    ii. Step Two: Emissions reductions.
    If a state wishes to rely on their program for purposes of their 
state plan, and they are not invoking RULOF to justify a less stringent 
standard, then 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 in the final EG. A state would have several options to make 
this demonstration.
    The first option would be to make a demonstration that the 
designated facility's state standard achieves the same degree of 
emission reduction as the designated facility BSER identified in the 
final EG using the EPA model plant/representative facility. The second 
option would be to make a demonstration that the designated facility's 
state standard, when applied to an actual facility in the state, 
achieves the same or greater emissions reduction as the designated 
facility model plant/representative facility emission reduction in the 
BSER analysis. The third option would be to conduct a state-wide 
emissions comparison, in which the state would apply the designated 
facility presumptive standard to data reflecting the population of 
sources in the state (e.g., using activity data (number of sources) and 
actual emissions data) and calculate the state-wide emission reduction 
that would be achieved by apply the presumptive standard, and then 
demonstrate that the state program requirements for a designated 
facility would achieve the same or greater emissions reduction. If, for 
any designed facility type, emissions reductions from the 
implementation of the state rule are less than would be achieved from 
the implementation of the final presumptive standards in the EG, and 
the state does not properly invoke RULOF to justify the less stringent 
standard(s), then the state cannot make an equivalency determination 
with the EPA's presumptive standards for that designated facility type. 
Conversely, 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 could proceed to 
Step Three.
    iii. Step Three: Make demonstration that compliance measures 
included for a designated facility under a state program are adequate.
    Once a state has determined that the emissions 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 emissions reductions. The EPA's presumptive standards 
included in the final EG are accompanied by compliance measures.
    The EPA's intention for providing these criteria is to offer states 
flexibility while establishing guideposts for states and the EPA to 
follow to ensure that the state plan would meet the degree of emission 
limitation required under the EG. These criteria are necessary to 
ensure that states are establishing standards of performance that meet 
the statutory requirements of section 111, the EPA's implementing 
regulations under section 111(d) (subpart Ba), and this final EG. They 
also enable the EPA to make reasoned decisions that are consistent 
across states with respect to whether state plans are ``satisfactory'' 
and therefore approvable under section 111(d). The EPA solicited 
comment on all aspects of the proposed state program equivalency 
demonstration methodology and evaluation criteria. The EPA received 
significant comments

[[Page 16997]]

regarding the type of equivalency evaluation. A summary of the comments 
received and the EPA's response to these comments, including any 
changes made to the final rule, as applicable are provided below. The 
EPA's full response to comments on the November 2021 Proposal and 
December 2022 Supplemental Proposal, including any comments not 
discussed in this preamble, can be found in the EPA's RTC document for 
the final rule.\693\
---------------------------------------------------------------------------

    \693\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

Types of Equivalency Evaluations: Total Program Evaluation
    Within the 2022 Supplemental Proposal, on pages 74813 to 74814, the 
EPA considered an option to allow ``total program evaluation.'' The EPA 
opted to not propose such an approach for the concerns expressed in 
that supplemental proposal. Even though commenters asked the EPA to 
allow total program evaluations, we are finalizing as proposed to not 
allow such an approach for the reasons explained below.
    Comment: Numerous stakeholders support a total program evaluation 
rather than the proposed source-by-source methodology. In general, 
commenters recommend that the EPA maximize flexibility by allowing 
states to continue implementing their existing state programs.\694\ One 
commenter implies that for a total program evaluation to work, the EPA 
would need to allow for emissions averaging across emissions sources to 
demonstrate equivalency.\695\ Another commenter generally states that 
they believe a total program evaluation can be employed, with 
appropriate guardrails, to both ensure significant emissions reductions 
opportunities will move forward while not disrupting effective state 
programs that are already in place.\696\ For example, the commenter 
wrote that states should be required to adopt new requirements for a 
particular source category only in the following circumstances: (1) 
where the state program does not include any reduction requirements for 
a particular source category; or (2) the state does have reduction 
requirements for a particular source category but those requirements 
achieve significantly less emissions reductions than the requirements 
set forth in the EG relative to the overall emission reductions from 
the oil and gas sector achieved by the state program. Absent these 
circumstances, the commenter asserts that the state should retain the 
flexibility necessary to continue with its current program, provided, 
of course, that the state can demonstrate that the overall program can 
achieve comparable emissions reductions to the EG. The comment further 
advocates that the final rule provide flexibility for states to 
demonstrate overall program equivalency as it pertains to existing 
state monitoring, recordkeeping, and reporting requirements. More 
specifically, the commenter requests that the final rule provide that 
if a state demonstrates overall program equivalency, changes or 
additions to existing monitoring, recordkeeping, and reporting 
provisions only be required where the existing provisions are 
substantially inadequate to ensure compliance with the associated 
emissions reductions requirements. The commenter expresses concern that 
in order to leverage a state program, the state may actually need to 
modify its existing regulatory provisions, which the commenter believes 
would undermine the state's implementation processes and practices and 
lead to less effective state regulation.
---------------------------------------------------------------------------

    \694\ See Document ID Nos. EPA-HQ-OAR-2021-0317-2249, -2286, -
2296, -2326, -2390, -2410.
    \695\ See Document ID No. EPA-HQ-OAR-2021-0317-2390.
    \696\ See Document ID No. EPA-HQ-OAR-2021-0317-2286.
---------------------------------------------------------------------------

    Similarly, another commenter requests that the EPA allow states to 
leverage existing state programs through submittal of total program 
evaluations to demonstrate equivalency with EG OOOOc.\697\ The 
commenter contends that precluding states from making a programmatic 
equivalency determination--by requiring the EPA's source-by-source 
approach--serves as a disincentive to state rulemaking. More 
specifically, the commenter argues that the source-by-source evaluation 
would be an application of a one-size-fits all approach to state 
regulation in contradiction of the cooperative federalism principles 
inherent throughout the CAA and specifically enumerated in CAA section 
111(d). Further, the commenter believes that the EPA's source-by-source 
equivalency approach will stifle progressive state rulemaking, as those 
states would be less likely to expend the significant resources to 
promulgate new rules only to have the EPA swoop in and set aside well-
thought-through state programs.
---------------------------------------------------------------------------

    \697\ See Document ID No. EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------

    Another commenter asserts that the EPA's proposal to preclude 
states from relying on emissions averaging across emissions sources to 
demonstrate equivalency will prevent states from effectively leveraging 
existing state programs, require states with existing, comprehensive 
regulatory programs to undertake additional rulemakings in order to 
prove identicality, rather than equivalency.\698\ They interpret the 
December 2022 Supplemental Proposal to have proposed a ban on averaging 
by relying on health-based considerations. The commenter asserts that 
the EPA justifies its decision to categorically preclude total program 
evaluations on the grounds that source-by-source equivalency 
demonstrations will result in greater emissions reductions because 
states with more stringent regulations for some sources will be 
required to revise any less stringent regulations to meet the EPA 
standard. They assert that the EPA's position cannot be squared with 
the interpretation of CAA section 111(d). The commenter cites to the 
D.C. Circuit's decision in American Lung Association that instructs 
that for the EPA to bar states from submitting plans that rely on 
averaging, the EPA must have a source- and pollutant-specific rationale 
that is justified and supportable.
---------------------------------------------------------------------------

    \698\ See Document ID No. EPA-HQ-OAR-2021-0317-2390.
---------------------------------------------------------------------------

    The same commenter further argues that they believe that CAA 
section 111(d) does not preclude state plans from including non-
designated facilities for the purpose of demonstrating equivalency. The 
commenter recommends that the EPA allow state plans to include rules 
that apply to non-designated facilities for the limited purpose of 
demonstrating the state plan will achieve equivalent emissions 
reductions as EG OOOOc. The commenter believes that allowing state 
plans to include regulations that apply to non-designated facilities, 
for the limited purpose of demonstrating equivalency, is consistent 
with the ``cooperative-federalism approach'' adopted by Congress in CAA 
section 111(d) ``that leaves the [s]tates discretion in determining how 
their [s]tate and industry can best meet quantitative emissions 
guidelines established by the EPA.''
    American Lung Ass'n, 985 F.3d at 942. They commenter continues to 
state that even if the EPA's interpretation is reasonable, the fact 
that the EPA proposed that a state plan cannot rely on emissions 
reductions from non-designated facilities does not justify the EPA's 
wholesale bar on submitting total

[[Page 16998]]

program evaluations. The commenter adds that the EPA does not provide 
any support in the statute or case law for its interpretation that 
states cannot rely on regulations that regulate the emission of VOCs or 
other pollutants, if the state can demonstrate that those regulations 
achieve equal reductions in methane as a co-benefit. The commenter 
asserts that the EPA does not rationally justify its concerns about 
allowing states to rely on different standards, both non-numerical and 
numerical, in the state plan equivalency demonstrations. The EPA's 
concern that allowing states to use a non-numerical standard different 
from the EPA's to demonstrate equivalency ``would likely be technically 
difficult because many of the presumptive standards in the EG OOOOc are 
work practice standards that do not quantify emissions'' fails to 
support its decision to deprive states of the flexibility Congress 
granted them under the statute. The commenter believes that the EPA 
assumes--without support--that this equivalency evaluation would need 
to be qualitative rather than quantitative because ``not all states 
have comprehensive source and source-specific emissions inventory data 
[on which] to base a stringency comparison on emissions reductions 
alone.''
    The commenter criticizes the EPA's December 2022 Supplemental 
Proposal by arguing that they believe the EPA did not rationally 
justify its concerns about allowing states to rely on different 
standards, both non-numerical and numerical, in the state plan 
equivalency demonstrations.\699\ They refer back to the joint comment 
on the November 2021 Proposal from a number of states requesting that 
the EPA permit the use of different numerical standards.
---------------------------------------------------------------------------

    \699\ See Document ID No. EPA-HQ-OAR-2021-0317-2390.
---------------------------------------------------------------------------

    One commenter recommends that the EPA consider previous regulatory 
investments and existing state implementation plan approvals.\700\ One 
commenter asserts that the EPA must provide states an option to 
demonstrate the equivalency of their existing programs against the 
EPA's proposed EG because requiring overburdened state agencies to 
implement and enforce two redundant regulations jeopardizes the 
regulatory agency's effectiveness and has not been justified in the EPA 
proposal.\701\ The commenter furthermore is concerned that the proposed 
framework for leveraging state programs does not actually provide 
states with regulatory programs an option to demonstrate equivalency 
because many state's regulated pollutant is VOC rather than GHG 
(methane) even though VOC will achieve methane co-reductions. The 
commenter believes the source-by-source criteria and methodology to be 
unworkable, inflexible, and short-sighted and will result in redundant 
regulations, unnecessary, and an extremely poor use of state regulatory 
agencies' limited staffing resources. The commenter believes that it is 
incumbent upon the EPA to consider the above points and to allow 
equivalency demonstrations for states and have a streamlined process 
for the adoption of states' existing rules.
---------------------------------------------------------------------------

    \700\ See Document ID No. EPA-HQ-OAR-2021-0317-2249.
    \701\ See Document ID No. EPA-HQ-OAR-2021-0317-2296.
---------------------------------------------------------------------------

    Response: While reviewing and assessing these comments, the EPA 
observed that commenters do not provide specific alternative criteria 
or a specific alternative methodology for a total program evaluation 
that addresses the complexities and challenges unique to the oil and 
natural gas source category that the EPA identified in the December 
2022 Supplemental Proposal.\702\ Furthermore, the EPA observes that 
some commenters assert claims of equivalency with no supporting 
documentation to substantiate how they have made that determination 
articulated in their comments or identifying what criteria they used to 
compare their program to the December 2022 Supplemental Proposal. For 
example, the EPA posited that an accurate qualitative comparison on a 
total-program scale would be extremely complicated given that there are 
numerous types of designated facilities with presumptive standards, of 
which some have numerical limits and others are in the format of non-
numerical standards. Commenters did not provide the EPA with actionable 
ideas to address the concern that attempting to assess total program 
equivalency for this EG would be so complex that the results of such an 
analysis would likely be difficult to ascertain. The EPA remains 
concerned with allowing the type of total program equivalency that 
commenters appear to be asking for because the Agency has been unable 
to identify a methodology for conducting the comparison that would be 
likely to produce accurate and reliable results.
---------------------------------------------------------------------------

    \702\ See 87 FR 74812-16.
---------------------------------------------------------------------------

    Further, while evaluating these comments the EPA observed that 
total program equivalency would necessarily entail some degree of 
averaging across different types of designated facilities and 
recognizes that states would need to establish an emissions reduction 
tracking system to account for this averaging. If the EPA understands 
the commenters correctly, commenters would like the ability to, for 
example, regulate one type of designated facilities (e.g., fugitive 
emissions) in a manner that results in more emissions reductions than 
would occur under the presumptive standard in the EG and ``bank'' those 
``extra'' reductions to offset for a different type of designated 
facility (e.g., process controllers) where the state standard would be 
less stringent than the presumptive standards in the EG. This type of 
trading or averaging seems necessary to the idea of total program 
equivalency in the context of this EG. In this particular context, the 
EPA disfavors this approach and is not allowing this type of averaging 
in state plans under this EG. It is inherently difficult to accurately 
measure emissions from some of the designated facilities covered by 
this EG. More specifically, those designated facilities where the EPA 
is finalizing non-numerical presumptive standards are difficult to 
measure. In accordance with 40 CFR 60.24a(b), the EPA is to identify in 
the EG cases where it is not feasible to prescribe or enforce a 
standard formed as an allowable rate, quantity, or concentration. The 
EPA has done so in this EG. If the designated facility cannot be 
subject to a standard formed as a rate, quantity, or concentration of 
emissions, then it is logical that accurately measuring the emissions 
from such a designated facility would be difficult. If a state plan 
purported to ``overregulate'' a certain designated facility type that 
was subject to a non-numerical limit, beyond the presumptive standard 
in the EG, it would be extremely difficult to determine how much 
``credit'' would be banked for purposes of cross-designated facility 
averaging. This approach is not workable in a way that would ensure the 
integrity of the EG.
    To be clear, the EPA is not prohibiting all types of averaging in 
this final EG. On the contrary, states may average within the confines 
of each type of designated facility (e.g., storage vessel designated 
facilities to storage vessel designated facilities, pump designated 
facilities to pump designated facilities, fugitives designated 
facilities to fugitives designated facilities). This type of averaging 
does not run afoul of the concerns expressed above regarding total 
program equivalence. In the context of non-numerical standards, the EPA 
would expect the averaging associated with the equivalency

[[Page 16999]]

determination to be qualitative.\703\ This type of averaging to 
demonstrate equivalence is what the EPA means when discussing ``source-
by-source'' equivalency in the context of leveraging a state plan. 
States may very well take a different approach to certain types or 
groups of designated facilities. That is acceptable so long as the 
state plan follows the criteria laid out earlier in this section on 
leveraging a state plan. Specifically, step two (Emissions reductions) 
of the framework the EPA has laid out is the point at which this type 
of averaging is relevant.
---------------------------------------------------------------------------

    \703\ For an example of a qualitative equivalency determination 
in the context of the oil and natural gas source category, see 
memorandum, ``Equivalency of State Fugitive Emissions Programs for 
Well Sites and Compressor Stations to Final Standards at 40 CFR part 
60, subpart OOOOa,'' located at Docket ID No. EPA-HQ-OAR-2017-0483 
(January 17, 2020).
---------------------------------------------------------------------------

    We also clarify that averaging within the confines of each type of 
designated facility can be a form of a total program equivalence. The 
EPA recognized this possibility in the December 2022 Supplemental 
Proposal.\704\ In theory, if a state were to perform a source-by-source 
evaluation for each type of designated facilities in its state and 
determine equivalency for each type of designated facility, this would 
be a form of total program equivalency. Note however that this is 
distinct from the type of total program evaluation commenters advocate 
for and which the EPA is disallowing.
---------------------------------------------------------------------------

    \704\ See 87 FR 74814.
---------------------------------------------------------------------------

    The EPA also remains concerned about other complicating scenarios 
previously identified in the December 2022 Supplemental Proposal. 
Specifically, the EPA identified one scenario in which there are 
instances where a state covers part or a subset of the EG designated 
facility's applicability definitions. For example, Colorado requires 
the use of non-emitting \705\ process 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, as discussed in section 
XI.D of this preamble, the presumptive standard for process controllers 
included in the final EG is a methane emissions rate of zero with no 
site-wide production or other applicability threshold. Thus, the 
definition of the designated facility for controllers in the final EG 
covers a broader group of controllers than does Colorado's regulations. 
This would be problematic in a state plan because under CAA 111(d) and 
40 CFR part 60, subpart Ba, the state plan must include standards of 
performance for all designated facilities. Commenters did not provide 
the EPA with suggestions or ideas to address this concern. If the EPA 
were to permit total program equivalence in situations like this where 
the scope of the sources subject to regulation in the state programs do 
not align with the scope of coverage by the EG, then there could be 
situations where a state would be allowed to forgo regulating some 
designated facilities which the text of CAA section 111(d) says should 
be subject to standards of performance in a state plan. After review of 
the comments received, the EPA remains concerned that a total program 
evaluation would not guarantee that the same level of emissions 
reductions as identified in the EG would be achieved.
---------------------------------------------------------------------------

    \705\ The phrases ``zero emissions'' and ``non-emitting'' are 
used to describe process controllers, but the EPA does not use these 
phrases to mean the same thing. 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's final EG includes a presumptive standard for 
process controllers of zero emissions. The difference between non-
emitting, as defined by Colorado, and zero emissions, as used in 
this action, is that process controllers for which emissions are 
captured and routed to a combustion device do not have zero 
emissions. Therefore, routing emissions to a combustion device is 
not an option for compliance with the presumptive standard.
---------------------------------------------------------------------------

    In a related scenario, the EPA recognizes states may have broader 
thresholds for regulatory coverage that may differ from the EPA's EG 
definitions of designated facilities. For example, a state may cover a 
broader set of sources compared to the EG's designated facility 
applicability threshold. 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 
requirement. However, the EPA does not find it appropriate to allow a 
state to account for non-designated facilities for purposes of 
demonstrating program equivalency to the degree of emission limitation 
required by the EG, even if a state regulates such sources as a matter 
of state law. Put another way, for purposes of this EG, a state cannot 
bank credit for portions of a state plan that rely on state laws that 
regulate sources that are not designated facilities. CAA section 111(d) 
requires states to establish standards of performance for designated 
facilities that achieve the degree of emission limitations identified 
by the Administrator. Accordingly, the emission reductions relied upon 
for purposes of leveraging a state program to demonstrate source-by-
source equivalency should come from designated facilities. To be clear, 
the final EG in no way impacts states' ability to regulate sources 
under state law. States are still free to choose how to regulate 
sources. This section of this preamble is speaking to what are 
creditable emission reductions for purposes of averaging in a state 
plan submitted to the EPA under CAA 111(d) and 40 CFR part 60, subpart 
Ba, for purposes of this final EG.
    In addition, the EPA reiterates its interpretation that CAA section 
111(d) does not allow the EPA to approve state plan requirements for 
different pollutants other than those designated pollutants in the EG. 
Subpart Ba defined ``designated pollutant'' at 40 CFR 60.21a(a). The 
EPA is aware that while numerous states have programs in place that 
regulate emissions from the designated facilities that the EPA is 
finalizing presumptive standards for, many of those programs do not 
regulate GHGs in the form of limitations on methane. Some state 
programs regulate VOC. State plans must regulate the designated 
pollutant, which for this EG is GHGs in the form of limitations on 
methane. Further, as the EPA explained in the 2021 Proposal, states 
must submit plans ``to establish standards of performance for existing 
sources for any air pollutant: (1) The emission of which is subject to 
a Federal NSPS; and (2) which is neither a pollutant regulated under 
CAA section 108(a) (i.e., criteria pollutants such as ground-level 
ozone and particulate matter, and their precursors, like VOC) [footnote 
omitted] or a HAP regulated under CAA section 112.'' 86 FR 63110 at 
63134. While VOC are not specifically listed as CAA section 108(a) 
pollutants, the EPA is regulating VOC in the NSPS that corresponds to 
this EG as precursors to photochemical oxidants (e.g., ozone) and 
particulate matter (PM), both of which are listed CAA section 108(a) 
pollutants. Therefore, VOC fall within the CAA 108(a) exclusion here, 
and the EPA cannot approve a state plan that establishes standards of 
performance for VOC.
    The EPA clarifies we are not finalizing a framework that demands 
the state plan be identical to the EG. Under this EG, and consistent 
with the

[[Page 17000]]

cooperative federalism framework of CAA section 111(d), states have the 
prerogative to develop state plans and have flexibility to adopt 
standards that diverge from the presumptive standards finalized here 
(including by considering RULOF in the development of their state 
plans). However, the EPA specifies that the designated facilities and 
the regulated pollutants must be the same as specified in the EG. 
Further, unless the state is invoking RULOF to justify a less stringent 
standard, the state must demonstrate its plan achieves the degree of 
emission limitation in the EG in order to be approvable. After 
consideration of comments and for the reasons detailed in this section 
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 find that a total program evaluation 
along the lines that commenters describe would guarantee that the same 
emissions reductions as required by the EG would be achieved. 
Therefore, the EPA is not finalizing a framework to allow total program 
equivalency as commenters describe.\706\
---------------------------------------------------------------------------

    \706\ While the RIA includes information on state-level 
estimates of emissions reductions that could result from the final 
EG, it's not sufficient to judge the equivalence of a state plan. 
The RIA is intended to be illustrative in nature and is not precise 
enough to rely upon in an analysis of total program equivalency.
---------------------------------------------------------------------------

Types of Equivalency Evaluations: Source-by-Source Evaluation
    Comment: One commenter recommends that the EPA provide more clarity 
and specificity in its articulation of Steps 2 and 3 of the source-by-
source equivalency determination, particularly offering clarity about 
the approval of alternative technologies.\707\ The commenter recommends 
that the EPA establish guidance and work with states who choose to 
leverage their programs for purposes of their state plan submittal; the 
commenter believes this collaboration would pose little burden on the 
EPA. In addition, they suggest that ongoing resources be devoted to 
offering cooperative and consultative technical support to these 
states. The commenter recommends that the EPA be consistent across 
different regions in these determinations. However, the commenter 
asserts that the EPA must be clear in any guidance and offer a 
streamlined process for equivalency to give state and local agencies a 
high degree of certainty in leveraging their programs.
---------------------------------------------------------------------------

    \707\ See Document ID No. EPA-HQ-OAR-2021-0317-2249.
---------------------------------------------------------------------------

    Response: The EPA remains committed to working with states as they 
develop and submit state plans to the Agency for review. The EPA 
strives to maintain consistency in its collaboration with states to 
ensure that implementation of the EG will be uniform. Please see 
discussion in section XIII.D. and XIII.F. of this preamble related to 
components of state plan submissions and the EPA action on state plans.
    The EPA provides the following example for hypothetical state rules 
illustrating how states could implement the source-by-source 
(designated facility-by-designated facility) evaluation when conducting 
a state rule equivalency determination with the presumptive standards.
Centrifugal Compressor Examples--Comparison of Presumptive Standards 
With 4 Hypothetical Examples
    Table 27 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 emissions 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 27--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 Emissions Reduction
 (Basis): 56 percent (model
 compressor basis)..
Compliance Assurance Requirements:
 Records of changeout..
----------------------------------------------------------------------------------------------------------------

[[Page 17001]]

 
                                                    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 percent reduction)..
Estimated Emissions Reduction
 (Basis): 95 percent (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 Emissions Reduction
 (Basis): 92 percent (model
 compressor basis)..
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            PASS..................  PASS--Demonstrated      PASS.
 Reciprocating Compressor at                                    that the ``real
 Gathering and Boosting.                                        life'' state-wide
Designated Pollutant: Total gas flow                            emission reduction
 rate as surrogate for methane..                                for state rule was
Format of Standard: Numerical: 5                                greater than the
 scfm..                                                         ``real-life''
Estimated Emissions Reduction                                   reduction for the
 (Basis): using analysis of state-                              presumptive standard.
 wide emissions from actual
 reciprocating compressors, estimated
 that EG presumptive standard would
 achieve 85 percent reduction over
 the state, state rule would achieve
 87 percent reduction..
Compliance Assurance Requirements:
 Measure volumetric flow rate once
 every 6 months, record results..
----------------------------------------------------------------------------------------------------------------
                                                    Example E
----------------------------------------------------------------------------------------------------------------
Designated Facility: Single            PASS..................  FAIL--did not
 Reciprocating Compressor at                                    demonstrate that the
 Gathering and Boosting.                                        BSER presumptive
Designated Pollutant: Total gas flow                            standard model
 rate as surrogate for methane..                                facility reduction
Format of Standard: Numerical: 4                                was met.
 scfm..
Estimated Emissions Reduction
 (Basis): 88 percent (analysis of
 state-wide emissions from actual
 reciprocating compressors)..
Compliance Assurance Requirements:
 Measure volumetric flow rate once
 every 6 months, record results..
----------------------------------------------------------------------------------------------------------------

    The EPA further clarifies how we intend these steps of the source-
by-source equivalency determination to work with regards to the use of 
alternative technologies for monitoring of fugitive emissions. For 
illustrative purposes to assist with this response, we have identified 
three possible scenarios. First, if a state incorporates the 
presumptive standards and the associated advanced methane detection 
technology provisions from the EG model rule into their approved state 
plan submittal, then it would be reasonable to expect that when the EPA 
approves an alternative technology in the future, the designated 
facilities in the state could use the alternative technology. In a 
second scenario, if a state incorporates the presumptive standards but 
wants its state plan to include different alternative technology 
criteria, the state must demonstrate equivalence between the state's 
criteria and the criteria in the final EG. The EPA acknowledges however 
that certain authorities are retained by the EPA and a state would not 
have the authority to approve the alternative technology itself. 
Specifically, in Sec.  60.5373c the EPA lists authorities that will not 
be delegated to state, local, or Tribal agencies including but not 
limited to the approval of major alternatives to test methods and the 
approval of major alternatives to monitoring. In a third scenario, if 
the state's plan includes a standard that is not the presumptive 
standard from the EG and also different

[[Page 17002]]

alternative technology criteria than those included in the EG, the 
state would need to ensure that: (1) Their standard is equivalent to 
the presumptive standard (or invoke RULOF), and (2) the alternative 
technology criteria are equivalent to those included in the EG. 
However, just as with the second scenario, the authority to approve the 
alternative technology would be retained by the EPA.
b. Averaging
    As discussed in XIII.C.2.a of the December 2022 Supplemental 
Proposal, the EPA stated that CAA section 111(d) authorizes the EPA to 
allow states, in particular rules, to achieve the requisite emissions 
limitation through the aggregate reductions from their sources, and the 
EPA accordingly proposed to authorize states to leverage their state 
programs in specific ways to satisfy their CAA section 111(d) state 
plan obligations pursuant to the EG OOOOc. More specifically, the EPA 
proposed that states may average within the confines of each type of 
designated facility (e.g., pump designated facilities to pump 
designated facilities). As discussed previously, the EPA is allowing 
this type of averaging under the final EG. The EPA clarifies that this 
type of averaging may be used regardless of whether a state chooses to 
leverage an existing state program that predated EG OOOOc for purposes 
of their state plan submission. In other words, states may average 
within the confines of each type of designated facility even if a state 
does not choose to leverage an existing program, or if the state has no 
existing program and is developing new regulations in response to the 
EG for their state plan. In those situations, the EPA believes states 
can still use the discussion in section XIII.C.2.a of this document as 
guidance for ensuring their state plan is equivalent to the EG. Also, 
as discussed previously, the EPA is not allowing the type of averaging 
that commenters appear to be asking for when they discuss total program 
equivalency. The EPA's concerns with total program equivalency specific 
to this EG are explained above. The EPA received significant comments 
regarding the use of averaging in the state plan submittal. The EPA 
believes that the discussion on averaging above in this section 
responds to the most significant of those comments. The EPA's full 
response to comments on the November 2021 Proposal and December 2022 
Supplemental Proposal, including any comments not discussed in this 
preamble, can be found in the EPA's RTC document for the final 
rule.\708\
---------------------------------------------------------------------------

    \708\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

c. General Permitting Programs
    The EPA continues to recognize that some states may choose to 
regulate designated facilities under the EG 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 finalizing a regulatory provision on this 
topic within EG OOOOc, 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 
requires 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 otherwise meets those 
requirements.
3. Remaining Useful Life and Other Factors (RULOF)
    In the December 2022 Supplemental Proposal, the EPA proposed and 
solicited comment on requirements related to states' use of RULOF when 
applying standards of performance in their state plan submittals.\709\ 
However, the EPA is not finalizing any substantive provisions related 
to RULOF in EG OOOOc. The only provision included in the final version 
of EG OOOOc that relates to RULOF is 40 CFR 60.5365c, which directs 
states to the RULOF requirements specified in 40 CFR 60.24a (subpart 
Ba).
---------------------------------------------------------------------------

    \709\ See 87 FR 74816 (December 6, 2022).
---------------------------------------------------------------------------

    Since the supplemental proposal, the EPA has promulgated revisions 
to subpart Ba.\710\ These revisions represent the final, generally 
applicable requirements for RULOF, including consideration of the 
topics that the EPA addressed in the December 2022 Supplemental 
Proposal, and are applicable to these EG. State plans submitted in 
accordance with these EG that include provisions for RULOF must comply 
with the subpart Ba general RULOF provisions in 40 CFR 60.24a.\711\ As 
such, the EPA did not find it necessary to also finalize similar 
provisions in these EG as they would have been redundant with those 
recently finalized via a separate rulemaking process in subpart Ba.
---------------------------------------------------------------------------

    \710\ 88 FR 80480 (November 17, 2023).
    \711\ See 40 CFR 60.20a(a), which establishes applicability of 
subpart Ba requirements to EG OOOOc. Further, EG OOOOc does not 
supersede any requirement within subpart Ba related to RULOF.
---------------------------------------------------------------------------

    For informational purposes, the EPA will summarize the RULOF 
provisions that have been finalized in the subpart Ba rulemaking, which 
is separate and distinct from this action. 40 CFR 60.24a(e) explains 
that states may apply a standard of performance to a particular 
designated facility that is less stringent than otherwise required by 
an applicable EG taking into consideration that facility's RULOF, 
provided that the state demonstrates with respect to each such facility 
(or class of such facilities) that the facility cannot reasonably 
achieve the degree of emission limitation determined by the EPA based 
on: (1) 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 to the facility. The state must demonstrate 
that there are fundamental differences between the information specific 
to a facility or class of such facilities and the information the EPA 
considered in determining the degree of emissions limitation achievable 
through application of the BSER that make achieving such degree of 
emissions limitation unreasonable for that facility. Similarly, the 
state may apply a compliance schedule to a particular designated 
facility, or class of such facilities, that is longer than provided in 
an applicable emissions guideline taking into consideration that 
facility's RULOF, provided the state demonstrate there are fundamental 
differences between the information specific to the

[[Page 17003]]

facility and the information the EPA considered in determining the 
compliance schedule.
    If a state makes the demonstration in 40 CFR 60.24a(e), the plan 
may apply a standard of performance that is less stringent than 
required by an applicable EG. Such standard of performance must meet 
the requirements in 40 CFR 60.24a(f): (1) The standard must be no less 
stringent (or have a compliance schedule no longer) than is necessary 
to address the fundamental differences identified under 40 CFR 
60.24a(e). To the extent necessary to determine a standard of 
performance, the state must evaluate the systems of emission reduction 
identified in the applicable EG using the factors and evaluation 
metrics the EPA considered in assessing those systems, including 
technical feasibility, the amount of emission reductions, the cost of 
achieving such reductions, any nonair quality health and environmental 
impacts, and energy requirements. The states may also consider, as 
justified, other factors specific to the facility that were the basis 
of the demonstration under 40 CFR 60.24a(e) as well as other systems of 
emission reduction in addition to those the EPA considered in the 
applicable EG. (2) The standard of performance under 40 CFR 60.24a(f) 
must be in the form as required by the applicable EG. 40 CFR 60.24a(g) 
requires that where a state applies a less stringent standard of 
performance on the basis of an operating condition(s) within the 
designated facility's control, such as remaining useful life or 
restricted capacity, the plan must include such operating condition(s) 
as an enforceable requirement and provide for the implementation and 
enforcement of the operating condition(s), such as requirements for 
monitoring, reporting, and recordkeeping. 40 CFR 60.24a(h) requires 
that a less stringent standard of performance meet all other applicable 
requirements in subpart Ba and the applicable EG.
    Even though the EPA is not finalizing any RULOF requirements in EG 
OOOOc that are unique to the oil and natural gas industry, the EPA has 
provided information and analysis on this subject that states should 
consider when developing their state plans for this EG. First, as a 
point of clarification, application of the RULOF provisions in the 
context of EG OOOOc is distinct from source-by-source equivalency 
evaluations (that can account for a type of averaging) discussed 
earlier in section XIII.C.2 of this document. RULOF applies where a 
state intends to depart from the presumptive standards in EG OOOOc to 
apply a less stringent standard for a designated facility or class of 
facilities. That is, the RULOF provisions are relevant to a state's 
process of applying a standard of performance to an existing source in 
the first instance. In contrast, averaging is a mechanism that states 
may use to demonstrate compliance with the standards of performance 
that they have previously determined and are contained within their 
state plans. States are not required to use the RULOF provisions in 
order to implement averaging mechanisms to comply with a standard of 
performance that reflects the presumptive standard in EG OOOOc.
    Next, the EPA continues to find that states ought to consider 
certain circumstances that are specific to remaining useful life and 
the concept of unreasonable costs for EG OOOOc. The EPA explained these 
considerations within the December 2022 Supplemental Proposal. 87 FR 
74822-23. 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. Subpart Ba allows for a state to 
account for remaining useful life to apply a standard that is less 
stringent than the corresponding EG. Moreover, the recent revisions to 
subpart Ba, as explained above, clarified the circumstances in which 
states may invoke RULOF based on an existing source's remaining useful 
life, as well as the process for doing so.
    For purposes of this discussion, which is specific to EG OOOOc, the 
relevant provision of subpart Ba is 40 CFR 60.24a(e), which allows 
states to apply a less stringent standard if the state demonstrates 
that a facility, or class of facilities, cannot reasonably achieve the 
degree of emision limitation determined by the EPA based on, inter 
alia, unreasonable cost of control resulting from plant age. As 
explained in the December 2022 Supplemental Proposal, the EPA believes 
that the ability to demonstrate cost unreasonableness based on a 
source's remaining useful life would likely depend on whether the 
facility will be required to make a capital investment to comply with 
the presumptive degree of emission limitation.
    When the EPA determined the degree of emission limitation 
achievable through application of the BSER in this EG, as required by 
CAA section 111(a)(1), it considered costs of controls and, in many 
instances, the EPA specifically considered 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. The EPA provided the 
following example in the December 2022 Supplemental Proposal of how 
cost effectiveness is evaluated in these circumstances. This 
illustrative example is still helpful to understand the EPA's position 
and is therefore repeated here. In the estimation of the annual costs 
for the installation of an instrument air system to power process 
controllers with compressed air at a medium-sized transmission and 
storage site, the EPA estimated 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 7 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 illustrative example, the cost effectiveness is 
reasonable considering a capital recovery period, or payback period, of 
15 years. If the remaining useful life of a particular facility were to 
be less than 15 years, the result could be a cost effectiveness value 
for that facility that is outside of the range considered reasonable by 
the EPA, i.e., is fundamentally different from the cost of control the 
EPA considered in EG OOOOc. For example, consider a remaining useful 
life of 6 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 under 40 CFR 60.24a(e) that the costs 
were unreasonable for a remaining useful life of 6 years. However, if 
the remaining useful life were only 2 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

[[Page 17004]]

almost $4,600 per ton of methane removed, which is outside of the range 
considered reasonable by the EPA in this action. In this situation, 
this could potentially be used as part of a RULOF demonstration under 
subpart Ba to justify applying a less stringent standard.
    Note that this specific example is only for illustrative purposes. 
For process controller designated facilities, EG OOOOc identifies the 
degree of emission limitation achievable as zero methane emissions (100 
percent reduction). To invoke RULOF to apply a less stringent standard 
of performance, the state must show ``that the facility cannot 
reasonably achieve the degree of emission limitation determined by the 
EPA.'' 40 CFR 60.24a(e). While the example examines one potential 
control option to achieve the identified degree of emission limitation, 
there are other equivalent control options (e.g., electric controllers) 
that are considerably less expensive than the installation of an 
instrument air system. The EPA still finds this example helpful though 
because all zero-emissions control options for process controllers 
entail capital investment.
    In the December 2022 Supplemental Proposal, the EPA distinguished 
the application of remaining useful life based on cost unreasonableness 
for sources that would not incur capital costs to comply with the 
presumptive degree of emission limitation and proposed to preclude 
states from relying on the remaining useful life factor for certain 
specified facilities. While the EPA continues to believe that a cost 
unreasonableness determination based on remaining useful life for 
certain designated facility types (such as fugitive emissions, which do 
not entail large capital expenditures) would very likely not be 
justified under the RULOF provisions of subpart Ba, the EPA is not 
finalizing a regulatory provision prohibiting states from attempting to 
make such a demonstration in developing state plans for EG OOOOc.
    Nonetheless, the EPA continues to believe that for purposes of this 
EG the only cost factor that would likely be reasonable to consider in 
a remaining useful life determination of cost unreasonableness is 
whether there is a significant capital investment required to design, 
purchase, and install equipment. This is based on how the EPA conducted 
the relevant BSER analyses that resulted in the presumptive standards 
included in this final EG. The BSER determinations in EG OOOOc that are 
based on compliance measures that do not require such upfront capital 
expenditures were not based on the assumption that that the compliance 
costs would need to be amortized over a payback period in order to be 
considered cost reasonable, and therefore are reasonable for designated 
facilities that operate for any period of time into the future. If the 
presumptive standard included in this final EG does not require upfront 
capital expenditures, then the EPA believes it would be extremely 
unlikely that a state could demonstrate, based on costs relative to 
remaining useful life, ``that there are fundamental differences between 
the information specific to a facility (or class of such facilities) 
and the information EPA considered in determining the degree of 
emission limitation achievable through application of the best system 
of emission reduction or the compliance schedule that make achieving 
such degree of emission limitation or meeting such compliance schedule 
unreasonable for that facility.'' 40 CFR 60.24a(e)(2). Accordingly, a 
cost unreasonableness showing based on remaining useful life under 40 
CFR 60.24a(e) would likely only be appropriate for the following types 
of designated facilities in this EG: oil wells with associated gas, 
storage vessels, process controllers, and pumps. While states are not 
precluded from attempting to demonstrate cost-unreasonable based on 
remaining useful life for other designated facility types in this EG, 
the EPA does not believe that such a demonstration for the other 
designated facilities would likely satisfy the requirements of subpart 
Ba.
    Note that this discussion is specific to application of 40 CFR 
60.24a(e) based on unreasonable cost of control resulting from plant 
age (remaining useful life) within the context of this specific EG 
(OOOOc) and does not speak to application of the other circumstances 
provided in 40 CFR 60.24a(e).
    Within the December 2022 Supplemental Proposal, the EPA solicited 
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.'' 87 FR 74823. The EPA's 
reasoning for soliciting comments on this issue was that establishing 
such an outermost retirement date could avoid potential inequities 
associated with different states making demonstrations that result in 
different remaining useful life periods for the same types of 
designated facilities. After reviewing comments and considering this 
issue in conjunction with the final provisions promulgated as part of 
40 CFR part 60, subpart Ba, the EPA has determined that establishing 
outermost retirement dates in this EG is not necessary to avoid the 
potential inequities that the Agency expressed concern about in the 
December 2022 Supplemental Proposal. Specifically, the EPA finds that 
this potential inequity will be mitigated by the requirements within 
subpart Ba mandating that any standard less stringent than otherwise 
required by the EG be no less stringent than necessary to address the 
fundamental differences between the facility and the information the 
EPA considered when developing the EG. 40 CFR 60.24a(f)(1). This will 
help to ensure that the state's basis for relying on a particular 
retirement date to establish a less stringent standard is well-
justified. Moreover, the EPA recognizes the possibility, in the context 
of this EG, that certain designated facilities may be situated such 
that different remaining useful life periods for the same types of 
designated facilities could be justified. Due to the large number of 
existing sources, the wide variety of configurations, and the fact that 
the EPA's presumptive standards already include subcategories for some 
types of designated facilities, it is conceivable that fact-specific 
circumstances taken into account when applying the RULOF process in 
subpart Ba could result in different remaining useful life periods for 
the same types of designated facilities.
    Lastly, as previously discussed, subpart Ba requires 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. 40 CFR 60.24a(g). Accordingly, if a 
state applies a less stringent standard by accounting for remaining 
useful life, per subpart Ba, the state must include in the state plan 
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 specifying that the designated 
facility will not operate beyond a certain date (the facility's planned 
retirement date), and that regulation or agreed order would then be 
incorporated into the state plan. The state could also choose to 
incorporate the retirement date into a permit, such as a 
preconstruction permit, and incorporate that permit into the state 
plan.
    As required by CAA section 111(d) and subpart Ba, a state plan must

[[Page 17005]]

include a standard of performance that applies to a designated facility 
until its retirement (all designated facilities must be subject to a 
standard of performance). If the state is invoking RULOF to apply a 
less stringent standard, then the less stringent standard ``must be no 
less stringent . . . than is necessary to address the fundamental 
differences'' between the relevant facility and the information the EPA 
considered when developing the EG. 40 CFR 60.24a(f)(1). The EPA 
recognizes that, in some instances, a designated facility may intend to 
retire imminently such that the remaining useful life of that facility 
results in costs that are fundamentally different from the costs that 
the EPA considered in EG OOOOc. In such situations it may not be 
reasonable to require that any additional controls be installed, based 
on the source's exceptionally short remaining useful life. This could 
be especially true if such controls require upfront capital 
expenditures. In the case of an imminently retiring source, the EPA 
continues to believe that states should apply a standard of performance 
no less stringent than one that reflects the designated facility's 
current operations.
    The EPA explained this position in the December 2022 Supplemental 
Proposal at page 74823. If the fundamental difference between the 
facility at issue and the information that the EPA considered in this 
EG is that the facility intends to cease operations in the very near 
future, then it seems apparent to the EPA that the requirements of 
subpart Ba as applied to this EG would result in a standard that is no 
less stringent than what the source is already doing to control 
emissions. The EPA believes it would be extremely unlikely that a state 
could justify a standard less stringent than maintaining the existing 
level of emission control already in place at the facility.
4. Providing Measures That Implement and Enforce Such Standards
    In conjunction with establishing standards of performance, state 
plans must also include compliance schedules for those standards, and, 
where required by the applicable EG, must also include increments of 
progress. See 40 CFR 60.24a(a) and (d). Section XIII.E explains the 
timing of state plan submissions, compliance schedules, and increments 
of progress for EG OOOOc. The EPA's subpart Ba implementing regulations 
require that state plans shall require final compliance as 
expeditiously as practicable, but no later than the compliance times 
specified in the applicable EG. See 40 CFR 60.24a(c). States that 
identify a need for longer compliance times than those specified in the 
final EG must invoke RULOF to justify those longer times. See 40 CFR 
60.24a(e)-(h). Moreover, 40 CFR 60.24a(d) requires state plans to 
include increments of progress when the compliance schedule under the 
applicable EG extends more than 20 months after the state plan 
submittal date. Since the compliance schedule for EG OOOOc is 36 
months, the EPA has considered the need for and ultimately required 
increments of progress to be included in state plans. States that 
invoke RULOF to justify a compliance schedule longer than 36 months 
should consider whether additional increments of progress, beyond those 
required in EG OOOOc, are ``necessary to permit close and effective 
supervision of progress toward final compliance.'' 40 CFR 60.24a(d). 
Where a state invokes RULOF to apply a less stringent standard of 
performance, the compliance schedule must be as expeditious as 
practicable but no later than the time specified in EG OOOOc, 40 CFR 
60.24a(c), unless the state also justifies a longer compliance schedule 
pursuant to 40 CFR 60.24a(e) and (f).
    In addition to establishing standards of performance and compliance 
schedules, state plans must also include, adequately document, and 
demonstrate the methods employed to implement and enforce the standards 
of performance such that the EPA can review and identify measures that 
assure transparent and verifiable implementation. As part of ensuring 
that regulatory obligations appropriately meet statutory requirements 
such as enforceability, the EPA has historically and consistently 
required that obligations placed on sources be quantifiable, non-
duplicative, permanent, verifiable, and enforceable. See 40 CFR 
60.27a(g)(3)(vi). In accordance with the EPA's implementing 
regulations, standards of performance required for designated 
facilities as part of a state plan to implement the EG must be non-
duplicative, permanent, verifiable, and enforceable. Further, in this 
EG and in accordance with subpart Ba at 60.24a(b), the EPA has 
identified certain types of designated facilities where the Agency has 
determined that it is not feasible to prescribe or enforce a standard 
based on an allowable rate, quantity, or concentration of emissions 
(numeric limit). For these, the final EG includes non-numerical 
presumptive standards, consistent with CAA section 111(h)(1), sometimes 
referred to in shorthand as presumptive ``work practice standards'' but 
which can also be design, equipment, or operational standards, or a 
combination thereof.\712\ When states include non-numerical limits in 
their plan, ``the plan shall, to the degree possible, set forth the 
emission reductions achievable by implementation of such standards, and 
may permit compliance by the use of equipment determined by the State 
to be equivalent to that prescribed.'' 40 CFR 60.24a(b). A state plan 
implementing the EG should include information adequate to support a 
determination by the EPA that the plan meets these requirements.
---------------------------------------------------------------------------

    \712\ See tables 25 and 26 in this preamble for summary of final 
EG subpart OOOOc presumptive standards.
---------------------------------------------------------------------------

    Additionally, states must include appropriate monitoring, 
reporting, and recordkeeping requirements to ensure that state plans 
adequately provide for the implementation and enforcement of standards 
of performance. See 40 CFR 60.25a. The model rule included within the 
final EG OOOOc includes many monitoring, reporting, and recordkeeping 
provisions associated with the final presumptive standards. Within the 
2022 Supplemental Proposal, the EPA clarified our position ``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.'' 87 FR 74702 
at 74826. The EPA is finalizing this approach because the Agency has 
determined that the monitoring, reporting, and recordkeeping provisions 
included in the final EG are necessary to implement and enforce the 
associated presumptive standards. Put another way, if a state chooses 
to include a final presumptive standard in their state plan, then they 
need to also incorporate the associated final monitoring, 
recordkeeping, and reporting requirements contained in the model rule, 
or equivalent requirements, to ensure that the state plan adequately 
provides for the implementation and enforcement of the standard of 
performance. Where a state plan includes standards of performance that 
differ from the presumptive standards, the plan may accordingly include 
different monitoring, reporting, and recordkeeping requirements than 
those in the final model rule, but such requirements must be 
appropriate for the implementation and enforcement of the standards. In 
those situations, states may still find the monitoring, reporting, and 
recordkeeping provisions included in the model rule helpful and 
informative for development of their

[[Page 17006]]

state plan. The EPA reviews all state plan submittals for approvability 
through notice and comment rulemaking. As such, components of a state 
plan that differ from any presumptively approvable aspects of the EG, 
including monitoring, reporting, and recordkeeping provisions included 
in a state plan, will be thoroughly reviewed by the EPA and will be 
subject to review and comment by the public.
5. Emissions Inventories
    Within the November 2021 Proposal, the EPA solicited comment on 
whether to supersede the emission inventory requirements of 40 CFR 
60.25a(a).\713\ Based on comments received, in the December 2022 
Supplemental Proposal, the EPA proposed 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 that subpart Ba provision. 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 emissions 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. While the latest revisions to 
subpart Ba did alter this provision some, those revisions were not 
meaningful with respect to the reasoning that the EPA included in the 
December 2022 Supplemental Proposal for superseding this inventory 
requirement for the oil and natural gas EG.
---------------------------------------------------------------------------

    \713\ 86 FR 63253.
---------------------------------------------------------------------------

    The EPA received significant comments regarding the inclusion of an 
emissions inventory in the state plan submittal. A summary of the 
comments received and the EPA's response to these comments, including 
any changes made to the final rule, as applicable are provided below. 
The EPA's full response to comments on the November 2021 Proposal and 
December 2022 Supplemental Proposal, including any comments not 
discussed in this preamble, can be found in the EPA's RTC document for 
the final rule.\714\
---------------------------------------------------------------------------

    \714\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

    Comment: Several commenters support the use of existing emissions 
inventory data to fulfill state plan requirements even if that data 
might not be fully aligned with the designated facilities in the 
EG.\715\ One commenter \716\ suggested that the emissions inventory 
data could be derived from the GHGRP whereas other commenters \717\ did 
not support the use of GHGRP as a basis for their state inventory data 
due to the large reporting threshold. Several other commenters 
supported the EPA's proposal to supersede the requirements of 40 CFR 
60.25a(a) so that state plans do not have to include an inventory and 
emissions data as described.\718\ Lastly, one commenter reported that 
their state regulations require that any source of regulated air 
pollutants must submit an emission inventory and suggests the EPA 
accept emissions data for these facilities in accordance with the 
provisions of the Air Emissions Reporting Requirements (AERR), with 
detailed requirements for designated facilities that are classified as 
AERR Type A and B sources and the use of alternative methods (e.g., a 
nonpoint tool) for designated facilities that would be classified as 
nonpoint sources under the AERR.\719\ The commenter reports that AERR 
already has emissions thresholds for what should be inventoried as a 
point source, and what is being captured in the NEI as a nonpoint 
source. The commenter believes that the rule should align with the AERR 
thresholds and requirements and suggests that using the NEI would give 
a much more comprehensive accounting of facilities and provide more 
accurate emissions.
---------------------------------------------------------------------------

    \715\ See Document ID No. EPA-HQ-OAR-2021-0317-2218, -2286, -
2296, -2393, -2410.
    \716\ See Document ID No. EPA-HQ-OAR-2021-0317-2218.
    \717\ See Document ID No. EPA-HQ-OAR-2021-0317-2296, -2393.
    \718\ See Document ID No. EPA-HQ-OAR-2021-0317-2286, -2296.
    \719\ See Document ID No. EPA-HQ-OAR-2021-0317-2393.
---------------------------------------------------------------------------

    Response: The EPA maintains that, due to the very large number of 
existing oil and natural gas sources (designated facilities) \720\ and 
the frequent change of configuration and/or ownership, it is not 
practical to require states to compile this information generally 
required by subpart Ba in the same way that is typically expected for 
other industries under other EG. Furthermore, the EPA believes that, 
while 40 CFR 60.25a(a) could be superseded to require the use of 
existing emissions inventory data such as GHGRP or NEI to fulfill state 
plan requirements, the development of such an inventory would still be 
resource intensive with little benefit. Specifically, the EPA does not 
find it reasonable to burden states to derive information from GHGRP, 
the AERR, or the NEI, which the EPA already has, only to resubmit it to 
the Agency. Therefore, in order to avoid the potential burden that 
could be imposed by applying 40 CFR 60.25a(a) as written to this EG, as 
well as the potential burden and duplicative information collection 
imposed by requiring states to use other existing inventories such as 
GHGRP, the EPA finalizes, as proposed, 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. The EPA further reiterates for purposes of this EG, 
that the EPA does not find that the inventory and detailed emissions 
data required under 40 CFR 60.25a(a) is necessary for states to develop 
standards of performance.
---------------------------------------------------------------------------

    \720\ 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.
---------------------------------------------------------------------------

6. Meaningful Engagement
    In the November 2021 Proposal and December 2022 Supplemental 
Proposal, the EPA proposed and solicited comment on a requirement that 
states perform early outreach and meaningful engagement with pertinent 
stakeholders during the development process of their state plans 
pursuant to EG OOOOc.\721\ The EPA is not finalizing the provision for 
meaningful engagement in this rulemaking. Rather, since similar 
revisions to subpart Ba are now final and are therefore applicable to 
the EG OOOOc, state plans must be submitted according to the provisions 
in 40 CFR 60.23a(i) which requires states to document in their plan 
submittals how they provided meaningful engagement with the pertinent 
stakeholders. Specifically, subpart Ba requires as part of completeness 
criteria in 40 CFR 60.27a(g) that states must submit, with the plan or 
revision, documentation of meaningful engagement including a list of 
identified pertinent stakeholders and/or their representatives, a 
summary of the engagement conducted, a summary of stakeholder input 
received, and a description of how stakeholder input

[[Page 17007]]

was considered in the development of the plan or plan revisions.\722\
---------------------------------------------------------------------------

    \721\ See 86 FR 63254 (November 15, 2021) and 87 FR 74827 
(December 6, 2022).
    \722\ See 40 CFR 60.21a for the definitions of meaningful 
engagement and pertinent stakeholders.
---------------------------------------------------------------------------

    Since the EPA has finalized these meaningful engagement provisions 
within the context of subpart Ba, and since subpart Ba applies to the 
development of state plans for this EG, the EPA found it unnecessarily 
redundant to finalize similar provisions related to meaningful 
engagement in the context of this EG OOOOc. This EG therefore defers to 
subpart Ba on this topic. However, there are several related issues 
raised in comments that the EPA will briefly discuss here. First, as 
discussed in section VII of this preamble, the EPA summarized 
engagement with pertinent stakeholders for this rulemaking. To the 
extent that commenters take issue with the EPA's engagement with 
stakeholders on this rulemaking (the NSPS OOOOb and EG OOOOc), we 
direct them to section VII of this preamble and the separate RTC 
document associated with this final rulemaking.
    Second, the EPA recognizes that several comments the Agency 
received on the November 2021 Proposal and the December 2022 
Supplemental Proposal referenced several existing state and Tribal 
nation EJ programs and/or EJ analyses conducted in oil and natural gas 
producing states and Tribal nations. The EPA compiled information 
submitted by commenters and documented our review of other readily 
available information (e.g., state websites) on programs and analyses 
in a Memorandum to the public docket titled, Summary of State, Tribal 
and Local Environmental Justice (EJ) Programs and Analyses.\723\ The 
EPA believes this memorandum will serve as a helpful resource to 
states, pertinent stakeholders, and other interested parties trying to 
determine how to conduct their own meaningful engagement as part of the 
state planning process. The memorandum specifically describes a summary 
of existing EJ programs and other EJ activities conducted by state, 
Tribal, and local governments compiled from an in-depth assessment of 
government websites and publicly available documents. The EPA 
identifies state and Tribal EJ programs and procedures, including 
community identification criteria and mapping tools utilized.\724\ The 
EPA observes in the memorandum that while several states implement 
tools or procedures for conducting analyses, few of these states 
include readily available results of analyses their agencies have 
conducted (i.e., not accessible on their websites or through web 
searches), and no analyses conducted by tribes were identified. 
Analyses performed by local government associations for transportation 
planning purposes were available for review and included in this 
summary.
---------------------------------------------------------------------------

    \723\ See EPA-HQ-OAR-2021-0317.
    \724\ Comments also indicated several EJ studies had been 
conducted in oil and gas producing states by third parties. The 
focus of this review was on analyses conducted by state and local 
governments, although a few third-party analyses were included where 
information was readily available.
---------------------------------------------------------------------------

    Lastly, the EPA further recognizes that several comments the Agency 
received on the November 2021 Proposal and the December 2022 
Supplemental Proposal requested that the EPA be more specific about 
what the EPA would consider approvable for meaningful engagement and 
provide guidance to states (e.g., scope and degree). The EPA notes that 
as part of subpart Ba the EPA finalized procedural requirements for 
meaningful engagement as completeness criteria and is not prescribing 
how states proceed with such engagement. In particular, at 40 CFR 
60.23a(i), subpart Ba requires that states must submit, with the plan 
or revision, documentation of meaningful engagement including a list of 
identified pertinent stakeholders and/or their representatives, a 
summary of the engagement conducted, a summary of stakeholder input 
received, and a description of how stakeholder input was considered in 
the development of the plan or plan revisions. As an additional 
resource to states, the EPA compiled information that may assist states 
identify best practices for conducting meaningful engagement. This 
information can be found in a Memorandum to the public docket for this 
rulemaking titled, Summary of Strategies for Meaningful Engagement on 
Environmental Justice (EJ) Topics.\725\ This memorandum reviews over 
fifty EJ reports, policies, plans, and publications that have been 
produced by various state and local jurisdictions in the U.S. and the 
memorandum includes numerous referenced documents that pertinent 
stakeholders and other interested parties may find helpful.
---------------------------------------------------------------------------

    \725\ See EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

D. Components of State Plan Submission

    Under CAA section 111(d)(2), the EPA has an obligation to determine 
whether each state plan is ``satisfactory.'' Therefore, in addition to 
identifying the components that the EG must include, the EPA's 
implementing regulations \726\ for CAA section 111(d) (subpart Ba) 
identify additional components that a state plan must include. Many of 
these requirements are found in 40 CFR 60.23a, 60.24a, 60.25a, and 
60.26a. These provisions include requirements for components such as 
the following: procedures a state must follow for adopting a plan 
before submitting it to the EPA; the stringency of standards of 
performance and compliance timelines; emissions inventories, reporting, 
and recordkeeping; and a demonstration the state has legal authority to 
adopt and implement the plan. These requirements are also generally 
contained in a list of required state plan elements, referred to as the 
state plan completeness criteria, found at 40 CFR 60.27a(g)(2)-(3). If 
the EPA determines that a submitted plan does not meet these criteria, 
then the state is treated as not submitting a plan and the EPA has a 
duty to promulgate a Federal plan for that state. See CAA section 
111(d)(2)(A) and 40 CFR 60.27a(g)(1). If the EPA determines a plan 
submission is complete, such determination does not reflect a judgment 
on the eventual approvability of the submitted portions of the plan, 
which instead must be made through notice-and-comment rulemaking. The 
completeness criteria do not apply to states without any designated 
facilities because these states are instead directed to submit to the 
Administrator a letter of negative declaration certifying that there 
are no designated facilities, as defined by the EPA's emissions 
guidelines, located within the state. See 40 CFR 60.23a(b). No plan is 
required for states that do not have any designated facilities. 
Designated facilities located in states that mistakenly submit a letter 
of negative declaration could be subject to a Federal plan until a 
state plan regulating those facilities becomes approved by the EPA.
---------------------------------------------------------------------------

    \726\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------

    Subpart Ba of 40 CFR part 60 contains ten administrative and six 
technical criteria for complete state plans under CAA section 111(d). 
See 40 CFR 60.27a(g)(2)-(3). If a state plan does not include one of 
these established criteria, then the state plan may be deemed 
incomplete by the EPA. States that are familiar with the SIP submittal 
process under CAA section 110 will be familiar with the completeness 
criteria found in 40 CFR part 51, appendix V. While the completeness 
criteria for state plan submittals found at 40 CFR 60.27a(g)(2)-(3) are 
somewhat similar to the SIP submittal criteria in appendix V, the 
criteria are not exactly the same. As such, even states that are 
familiar with the SIP submittal process under CAA section 110 are 
strongly encouraged to

[[Page 17008]]

review the completeness criteria in 40 CFR 60.27a(g)(2)-(3) as well as 
the other state plan requirements found in 40 CFR 60.23a, 60.24a, 
60.25a, and 60.26a early in their planning process.
    In short, the administrative completeness criteria require that the 
state's plan include a formal submittal letter and a copy of the actual 
state regulations themselves, as well as evidence that the state has 
legal authority to adopt and implement the plan, actually adopted the 
plan, followed state procedural laws when adopting the plan, gave 
public notice of the changes to state law, held public hearing(s) if 
applicable, and responded to state-level comments. For a detailed 
description regarding the public hearing requirement, see 40 CFR 
60.23a. For a detailed description of what the state plan must include 
in terms of evidence that the state has legal authority to adopt and 
implement the plan, see 40 CFR 60.26a. States are strongly encouraged 
to review the state plan requirements included in 40 CFR 60.23a and 
60.26a in conjunction with the administrative completeness criteria in 
40 CFR 60.27a. Also, as explained above, the completeness criteria in 
subpart Ba now requires states to include in their plan submittals how 
they provided meaningful engagement with the pertinent stakeholders.
    The technical criteria require that the state's plan identify the 
designated facilities, the standards of performance, the geographic 
scope of the plan, monitoring, recordkeeping and reporting requirements 
(both for designated facilities to ensure compliance and for the state 
to ensure performance of the plan as a whole), and compliance 
schedules. The technical criteria further require that the state 
demonstrate that the plan is projected to achieve emission performance 
under the EG and that each emission standard is quantifiable, non-
duplicative, permanent, verifiable, and enforceable. As previously 
described, it may not be feasible to quantify certain non-numerical 
standards of performance. For a detailed description of the state plan 
requirements regarding standards of performance, see section XIV.C of 
this document and 40 CFR 60.24a.
    In addition to these technical criteria, 40 CFR 60.25a(a) requires 
that state plans include certain emissions inventory data for the 
designated facilities. As explained in section XIII.C.5 of this 
preamble, the EPA is, in this final action, superseding that 
requirement for this EG. Further, Sec.  60.25a provides a detailed 
description of what the state plan is required to include in terms of 
certain compliance monitoring and reporting. States are to review the 
state plan requirements included in 40 CFR 60.24a and 60.25a in 
conjunction with the technical completeness criteria in 40 CFR 60.27a 
to ensure their state plan submissions are complete.
    In the December 2022 Supplemental Proposal, the EPA proposed to 
include a provision within EG OOOOc regarding electronic submission of 
state plans. However, the EPA is not finalizing the provision for 
electronic submission of state plans in this rulemaking. Rather, since 
similar revisions to subpart Ba regarding electronic submission are now 
final and are therefore applicable to the EG OOOOc, state plans and 
negative declarations must be submitted according to the provisions in 
40 CFR 60.23a(3) and (b) respectively. These subpart Ba provisions 
require the electronic submission of state plans and negative 
declarations using the State Planning Electronic Collaboration System 
(SPeCS). As specified in subpart Ba, states are not to transmit CBI 
through SPeCS.\727\ The EPA found it unnecessary to also finalize 
provisions related to electronic submission within EG OOOOc because 
such provisions would be unnecessarily redundant with those now 
included in subpart Ba.
---------------------------------------------------------------------------

    \727\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------

E. Timing of State Plan Submission and Compliance Times

1. Background and Subpart Ba
    Under CAA section 111(d), each state has an 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 the 
version of 40 CFR part 60, subpart Ba that had been promulgated in 
2019. American Lung Ass'n, 985 F.3d at 991. See 86 FR 63255 (November 
15, 2021). These vacated timing requirements included: 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 governed 
the timing of these actions at the time the EPA proposed this EG in 
2021 and also at the time that the EPA issued the Supplemental Proposal 
for this EG in 2022.\728\ In a separate rulemaking in response to the 
vacatur, the EPA has now finalized new timelines in subpart Ba for 
purposes of the implementing regulations.\729\ These deadlines in 
subpart Ba are intended to apply generally to actions implementing EG 
promulgated after July 8, 2019, 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 which are further discussed in 
XIII.F.
---------------------------------------------------------------------------

    \728\ The court did not vacate the applicability provision for 
subpart Ba under 40 CFR 60.20a(a).
    \729\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------

    In the December 2022 Supplemental Proposal,\730\ for purposes of EG 
OOOOc, the EPA proposed 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. The EPA also proposed a uniform 
compliance timeline to be as expeditiously as practicable, but no later 
than 36 months following the state plan submittal deadline. Lastly, the 
EPA proposed two increments of progress. The first increment of 
progress was the submission of a final control plan by owners and 
operators within 2 years after the deadline for the state plan 
submittals. The second increment of process proposed was a notification 
of final compliance report for each designated facility on or before 60 
days after the compliance date of the state plan. The EPA proposed that 
for the notification of final compliance report, 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.
---------------------------------------------------------------------------

    \730\ See 87 FR 74831 (December 6, 2022).
---------------------------------------------------------------------------

    The EPA received comments regarding the timing of the state plan 
submission deadline and the compliance times. A summary of the comments 
received and the EPA's response to these comments, including any 
changes made to the final EG, as applicable are provided below. The 
EPA's full response to comments on the November 2021 Proposal and 
December 2022 Supplemental Proposal, including any comments not 
discussed in this preamble, can be found in the EPA's RTC document for 
the final rule.\731\
---------------------------------------------------------------------------

    \731\ Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil 
and Natural Gas Sector Climate Review. Response to Public Comments 
on the November 2021 Proposed Rule and the December 2022 
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR 
74702, December 6, 2022).
---------------------------------------------------------------------------

2. Timing of State Plan Submission
    Within the December 2022 Supplemental Proposal, the EPA proposed to 
require that each state

[[Page 17009]]

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. The EPA 
received many comments on this proposed timeline, and is finalizing a 
slightly extended deadline of 24 months after publication of the final 
EG OOOOc.
    Comments: A large number of state commenters in addition to other 
commenters expressed that the EPA's proposed 18-month state plan 
submission deadline would not provide adequate time for state plan 
development and state administrative processes for adopting a plan to 
regulate designated facilities.\732\ The commenters cite several 
concerns with the timeframe proposed. The commenters request that the 
EPA consider the impracticability of the criteria established in 40 CFR 
60.5365c of the proposed regulatory text for EG OOOOc and afford states 
greater flexibility to effectively develop a state plan. Specifically, 
a few commenters \733\ outlined factors that affect the time needed for 
states to develop and submit a plan to the EPA including the volume of 
sources, limited air regulatory experience of sources, time necessary 
to create an accurate source inventory, the proper notification to 
those sources and information requests from sources, the possible need 
for permit development, time needed for meaningful engagement and 
public participation, time needed to adopt any regulatory changes that 
would be necessary before submitting a state plan, time needed to 
develop and draft plans that include the required components, and time 
needed for adoption of the plans through their required administrative 
processes before submitting them to the EPA. Other commenters stated 
similar points and suggested that the 18-month timeframe would be 
inadequate for source-by-source equivalency determinations, and that 
states with a greater number of production wells (particularly low-
producing wells) will need additional time.\734\ The same commenters 
argue that even if states were to simply adopt the presumptive 
standards as proposed, the 18-month timeline would not provide states 
with sufficient time for meeting the requirements. They criticize the 
Agency for proposing the 18-month timeframe when the EPA itself has 
taken much longer to propose and finalize a FIP for the Uinta Basin 
ozone NAAQS. One state commenter asks that the EPA grant states with a 
substantial number of covered sources additional time as needed.\735\ 
The commenter expresses concern with regards to the significant 
workload and impact on the state resources, making it difficult to 
complete a state plan in 18-month timeframe. Several other commenters 
discuss the lengthy state administrative process and the need for 
adequate time to assess any RULOF considerations.\736\ Specifically, 
they argue in order to consider remaining useful life of a source in a 
state plan submission, states must be able to determine the compliance 
timeline by considering factors such as the source's anticipated 
retirement date, costs and benefits of an available technology, and 
technology that has already been deployed which they believe would 
necessitate additional time for these analysis.
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    \732\ Document ID Nos. EPA-HQ-OAR-2021-0317-2157, -2220, -2222, 
-2224, -2237, -2241, -2292, -2296, -2310, -2322, -2330, -2393, -
2403, -2410, -2418, -2446.
    \733\ Document ID Nos. EPA-HQ-OAR-2021-0317-2330, -2403.
    \734\ Document ID Nos. EPA-HQ-OAR-2021-0317-2446, -2241.
    \735\ Document ID Nos. EPA-HQ-OAR-2021-0317-2296, -2220.
    \736\ Document ID Nos. EPA-HQ-OAR-2021-0317-2220, -2237, -2393.
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    Specifically with regards to meaningful engagement, commenters 
discuss that the additional requirement of meaningful engagement that, 
as proposed, would have required additional outreach beyond what states 
typically conduct during a routine rulemaking and state CAA section 
111(d) plan development taking consequential time and resources 
required to fulfill those obligations to ensure state plan 
completeness.\737\ The commenter highlights the coordination that may 
be needed for meaningful engagement between a state, the EPA, and 
Tribal nations to address shared and neighboring jurisdictions. One 
commenter provides further details on the level of effort and time 
needed based on their experience of developing other state rules.\738\ 
According to the commenter, their state rulemaking process requires an 
internal draft development phase, numerous outreach meetings to 
stakeholders, and two Air Quality Advisory Board meetings. At the Air 
Quality Advisory Board meeting for one proposal, the state agency 
received significant comment that prompted additional review and 
revisions, and an Environmental Quality Council hearing. The commenter 
indicated this process took more than 18 months for development, 
stakeholder engagement, and statutory process while emphasizing that 
their example only addressed a subset of sources in one region of the 
state and that the work necessary to implement the EG will affect 
designated facilities statewide and will entail greater effort and need 
additional time. The commenter states that it would appear that the 
only workable option to states would be to adopt the model rule in the 
EG, which they argue denies states their legal right to consider a 
source's RULOF as established by the CAA.
---------------------------------------------------------------------------

    \737\ Document ID Nos. EPA-HQ-OAR-2021-0317-2220, -2222, -2393, 
-2241.
    \738\ Document ID No. EPA-HQ-OAR-2021-0317-2220.
---------------------------------------------------------------------------

    Some commenters provide a general recommendation for a minimum 24-
month timeline for state plan development and submission but many 
suggest a need provide for additional extensions for RULOF and for 
engagement with pertinent stakeholders.\739\ They tally the needed time 
to upwards of 3 years to complete state plan development.\740\
---------------------------------------------------------------------------

    \739\ Document ID Nos. EPA-HQ-OAR-2021-0317-2157, -2220, -2296, 
-2330, -2410, -2418.
    \740\ Document ID Nos. EPA-HQ-OAR-2021-0317-2222, -2225, -2237, 
-2241, -2310, -2322, -2393, -2403.
---------------------------------------------------------------------------

    On the contrary, other stakeholders argue that 18 months is too 
long.\741\ One commenter suggests that 6 to 12 months would be adequate 
time for states to submit their state plans.\742\ Other commenters urge 
the EPA to defer to the timeframe provided in the implementing 
regulations (subpart Ba).\743\ The commenters contends that the EPA did 
not provide adequate evidence in the December 2022 Supplemental 
Proposal, or the proposed implementing regulations under subpart Ba, to 
suggest that state-level administrative processes are different for 
designated facilities in the crude oil and natural gas source category 
than for any other source category, and so offers no reason why the 
proposed 18 months, rather than 15 months proposed in subpart Ba, are 
necessary to accommodate state plan development in this category. The 
commenter challenges the EPA's reasoning that EG OOOOc necessitates a 
longer timeframe due to the size and variety of emission sources in the 
source category.\744\ The commenter notes that this justification 
appears nowhere in the EG OOOOc preamble itself and does not support an 
18-month rather than 15-month submission period in any event. The 
commenter further asserts that given the urgent nature of climate 
change, the EPA must ensure that its proposed EG

[[Page 17010]]

OOOOc are implemented as swiftly as possible. The commenter urges the 
EPA to apply the proposed default 15-month timeline for state plan 
submissions proposed in subpart Ba under EG OOOOc rather than the 
extended 18-month period.
---------------------------------------------------------------------------

    \741\ Document ID Nos. EPA-HQ-OAR-2021-0317-2201, -2433.
    \742\ Document ID No. EPA-HQ-OAR-2021-0317-2201.
    \743\ Document ID Nos. EPA-HQ-OAR-2021-0317-2392, -2433.
    \744\ 87 FR 79181.
---------------------------------------------------------------------------

    Response: The proposed 18-month submittal timeline the EPA proposed 
for EG OOOOc was based on the EPA's proposed determination that this 
was a reasonably expeditious deadline that would provide states 
sufficient time to develop and submit an approvable state plan. After 
evaluation of the comments received, the EPA agrees with commenters 
that additional time is warranted for the state plan submittal for EG 
OOOOc. The EPA disagrees with commenters claiming that substantially 
less time would be adequate time for states to submit complete state 
plans. The EPA clarifies that while state-level administrative 
processes are not different for designated facilities in the crude oil 
and natural gas source category than for any other source category, 
there are numerous reasons why the EPA believes it is appropriate to 
supersede the state plan submittal timeframe of the subpart Ba 
implementing regulations in EG OOOOc. Furthermore, in the December 2022 
Supplemental Proposal (87 FR 74831 to 74835), the EPA discussed its 
considerations with respect to the characteristics and unique nature of 
the crude oil and natural gas source category in comparison to other 
EG. In response to comments on this discussion, the EPA provides 
further explanation.
    When developing a state plan submittal, the requirements of the 
recently finalized subpart Ba apply. This subpart imposes baseline 
requirements that the state must meet when developing its state plan in 
response to this EG OOOOc. Meeting those requirements takes time. There 
are also state-specific processes applicable to the development and 
adoption of a state plan, including the administrative processes (e.g., 
permitting processes, regulatory development, legislative approval) 
necessary to develop and adopt enforceable standards of performance. 
State plan development generally involves several phases, including 
providing notice that the state agency is considering adopting a rule; 
taking public comment; and approving or adopting a final rule. The 
process required to formally adopt a rule at the state level differs 
from state to state.
    Moreover, there are several recently added requirements in subpart 
Ba (for example, meaningful engagement) that states may be undertaking 
for the first time when developing their state plan submission in 
response to the final oil and natural gas EG. Further, the EPA 
generally agrees with commenters that meeting the requirements of 
subpart Ba within the context of their state plan submittal for EG 
OOOOc require time. For example, there are many diverse stakeholders 
who have equities and interests in how this industry is regulated. 
These stakeholders may submit many complex comments to the state during 
the state's plan development process. The EPA received over 470,000 
comments on the November 2021 Proposal and over 515,000 comments on the 
December 2022 Supplemental Proposal. While it would be unusual for a 
state plan to garner this same number of comments as a national 
rulemaking, it is nonetheless reasonable to assume these larger than 
typical number of comments are an indication of the increased level of 
interest that state plans are likely to receive. Since the state is 
required to include responses to comments received in their state plan 
submittal, development of plans for this EG could take longer than 
typical. Subpart Ba, 60.27a(g)(2)(viii).
    In addition to the baseline requirements of subpart Ba, these EG 
also impose unique circumstances to consider on states. For example, 
the EPA explained in the December 2022 Supplemental Proposal that EG 
OOOOc has the potential to require states to perform considerable 
engineering and/or economic analyses for their plan. For purposes of 
these EG, states will be required to establish standards of performance 
for nine different types of designated facilities, of which three have 
numerical limits and six are in the format of non-numerical standards. 
The designated facilities are also geographically spread out covering 
multiple industry segments. If a state wishes to utilize the 
flexibilities explained in section XIII.C.2 of this preamble related to 
leveraging an existing state program, determining equivalency, and/or 
averaging, then the requisite analysis can be time consuming. Contrary 
to some commenters' assertions, the EPA explained these concerns at 87 
FR 74833 and 74834 of the December 2022 Supplemental Proposal. Those 
commenters that suggest that states need less time to submit plans did 
not appear to address these concerns that the EPA expressed or the 
requirements of state laws governing the development and submission of 
plans. We still find these to be compelling reasons to allow the states 
even more time to develop and submit their plans for this EG.
    Therefore, the EPA is superseding the timeline included in subpart 
Ba and is finalizing 24 months for the timing of the state plan 
submissions for purposes of EG OOOOc. The EPA believes that 24 months 
from the time the EG is published will be adequate to complete state 
administrative processes, conduct public hearings, engage with 
pertinent stakeholders, and meet all other applicable requirements of 
subpart Ba. This timeline represents a reasonable balance between 
providing states sufficient time to develop and submit a plan that 
satisfies the applicable requirements and ensuring that the emission 
reductions contemplated in an EG are achieved as expeditiously as 
practicable. While the EPA recognizes that states need time to follow 
their state-specific processes and laws, we are also aware from the 
Agency's experience with SIPs that some states have adopted, or may 
adopt, procedures that are longer than necessary and that could delay 
Federal emission-reduction obligations. Extending the state plan 
submittal deadline beyond 24 months to account for any and all unique 
state procedures would inappropriately delay reductions in emissions 
that have been found under CAA section 111 to endanger health or the 
environment. The timeline of 24 months strikes an appropriate balance 
for this EG between the state's need for time and the EPA's 
responsibility to ensure expeditious implementation in consideration of 
the important benefits of the pollution reductions. This balance also 
comports with the court's reasoning in American Lung Ass'n (985 F.3d 
914 (D.C. Cir. 2021)).
    Furthermore, the EPA finds that 24 months will accommodate the 
challenges commenters identified and help ensure states have the time 
to ensure their plans are complete and approvable to ensure that the EG 
will be timely implemented given the urgent need of climate change. The 
EPA recognizes that the recent revisions to subpart Ba include a state 
plan submittal timeline of 18 months. To avoid any potential confusion, 
the EPA is clarifying that the state plan submittal timeline of 24 
months being finalized in this action for EG OOOOc supersedes the 
default timeline in subpart Ba, but only for purposes of those state 
plans submitted in accordance with this EG OOOOc.
3. Compliance Timelines
    Within the November 2021 Proposal, the EPA proposed to require that 
state plans require designated facilities to

[[Page 17011]]

come into full compliance with the applicable standards of performance 
as expeditiously as practicable, but no later than 2 years following 
the state plan submittal deadline. Based on comments received on the 
November 2021 Proposal, the EPA extended this timeline to 36 months in 
the December 2022 Supplemental Proposal (87 FR 74835-74837). The EPA is 
finalizing the compliance timeline of 36 months from the deadline for 
state plan submittals.
    Comments: Numerous commenters express concern that the proposed 36-
month compliance timeline does not provide adequate implementation time 
for owners and operators to accomplish successful emission reductions 
for the tens of thousands of facilities.\745\ Commenters highlight 
constraints on equipment supplies particularly for converting to zero-
emissions equipment for process controllers and pumps. The commenters 
believe that the scope and breadth of the EG will exacerbate existing 
delays in acquiring equipment on such a large scale. One commenter 
articulates that more time is needed to account for the cumulative 
burden of the multiple actions that the EPA is finalizing, and that 
owners and operators need time to understand how all the rules are 
intended to interact together.\746\
---------------------------------------------------------------------------

    \745\ Document ID Nos. EPA-HQ-OAR-2021-0317-2288, -2237, -2296, 
-2403, -2423.
    \746\ Document ID No. EPA-HQ-OAR-2021-0317-2423.
---------------------------------------------------------------------------

    Some commenters recommend that the EPA establish a final compliance 
timeline that begins with the date of the EPA's approval of the state 
plan rather than the state plan submission date.\747\ Other commenters 
state that the final compliance date should be no less than the 
proposed 36-month timeline.\748\ One commenter adds that states and 
operators are ill-equipped and unprepared to comply with the EG.\749\ 
For example, the commenter states that certain presumptive standards, 
like fugitive emissions monitoring requirements, have a regulatory 
framework that is dependent on component counts which is different than 
how some states or existing sources have tracked their facilities, so 
time is needed to understand and establish a new framework for tracking 
regulatory requirements. The commenter furthermore stresses that states 
have considerable staffing shortages and that it will take additional 
time for designated facilities and states to process necessary 
reporting requirements or updating of permits.
---------------------------------------------------------------------------

    \747\ Document ID Nos. EPA-HQ-OAR-2021-0317-2403, -2446.
    \748\ Document ID Nos. EPA-HQ-OAR-2021-0317-2288, -2237.
    \749\ Document ID No. EPA-HQ-OAR-2021-0317-2304.
---------------------------------------------------------------------------

    Other commenters take the opposite position. One commenter states 
that designated facilities should not receive additional compliance 
time at the expense of the public interest in pollution reduction, and 
urges the EPA to require accelerated compliance in states with higher 
methane emissions from designated facilities.\750\ Several other 
commenters suggest that for standards that do not require the 
installation of new equipment, the compliance timeline should be 
accelerated.\751\ They identify that designated facilities other than 
oil wells with associated gas, storage vessels, process controllers, 
and pumps, such as alternative leak detection programs, should be 
placed on faster compliance timelines. According to commenters, 
fugitive and leak detections programs and alternative leak detection 
programs can be implemented relatively quickly and inexpensively as 
compared to equipment retrofits. They believe that the EPA has failed 
to justify why such a lengthy compliance period would be necessary for 
these types of sources. The commenter adds that the desire to simplify 
compliance and ease the burden on industry operators is not a valid 
basis for this timeframe under the statute and not warranted by these 
circumstances. Furthermore, they argue that leak detection standards 
are not impacted by supply chain and logistical issues in the same way 
as standards requiring equipment procurement and possible shutdowns of 
designated facilities, such as standards for process controllers, 
pumps, and storage vessels. The commenters suggest a shortened timeline 
for compliance for these facilities of no more than 6 months to 1 year 
after the EPA's approval of a state plan.
---------------------------------------------------------------------------

    \750\ Document ID No. EPA-HQ-OAR-2021-0317-1659.
    \751\ Document ID Nos. EPA-HQ-OAR-2021-0317-2028, -2284, -2392, 
-2410, -2433.
---------------------------------------------------------------------------

    Commenters advocating for an earlier compliance timeline for some 
sources identify the advantages of phasing-in leak detection programs 
for EG OOOOc and recommend incentivizing earlier compliance. For 
example, the commenter asks the EPA to consider incentivizing a 
separate, earlier phase-in period for control strategies that do not 
involve significant capital expenditures or retrofits which could be 
used to balance emissions from areas of the rule that may require 
additional time to implement. The commenters suggest the EPA consider 
adopting a shorter timeline than proposed, such as 24 to 30 months 
after plan submission deadlines, for sources that do not require 
capital expenditures for compliance. Another commenter recommends that 
the EPA reconsider whether to accelerate the timeline for compliance 
for specific performance standards.\752\ The commenter notes that the 
EPA should reconsider whether the benefits of the proposed three-year 
uniform deadline may be overstated and whether the urgency of the 
health and environmental harms that state plans will address merits a 
shorter deadline for compliance to increase net benefits for society. 
According to the commenter, the EPA has given some consideration to the 
need for expeditious compliance, but given the December 2022 
Supplemental Proposal's significant health and environmental benefits, 
the EPA should reevaluate the feasibility of a more aggressive 
compliance schedule that would allow these benefits to be realized 
sooner. The commenter recommends that to select which standards of 
performance merit an earlier compliance deadline, the EPA should apply 
the nine factors that the EPA identified for this purpose in the 
December 2022 Supplemental Proposal (e.g., supply-chain issues).\753\ 
However, in lieu of the existing second and ninth factors (``[t]he cost 
of equipment'' and ``overall methane emissions reduction that will 
result from control of existing sources under the [emissions 
guideline]''), the commenter suggests that it would be preferable to 
examine net benefits. Compared to methane emissions reductions alone, 
looking to net benefits would allow for consideration of all relevant 
costs and benefits--including benefits from methane's co-pollutants 
emitted along with methane--when evaluating whether to prioritize 
compliance with one standard of performance over another. The commenter 
continues that, the nine factors indicate that the EPA should 
substantially shorten the timeline for existing sources to comply with 
the super-emitter response program. The EPA's concerns about the costs 
of simultaneous implementation across the sector and planning burdens 
do not apply to this program. For the same reasons that 14 days is too 
long to wait before acting on a single super-emitter event, the 
commenter states that 3 years is too long to wait for the entire 
program. The commenter suggests that, in instances where the EPA has

[[Page 17012]]

differentiated between subcategories of affected facilities, the EPA 
should further consider accelerating compliance for select 
subcategories if doing so appears more net beneficial than subjecting 
all designated facilities to the same deadline. The commenter provides 
that staggering compliance across tiers within a single EG could reduce 
the planning burden on entities in a given year and help prevent 
bottlenecks for specialized equipment and services by spreading 
compliance deadlines out over time. For instance, the commenter points 
out the consideration of fugitive emissions at wells, a category that 
the EPA already divides into four tiers with different monitoring 
requirements based on the number of wells at the site and the presence 
of major equipment. The commenter states that the EPA could apply the 
same nine factors discussed above to designate one or more tiers of 
wells subject to an accelerated compliance timeline. The commenter adds 
that the EPA could conduct a similar assessment for its four potential 
subcategories for pneumatic controllers (well sites, gathering and 
boosting stations, transmission and storage compressor stations, and 
natural gas processing plants). The commenter notes that this tiering 
of compliance deadlines may increase net benefits relative to waiting 3 
years for all four tiers because a subset of the December 2022 
Supplemental Proposal's benefits would be achieved sooner and thus 
accrue over the additional time. While annual costs would also accrue 
over the additional time, the commenter believes that the benefits 
would most likely exceed the costs to the same extent as they are 
projected to do so for future years.
---------------------------------------------------------------------------

    \752\ EPA-HQ-OAR-2021-0317-2343.
    \753\ See Table 38 in the December 2022 Supplemental Proposal at 
87 FR 74835.
---------------------------------------------------------------------------

    Response: The EPA disagrees with the comments suggesting additional 
time is necessary. When the compliance timeline of 36 months is 
considered in conjunction with the state plan submittal deadline of 24 
months, that means that sources could have up to 5 years between when 
the EG are final and when they are required to fully comply with the 
applicable standards of performance. The EPA believes that any concerns 
with possible equipment or staffing shortages, which commenters 
speculate could be an issue, would likely be addressed by industry and 
regulators in that timeframe. The EPA did evaluate the types of factors 
that commenters raised, as explained in the December 2022 Supplemental 
Proposal (87 FR 74835, table 38). After re-considering these factors in 
conjunction with the comments received on the December 2022 
Supplemental Proposal, the EPA still finds that 36 months is 
appropriate because commenters did not present the EPA with convincing 
information to suggest that the assumptions made in the 2022 
Supplemental Proposal were inaccurate.
    The EPA agrees to a certain extent with some comments that suggest 
the Agency could have taken a different approach wherein we could have 
established different compliance timelines for different types of 
designated facilities. The EPA discussed this consideration in the 
December 2022 Supplemental Proposal at 87 FR 74836. After considering 
comments, the EPA still believes that it is appropriate to finalize a 
uniform outermost compliance deadline for purposes of these EG. In 
addition to the reasoning for preferring uniformity and easing burden 
explained in the December 2022 Supplemental Proposal, which the EPA 
believes to still hold true (and which commenters do not appear to take 
direct issue with), the EPA believes that many of the issues raised by 
commenters could be more appropriately addressed by states during plan 
development. The EPA highlights that this compliance deadline included 
in the final EG represents the furthest date into the future that the 
EPA finds appropriate for a state to allow as a final compliance 
deadline for the state's standards of performance. Put another way, the 
36-month timeline is the most time that the EPA believes a state will 
need to allow for sources to come into compliance. However, states are 
free to establish compliance timelines within their state plan 
submittals for certain designated facilities that are shorter than 36 
months, and indeed states should be examining shorter timelines as a 
possibility to ensure that sources come into compliance with their 
respective standards of performance as expeditiously as practicable. 
Subpart Ba is clear that ``final compliance shall be required as 
expeditiously as practicable, but no later than the compliance times 
specified in an applicable subpart of this part.'' By finalizing the 
outermost compliance deadline of 36 months, the EPA is not suggesting 
that it is necessarily appropriate for all compliance timelines in all 
state plans to be set at 36 months. On the contrary, states must 
require designated facilities to come into final compliance with their 
standards of performance ``as expeditiously as practicable.'' The time 
needed for particular groups of existing sources to come into full 
compliance with a state's standards depends on many factors including 
the specifics of that yet-to-be-determined standard as well as the 
preexisting regulatory framework, if any. The EPA cannot account for 
all these possible variables when establishing these EG, but states 
can, and should, account for specific circumstances in their state 
plans because they will have the relevant facts available to them when 
developing their state plan submittals.

F. The EPA's Action on State Plans and Promulgation of Federal Plans

    The EPA finalized deadlines for its action on state plan 
submissions and for promulgation of a Federal plan in a separate 
rulemaking for the implementing regulations (subpart Ba).\754\ See 40 
CFR 60.27a. Unless superseded by a particular EG, the subpart Ba 
deadlines apply generally to all EG promulgated after July 8, 2019, 
under CAA section 111(d), and also apply to the EPA's action on state 
plan submissions and promulgation of a Federal plan under the final EG. 
The EPA is not superseding the deadlines in the final oil and natural 
gas EG OOOOc. As such, the deadlines included in the final revisions 
for subpart Ba for the EPA action on a state plan submit and for 
promulgation of a Federal plan apply in the context of this EG.
---------------------------------------------------------------------------

    \754\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------

    As discussed in the November 2021 Proposal and December 2022 
Supplemental Proposal, it was not necessary for the EPA to propose 
deadlines for the EPA's action on state plans submitted in response to 
a final EG OOOOc, or for the promulgation of a Federal plan where a 
state fails to submit an approvable plan, as part of the November 2021 
Proposal or December 2022 Supplemental Proposal, because these 
deadlines are not relevant to states in the development of their plans. 
Additionally, as described in section XIII.E of this document, the EPA 
proposed and is finalizing in EG OOOOc the final compliance schedule 
for designated facilities to run from the deadline for state plan 
submissions.
    The EPA subsequently provides this process information for 
stakeholder awareness. While CAA section 111(d)(1) authorizes states to 
develop state plans that establish standards of performance and 
provides states with certain discretion in determining the appropriate 
standards, CAA section 111(d)(2) provides the EPA a specific oversight 
role with respect to such state plans. CAA section 111(d)(2) authorizes 
the EPA to prescribe a Federal plan for a state ``in cases where the 
state fails to submit a satisfactory plan.'' The states must therefore 
submit their plans to the

[[Page 17013]]

EPA, and the EPA must evaluate each state plan to determine whether 
each plan is ``satisfactory.'' The EPA's implementing regulations for 
CAA section 111(d) accordingly provide procedural requirements for the 
EPA to make such a determination. See 40 CFR 60.27a.
    Upon receipt of a state plan, the EPA is first required to 
determine whether the state plan submittal is complete in accordance 
with the completeness criteria explained above. See 40 CFR 60.27a(g). 
Per the finalized amendments to subpart Ba, the EPA has 12 months to 
act on a state plan after the plan is deemed complete. Id. at 
60.27a(b). If the EPA determines that the state plan submission is 
incomplete, then the state will be treated as not having made the 
submission, and the EPA would be required to promulgate a Federal plan 
for the designated facilities in that state within 12 months. Likewise, 
if a state does not make any submission by the applicable deadline for 
state plan submissions, then the EPA is required to promulgate a 
Federal plan within 12 months. If the EPA does not make an affirmative 
determination regarding completeness of the state plan submission 
within 60 days of receiving the submittal, then the submission is 
deemed complete by operation of law.
    If a state has submitted a complete plan, then the EPA is required 
to evaluate that plan submission for approvability in accordance with 
the CAA, the EPA's implementing regulations, and the applicable EG. The 
EPA may approve or disapprove the state plan submission in whole or in 
part. See 40 CFR 60.27a(b). If the EPA approves the state plan 
submission, then that state plan becomes Federally enforceable. If the 
EPA disapproves the required state plan submission, in whole or in 
part, then the EPA is required to promulgate a Federal plan for the 
designated facilities in that state via a notice-and-comment 
rulemaking, and with an opportunity for public hearing. In the case of 
a disapproval, the scope of the disapproval (in whole or in part) 
defines the scope of the EPA's duty to issue a Federal plan. The EPA 
will also promulgate a Federal plan if a state fails to submit a plan 
by the state plan submission deadline and if a state submission is 
determined to be incomplete. See 40 CFR 60.27a(c) and (f). The EPA 
would not be required to promulgate the Federal plan if the state 
corrects the deficiency giving rise to the EPA's duty and the EPA 
approves the state's plan before promulgating the Federal plan. 
Requirements regarding the content of a Federal plan are included in 40 
CFR 60.27a(e).

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

    Under the 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 TIP implementing the EG. If a Tribe obtains 
approval and submits a TIP, the EPA will generally use similar criteria 
and follow similar procedures as those described above for state plans 
when evaluating the TIP submission, and will approve the TIP if 
appropriate. The EPA is committed to working with eligible Tribes to 
help them seek authorization and develop plans if they choose. Tribes 
that choose to develop plans will generally have the same flexibilities 
available to states in this process. If a Tribe does not seek and 
obtain the authority from the EPA to establish a TIP, the EPA has the 
authority to establish a Federal plan under CAA section 111(d) for 
areas of Indian country where designated facilities are located. A 
Federal plan would apply to all designated facilities located in the 
areas of Indian country covered by the Federal plan unless and until 
the EPA approves an applicable TIP applicable to those facilities.

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

A. Summary of Requirements

    In this action, the EPA is finalizing a protocol for the use of OGI 
as appendix K to 40 CFR part 60. The EPA notes that while this protocol 
is being finalized in this action, the applicability of the protocol is 
broader. The protocol is applicable to facilities when specified in a 
referencing subpart to help determine the presence and location of 
leaks; it is not currently applicable for use in direct emission rate 
measurements from sources. The protocol does not on its own apply to 
any sources; it applies only where a specific rule subpart incorporates 
it by reference and specifies the sources to which it applies. In this 
case, we are finalizing the use of the protocol only for implementing 
the standards for process units at natural gas processing plants that 
are being finalized in this action.
    Once incorporated into a subpart, the protocol would only be 
applicable for 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. Additionally, the OGI camera used for surveying must 
also be capable of detecting (or producing a detectable image of) 
methane emissions of 19 g/hr and either butane emissions of 29 g/hr or 
propane emissions of 22 g/hr at a viewing distance of 2.0 meters and a 
delta-T of 5.0 [deg]C in an environment of calm wind conditions around 
1.0 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.
    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 cases where an operating envelope has not yet been established 
for an OGI camera model or an OGI camera operator needs to expand an 
operating envelope to account for site-specific conditions, the OGI 
camera operator can conduct a daily field check for maximum viewing 
distance prior to conducting the monitoring survey. The daily field 
check must be conducted for each OGI camera operator who will conduct 
the monitoring survey using the OGI camera (and each camera 
configuration) they will use to complete

[[Page 17014]]

the monitoring survey. The daily field check must be performed using 
the same gases and flow rates used for setting the operating envelope 
and initial verification check. The maximum viewing distance for the 
day for the OGI camera operator will be the farthest viewing distance 
where the OGI camera operator is able to visualize a leak of both test 
gases. A complete video record, as well as documentation of the delta-
T, wind speed, and viewing distance, must be retained for the daily 
field check. If the delta-T in the field decreases below the delta-T 
that was recorded for the daily field check or if the wind speed 
increases above the wind speed recorded for the daily field check, the 
maximum viewing distance determination must be repeated for the new 
delta-T and wind speed conditions. A description of how the OGI camera 
operator will monitor viewing distance, delta-T, and wind speed must be 
included in the monitoring plan.
    Each site must 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, how 
the operator will ensure an adequate delta-T is present in order to 
view potential gaseous emissions, operator rest breaks, documenting 
surveys, and quality assurance.
    The EPA is finalizing requirements to view each component from at 
least two different angles. The OGI camera operator must dwell on each 
angle for a minimum time, where dwell time is defined as the time the 
scene is steady and in focus and the operator is actively viewing the 
scene. For a simple scene consisting of 10 or fewer components, the 
camera operator must dwell for a minimum of 10 seconds per angle. For a 
scene with greater than 10 components, the camera operator must dwell 
for a minimum of 2 seconds per component in the field of view.
    Each facility or company performing 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. 
Appendix K prescribes a multi-faceted approach to training. Training 
includes classroom instruction (either online, remotely, 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 2 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.
    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.
    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 
publication date of this final rule 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.
    Appendix K requires records 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.

B. Changes Since Supplemental Proposal

    This section of this preamble presents a summary of significant 
comments received on the EPA's protocol for the use of OGI in leak 
detection being finalized as appendix K to 40 CFR part 60 (referred to 
hereafter as appendix K) and the EPA's response to those comments. This 
section also presents changes that have been made to appendix K since 
the December 2022 Supplemental Proposal.
1. Dwell Time
    Comment: Several commenters suggested that the dwell time 
requirement in appendix K should be

[[Page 17015]]

removed.\755\ The commenters felt that the dwell time requirements were 
overly restrictive, and dwell time should be left to the discretion of 
the trained operator. One commenter \756\ stated that the proposed 
viewing requirements would increase survey time approximately four-
fold. Commenters were also critical of the proposed allowance for 
reduction of the dwell time for complex scenes based on the monitoring 
area and number of components according to table 14-1 of appendix 
K.\757\ These commenters argued that dwell times and angles are 
unnecessary, burdensome, and impractical to implement.
---------------------------------------------------------------------------

    \755\ EPA-HQ-OAR-2021-0317-2177, -2258, -2421, -2428, and -2196.
    \756\ EPA-HQ-OAR-2021-0317-2483.
    \757\ EPA-HQ-OAR-2021-0317-2366 and -2483.
---------------------------------------------------------------------------

    Some commenters provided suggestions for alternative dwell times. 
One commenter \758\ suggested that a minimum of 3 seconds per scene 
would be appropriate, while another commenter \759\ recommended a 
maximum dwell time of 5 seconds per angle of view for scenes with 
multiple components. A third commenter \760\ suggested that scenes be 
differentiated according to the number of components being imaged and 
viewing distance. The commenter stated that an example of a ``simple'' 
scene would be a scene of 20-25 components viewed from a distance of 
15-25 feet. The commenter stated that this approach offers a high 
probability of leak detection by a technician and limiting the number 
of components to 25 in a simple scene means a technician is likely to 
have great discernment or granularity of the image which improves the 
ability to detect a leak.
---------------------------------------------------------------------------

    \758\ EPA-HQ-OAR-2021-0317-2305.
    \759\ EPA-HQ-OAR-2021-0317-2421.
    \760\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA considers dwell time an important component of an 
OGI monitoring protocol. It is important to specify the minimum amount 
of time that OGI camera operators must survey a scene in order to 
reliably assess whether leaks are present. Surveying a scene too 
quickly can lead to OGI camera operators not identifying leaks, 
potentially leading to an increase in fugitive emissions over time by 
leaving the leaks unaddressed. The EPA therefore disagrees with the 
comment suggesting removal of the dwell time requirement.
    To be clear on our intent, in the final rule, the EPA has clarified 
that the dwell time requirements in appendix K represent the minimum 
amount of time required to survey a scene in order to provide adequate 
probability of leak detection, and that dwell time begins only after 
the OGI camera operator has put the camera in an appropriate operating 
mode and the scene is in focus and steady. If the OGI camera operating 
mode must be changed, the dwell time restarts. We have further 
clarified that additional dwell time beyond the minimum requirement may 
be necessary to adequately monitor for leaks, depending on conditions 
and configuration of the components. OGI camera operators should use 
training and knowledge of conditions to adjust dwell time when needed.
    However, the EPA agrees with commenters that allowing for a 
standard dwell time instead of requiring the dwell time to be based on 
the number of components is appropriate in some instances. In the final 
rule, the EPA is removing table 14-1 in the proposed appendix K, which 
was a mechanism intended to allow a reduction in dwell time by reducing 
the number of components being visualized at one time. Instead, the EPA 
is finalizing a standard dwell time requirement for ``simple'' scenes. 
To implement this change, we have created a definition for a simple 
scene in appendix K, where a simple scene is defined as a scene 
consisting of 10 or fewer components. For a simple scene, the OGI 
camera operator must dwell for a minimum of 10 seconds per angle. The 
EPA disagrees that a standard dwell time should be extended to scenes 
that do not qualify as a simple scene (i.e., a scene with greater than 
10 components) because these scenes are often very complex with 
complicated backgrounds and an increased density of components. These 
factors make it more difficult for OGI camera operators to visualize 
the individual components in the scene, and an OGI camera operator 
needs to spend more time looking at the individual components to ensure 
there are no leaks. For these scenes, the EPA is retaining the 
requirement, as proposed, that the OGI camera operator must dwell on 
the scene for a minimum of 2 seconds per component in the field of 
view. As we noted in the December 2022 Supplemental Proposal,\761\ 2 
seconds per component in the field of view aligns closely with the 
estimated time to complete a monitoring survey based on data provided 
by OGI camera operators and provides adequate time to determine whether 
a leak is present. Although commenters suggested different timeframes 
for a minimum dwell time, the commenters did not provide substantive 
information on why these different minimum dwell times would ensure 
that an OGI camera operator views a scene long enough to find all leaks 
that exist. The EPA notes that OGI camera operators can choose to 
reduce the dwell time of these more complex scenes by reducing the 
viewing distance from components, thereby reducing the number of 
components in the field of view and changing the more complex scene 
into a simple scene. This would allow the OGI camera operator to use 
the standard dwell time for simple scenes.
---------------------------------------------------------------------------

    \761\ 87 FR 74839 (December 6, 2022).
---------------------------------------------------------------------------

2. Detection Limits
    Comment: One commenter \762\ agreed with the new minimum detection 
level of butane as 5 grams per hour (g/hr) but questioned the level of 
detection for propane. The commenter stated that the foundation of 
appendix K and OGI as a technology is based on the response factors, 
per section 6.1.1 and Annex 1 of appendix K. Therefore, the commenter 
states that propane (a compound with a response factor of 1.000) should 
not have a detection threshold higher than methane (a compound with a 
response factor of 0.297). The commenter recommended that propane have 
a minimum detection level similar to butane, 5 g/hr, since it is also 
over 3.3 times more absorptive for the defined technology in the 
spectral range of the technology, and the commenter suggested that all 
references to the minimum detection threshold of propane in section 8 
also be changed to 5 g/hr. Another commenter \763\ questioned why a 
lower mass rate criteria was selected for butane when the response 
factor for butane and propane are almost identical. The commenter 
stated that this seems inconsistent with the language in section 1.2, 
which allows for the average response factor approach with respect to 
propane.
---------------------------------------------------------------------------

    \762\ EPA-HQ-OAR-2021-0317-2421.
    \763\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA reviewed the detection limit criteria included in 
the December 2022 Supplemental Proposal in light of the comments and 
updated the TSD for appendix K. As noted in the updated TSD that 
accompanies the final appendix K, the expected field detection limit of 
propane is 22 g/hr. Based on this detection limit and updated response 
factors \764\ for methane and n-butane, we have determined that the 
field detection limits of methane and n-butane are 19 g/hr and 29 g/hr, 
respectively. It may seem

[[Page 17016]]

counterintuitive that propane has a greater detection limit than 
methane, even though propane has a higher response factor. This is due 
to the difference in the molecular weights of the compounds. Molecular 
weight is used to convert between the concentration (ppmv) and mass 
flowrate (g/hr). Because propane is nearly three times as heavy as 
methane, the detection limit for propane, when expressed as a mass 
flowrate, is higher than the detection limit for methane. Similarly, 
butane is heavier than propane, so the detection limit expressed as a 
mass flowrate is higher for butane than for propane.\765\
---------------------------------------------------------------------------

    \764\ See August 18, 2023, email from Yousheng Zeng to Gerri 
Garwood, included in the docket for this action.
    \765\ See TSD, Optical Gas Imaging Protocol (40 CFR part 60, 
Appendix K). September 2023. Pages 124-125.
---------------------------------------------------------------------------

    While we note that the laboratory detection limits will be lower 
than this, as demonstrated in the supporting documentation provided in 
the OGI detection estimation memo \766\ included in the docket, because 
the detection limits in appendix K are used to set the operating 
envelope, it is important that they are achievable in the field, not 
just the laboratory. We have updated the final appendix K TSD and final 
text within appendix K to reflect these updated detection limits. We 
have also updated the final appendix K TSD to discuss the derivation of 
the field detection limits for compounds other than propane.
---------------------------------------------------------------------------

    \766\ EPA-HQ-OAR-2021-0317-1532.
---------------------------------------------------------------------------

3. Operating Envelopes
    Comment: One commenter \767\ stated the operating envelope is 
overly complicated and that daily field checks ensure the camera 
operator can identify fugitive emissions and set a maximum viewing 
distance. The commenter suggested that a change in weather that could 
significantly alter the viewing distance could trigger a retest to 
ensure the viewing distance set point is still adequate to identify 
fugitive emissions. Another commenter \768\ maintained that most OGI 
camera manufacturers plan to have completed the development of the 
operating envelopes after appendix K is promulgated but urged that a 
daily or site-specific distance check should remain an option. The 
commenter acknowledged that there may be times when OGI camera 
operators will be using an OGI camera that does not yet have any 
established operating envelopes either because the camera manufacturer 
has yet to publish operating envelopes once appendix K is promulgated, 
the OGI camera is new to market, or monitoring conditions for a 
specific survey or site are unique regarding the pre-defined operating 
envelopes and the camera operator may want to ensure that the delta-T 
and viewing distance are appropriately set.
---------------------------------------------------------------------------

    \767\ EPA-HQ-OAR-2021-0317-2305.
    \768\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------

    Response: The EPA agrees that there may be times when an OGI camera 
model does not yet have an established operating envelope, such as 
immediately after development of the OGI camera, or when an OGI camera 
operator may need to adjust an operating envelope to account for site-
specific conditions, such as wind speed. In the final appendix K, the 
EPA has added an option to conduct a daily field check for distance in 
lieu of using a pre-defined operating envelope. The EPA notes that this 
is an optional field check for distance when an OGI camera operator is 
not using a pre-defined operating envelope. For OGI camera operators 
using a pre-defined operating envelope, this daily distance check is 
not required.
    If an OGI camera operator chooses to use this optional daily field 
check for distance, it must be documented. The daily field check must 
use the same gases at the same flow rate as those specified in section 
6.1.2 for the initial verification check and development of the 
operating envelopes. The daily field check must be conducted by the OGI 
camera operator(s) who will be conducting the monitoring survey using 
the OGI camera(s) that will be used to conduct the monitoring survey. 
If the OGI camera operator encounters delta-T values that are lower 
than or wind speed values that are higher than the values during the 
daily field check, the distance check must be repeated.
4. Other Changes
    Additionally, the EPA has made a number of clarifications and minor 
adjustments to the text of appendix K in response to comments received:
    <bullet> Added definitions for OGI camera operator, simple scene, 
and survey hour.
    <bullet> Adjusted the specifications for instrumentation described 
in section 6.2 that is used for the initial verification of the camera 
specifications.
    <bullet> Added specifications for coordinates when global 
positioning systems are used to document the path taken by the OGI 
camera operator.
    <bullet> Removed the language that allows for full video records in 
lieu of video clips or photographs. We are clarifying that a full video 
record does suffice for video clips of leaks, but the addition of the 
language in the supplemental proposal caused unintended confusion to 
commenters.
    <bullet> Reduced the audit frequency for OGI camera operators from 
quarterly to semiannually.
    <bullet> In Annex 1, changed the pixel count for each area from a 
minimum of 1 to 0.5 percent of the total pixels of the detector.
    <bullet> In Annex 1, changed the minimum number of measured 
infrared radiance pixel area within a data set to 1000 data points.

XV. Prevention of Significant Deterioration and Title V Permitting

    This final rule regulates GHGs (in the form of methane limitations) 
under CAA section 111. Because regulation of GHGs under CAA section 111 
could have implications for other EPA rules and for permits written 
under the CAA PSD preconstruction permit program and the CAA title V 
operating permit program, the EPA is including provisions in this final 
rule that explicitly address some of these potential implications, 
consistent with our experience in prior rules regulating GHGs. The EPA 
included and explained the basis for similar provisions when 
promulgating 2016 NSPS OOOOa, as well as the 2015 subpart TTTT NSPS for 
electric utility generating units. See 81 FR 35823, 35871 (June 3, 
2016) and 80 FR 64509, 64628 (October 23, 2015). The discussion in 
these prior rule preambles equally applies to the oil and gas sources 
subject to NSPS OOOOb and EG OOOOc.
    In summary, in light of the U.S. Supreme Court's decision in 
Utility Air Regulatory Group v. Environmental Protection Agency, 573 
U.S. 302 (2014) (UARG), the EPA may not treat GHGs as an air pollutant 
for purposes of determining whether a source is a major source (or 
modification thereof) for the purpose of PSD applicability. Certain 
portions of the EPA's PSD regulations (specifically, the definition of 
``subject to regulation'') effectively ensure that most sources will 
not trigger PSD solely by virtue of their GHG emissions. E.g., 40 CFR 
51.166(b)(48)(iv), 52.21(b)(49)(iv). However, the EPA's PSD regulations 
(specifically, the definition of ``regulated NSR pollutant'') provide 
additional bases for PSD applicability for pollutants that are 
regulated under CAA section 111. To address this latter component of 
PSD applicability, the EPA is adding provisions within the subpart 
OOOOb NSPS and subpart OOOOc EG to help clarify that the promulgation 
of GHG standards under section 111 will not result in additional 
sources becoming subject to PSD based solely on GHG emissions, which 
would be contrary to the holding in UARG. See 40 CFR

[[Page 17017]]

60.5360b(b)(1)-(2), 60.5361c(b)(1)-(2). These provisions are similar to 
those in the 2016 NSPS OOOOa and other section 111 rules that regulate 
GHGs. See, e.g., 40 CFR 60.5360a(b)(1)-(2), 60.5515(b)(1)-(2).
    The EPA understands there are also concerns that if methane were to 
be subject to regulation as a separate air pollutant from GHGs, sources 
that emit methane above the PSD thresholds or modifications that 
increase methane emissions could be subject to the PSD program. To 
address this concern and for purposes of clarity, the EPA is adopting 
regulatory text within subpart OOOOb NSPS and subpart OOOOc EG to 
clarify that the air pollutant that is subject to regulation is GHGs, 
even though the standard is expressed in the form of a limitation on 
emissions of methane. See 40 CFR 60.5360b(a), 60.5361c(a). This 
language is substantially similar to language found in, for example, 
the 2016 NSPS OOOOa and other rules. See, e.g., 40 CFR 60.5360a(a), 
60.5515(a).
    For sources that are subject to the PSD program based on non-GHG 
emissions, the CAA continues to require that PSD permits satisfy the 
best available control technology (BACT) requirement for GHGs. Based on 
the language in the PSD regulations, the EPA and states may continue to 
limit the application of BACT to GHG emissions in those circumstances 
where a new source emits GHGs in the amount of at least 75,000 tpy on a 
CO<INF>2</INF> Eq. basis or an existing major source increases 
emissions of GHGs by more than 75,000 tpy on a CO<INF>2</INF> Eq. 
basis. See 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv). The revisions to 
the regulatory text within subparts OOOOb NSPS and OOOOc EG ensure that 
this BACT applicability level remains operable to sources of GHGs 
regulated under CAA section 111, as have similar revisions in prior 
rules. See 40 CFR 60.5360b(b)(1)-(2), 60.5361c(b)(1)-(2); see also, 
e.g., 40 CFR 60.5360a(b)(1)-(2), 60.5515(b)(1)-(2). This rule does not 
require any additional revisions to SIPs.
    Regarding title V, the UARG decision similarly held that the EPA 
may not treat GHGs as an air pollutant for purposes of determining 
whether a source is a major source for the purpose of title V 
applicability. Promulgation of CAA section 111 requirements for GHGs 
will not result in the EPA imposing a requirement that stationary 
sources obtain a title V permit solely because such sources emit or 
have the potential to emit GHGs above the applicable major source 
thresholds.\769\
---------------------------------------------------------------------------

    \769\ The additional regulatory text in the final rule further 
ensures that title V regulations are not applied to GHGs solely 
because they are regulated under CAA section 111. See 40 CFR 
60.5360b(b)(3)-(4), 60.5361c(b)(3)-(4); see also, e.g., 40 CFR 
60.5360a(b)(3)-(4), 60.5515(b)(3)-(4). The EPA understands that 
concerns regarding the regulation of methane as a separate air 
pollutant (described with respect to PSD) also apply to title V. The 
EPA's regulatory text here in this final rule--clarifying that the 
pollutant subject to regulation is GHGs--similarly addresses these 
concerns with respect to title V. See 40 CFR 60.5360b(a), 
60.5361c(a).
---------------------------------------------------------------------------

    To be clear, however, unless exempted by the Administrator through 
regulation under CAA section 502(a), any source, including a ``non-
major source,'' subject to a standard or regulation under CAA section 
111 is required to apply for, and operate pursuant to, a title V permit 
that ensures compliance with all applicable CAA requirements for the 
source, including any GHG-related applicable requirements. This aspect 
of the title V program is not affected by UARG.\770\ The EPA is 
including an exemption from the obligation to obtain a title V permit 
for sources subject to NSPS OOOOb and EG OOOOc, unless such sources 
would otherwise be required to obtain a permit under 40 CFR 70.3(a) or 
40 CFR 71.3(a), as the EPA did in NSPS OOOO and OOOOa.\771\ See 40 CFR 
60.5360b(c); see also 40 CFR 60.5370, 60.5370a. However, sources that 
are subject to the CAA section 111 standards promulgated in this rule 
and that are otherwise required to obtain a title V permit under 40 CFR 
70.3(a) or 40 CFR 71.3(a) will be required to apply for, and operate 
pursuant to, a title V permit that ensures compliance with all 
applicable CAA requirements, including any GHG-related applicable 
requirements.
---------------------------------------------------------------------------

    \770\ See Memorandum from Janet G. McCabe, Acting Assistant 
Administrator, Office of Air and Radiation, and Cynthia Giles, 
Assistant Administrator, Office of Enforcement and Compliance 
Assurance, to Regional Administrators, Regions 1-10, Next Steps and 
Preliminary Views on the Application of Clean Air Act Permitting 
Programs to Greenhouse Gases Following the Supreme Court's Decision 
in Utility Regulatory Group v. Environmental Protection Agency (July 
24, 2014) at 5.
    \771\ The EPA provided the rationale for exempting this source 
category from the title V permitting requirements during the 
rulemaking for the 2012 NSPS OOOO. See 76 FR 52737, 52751 (August 
23, 2011). That rationale continues to apply to this source 
category.
---------------------------------------------------------------------------

XVI. Summary of Cost, Environmental, and Economic Impacts

A. What are the air quality impacts?

    The EPA projected that, from 2024 to 2038, relative to the 
baseline, the final NSPS OOOOb and EG OOOOc will reduce about 58 
million short tons of methane emissions (1.5 billion tons 
CO<INF>2</INF> Eq. using a GWP of 28), 16 million short tons of VOC 
emissions, and 590 thousand short tons of HAP emissions from affected 
facilities. The EPA projected regulatory impacts beginning in 2024 as 
that year represents the first full year of implementation of the final 
NSPS OOOOb. The EPA assumes that emissions impacts of the final EG 
OOOOc will begin in 2028. The EPA projected impacts though 2038 to 
illustrate the accumulating effects of this rule over a longer period. 
The EPA did not estimate impacts after 2038 for reasons including 
limited information, as explained in the RIA.

B. What are the secondary impacts?

    The energy impacts described in this section of this document are 
those energy requirements associated with the operation of emissions 
control devices. Potential impacts on the national energy economy from 
the rule are discussed under economic impacts in section XVI.D of this 
document. There will likely be minimal change in emissions control 
energy requirements resulting from this rule. Additionally, this final 
action continues to encourage the use of emissions controls that 
recover hydrocarbon products that can be used onsite as fuel or 
reprocessed within the production process for sale.

C. What are the cost impacts?

    The EAV of the regulatory compliance cost associated with the final 
NSPS OOOOb and EG OOOOc over the 2024 to 2038 period was estimated to 
be $1.5 billion per year using a 2-percent discount rate (in 2019 
dollars), $1.5 billion per year using a 3-percent discount rate, and 
$1.6 billion using a 7-percent discount rate. The corresponding 
estimates of the PV of compliance costs were $19 billion using a 2-
percent discount rate, $18 billion using a 3-percent discount rate, and 
$14 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 final 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 final rule over the 2024 to 2038

[[Page 17018]]

period were estimated to be $2.4 billion using a 2-percent discount 
rate, $2.4 billion using a 3-percent discount rate, and $2.4 billion 
per year using a 7-percent discount rate. The PV of these costs were 
estimated to be $31 billion using a 2-percent discount rate, $29 
billion using a 3-percent discount rate, and $22 billion using a 7-
percent discount rate.

D. What are the economic impacts?

    The EPA conducted a suite of economic impact and distributional 
analyses for this rule, as detailed in section 4 of the final RIA. To 
provide a partial measure of the economic consequences of the final 
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 final 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 EIA and supply and demand elasticity estimates from the 
economics literature.
    For oil well sites, the RIA projects that regulatory costs are at 
their highest in 2038, the final year analyzed in the RIA. We estimated 
that the final rule could result in a maximum decrease in annual crude 
oil production of about 41.1 million barrels in 2038 (or about 1.05 
percent of baseline projections of onshore crude oil production) with a 
maximum price increase of $0.25 per barrel (or about 0.33 percent of 
the projected baseline price).
    For natural gas-related sites, the RIA projects that regulatory 
costs are at their highest in 2028. We estimated that the final rule 
could result in a maximum decrease in natural gas production of about 
272.5 million Mcf in 2028 (or about 0.75 percent of baseline 
projections of onshore natural gas production) with a maximum price 
increase of $0.06 per Mcf (or about 1.76 percent of the projected 
baseline natural gas price).
    Before 2028, the modeled market impacts are smaller than later 
impacts as only the incremental requirements under the final NSPS OOOOb 
are assumed to be in effect. 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 final rule, 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 and technological change. A large number of workers 
are also employed in related sectors that provide materials and 
services for the industry.\772\ As indicated above, the final 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.
---------------------------------------------------------------------------

    \772\ Employment figure drawn from the Bureau of Labor 
Statistics Current Employment Statistics for NAICS code 211.
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E. What are the benefits?

    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 final NSPS OOOOb and EG OOOOc. The EPA 
expects climate and health benefits due to the emissions reductions 
projected under the final NSPS OOOOb and EG OOOOc. The EPA estimated 
the climate benefits of methane emission reductions expected from this 
final rule using SC-CH<INF>4</INF> estimates that reflect recent 
advances in the scientific literature on climate change and its 
economic impacts and incorporate recommendations made by the National 
Academies of Science, Engineering, and Medicine (National Academies 
2017). The EPA presented these estimates in a sensitivity analysis in 
the December 2022 RIA, solicited public comment on the methodology and 
use of these estimates, and has conducted an external peer review of 
these estimates, as described further below.
    The SC-CH<INF>4</INF> is the monetary value of the net harm to 
society from emitting a metric ton of CH4 into the atmosphere in a 
given year, or the benefit of avoiding that increase. In principle, SC-
CH<INF>4</INF> is a comprehensive metric that includes the value of all 
climate change impacts (both negative and positive), including (but not 
limited to) changes in net agricultural productivity, human health 
effects, property damage from increased flood risk, changes in the 
frequency and severity of natural disasters, disruption of energy 
systems, risk of conflict, environmental migration, and the value of 
ecosystem services. The SC-CH<INF>4</INF> 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 methane 
emissions. In practice, data and modeling limitations restrain the 
ability of SC-CH<INF>4</INF> estimates to include all physical, 
ecological, and economic impacts of climate change, implicitly 
assigning a value of zero to the omitted climate damages. The estimates 
are, therefore, a partial accounting of climate change impacts and 
likely underestimate the marginal benefits of abatement.
    Since 2008, the EPA has used estimates of the social cost of 
various greenhouse gases (i.e., social cost of carbon dioxide (SC-
CO<INF>2</INF>), SC-CH<INF>4</INF>, and social cost of nitrous oxide 
(SC-N<INF>2</INF>O)), collectively referred to as the ``social cost of 
greenhouse gases'' (SC-GHG), in analyses of actions that affect GHG 
emissions. The values used by the EPA from 2009 through 2016, and since 
2021--including in the November 2021 RIA and December 2022 RIA for this 
rulemaking--have been consistent with those developed and recommended 
by the Interagency Working Group on the SC-GHG (IWG); and the values 
used from 2017 through 2020 were consistent with those required by 
Executive Order (E.O.) 13783. During that time, the National Academies 
conducted a comprehensive review of the SC-CO<INF>2</INF> and issued a 
final report in 2017 recommending specific criteria for future updates 
to the SC-CO<INF>2</INF> estimates, a modeling framework to satisfy the 
specified criteria, and both near-term updates and longer-term research 
needs pertaining to various components of the estimation process. The 
IWG was reconstituted in 2021 and E.O. 13990 directed it to develop a 
comprehensive update of its SC-GHG estimates, recommendations regarding 
areas of

[[Page 17019]]

decision-making to which SC-GHG should be applied, and a standardized 
review and updating process to ensure that the recommended estimates 
continue to be based on the best available economics and science going 
forward.
    The EPA is a member of the IWG and is participating in the IWG's 
work under E.O. 13990. While that process continues, as noted in 
previous EPA RIAs, the EPA is continuously reviewing developments in 
the scientific literature on the SC-GHG, including more robust 
methodologies for estimating damages from emissions, and looking for 
opportunities to further improve SC-GHG estimation going forward. In 
the RIA for the December 2022 Supplemental Proposal, the EPA included a 
sensitivity analysis of the climate benefits of the supplemental 
proposal using a new set of SC-GHG estimates that incorporates recent 
research addressing recommendations of the National Academies of 
Science, Engineering, and Medicine (2017), in addition to using the IWG 
recommended interim SC-GHG estimates presented in the Technical Support 
Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim 
Estimates under Executive Order 13990, published in February 2021 (IWG, 
2021).
    The EPA solicited public comment on the sensitivity analysis and 
the accompanying draft technical report, which explains the methodology 
underlying the new set of estimates, in the December 2022 Supplemental 
Proposal.\773\ To ensure that the methodological updates adopted in the 
technical report are consistent with economic theory and reflect the 
latest science, the EPA also initiated an external peer review panel to 
conduct a high-quality review of the technical report, completed in May 
2023. The peer reviewers commended the agency on its development of 
this update, calling it a much-needed improvement in estimating the SC-
GHG and a significant step towards addressing the National Academies' 
recommendations with defensible modeling choices based on current 
science. The peer reviewers provided numerous recommendations for 
refining the presentation and for future modeling improvements, 
especially with respect to climate change impacts and associated 
damages that are not currently included in the analysis. Additional 
discussion of omitted impacts and other updates have been incorporated 
into the technical report to address peer reviewer recommendations. 
Complete information about the external peer review, including the peer 
reviewer selection process, the final report with individual 
recommendations from peer reviewers, and the EPA's response to each 
recommendation is available on the EPA's website. The EPA is a member 
of the Interagency Working Group (IWG) on the SC-GHG and continues to 
participate in its work. The EPA's new SC-GHG estimates along with the 
peer review of the updated methodology will be among the many technical 
inputs available to the IWG as it continues its work.
---------------------------------------------------------------------------

    \773\ See volume 2 of the RTC, chapter 20, in EPA-HQ-OAR-2021-
0317.
---------------------------------------------------------------------------

    An overview of the methodological updates incorporated into the new 
SC-GHG estimates is provided in the RIA. A more detailed explanation of 
each input and the modeling process is provided in the technical 
report, EPA Report on the Social Cost of Greenhouse Gases: Estimates 
Incorporating Recent Scientific Advances (EPA 2023), which is also 
included as supporting material for the RIA in the docket.\774\ 
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, the December 
2022 Supplemental Proposal, and earlier in this action, the EPA weighed 
the relevant statutory factors to determine the appropriate 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-CH<INF>4</INF> 
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.
---------------------------------------------------------------------------

    \774\ 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 2024 to 
2038 period to be $110 billion at a 2 percent near-term Ramsey discount 
rate. The EAV of these benefits is estimated to be $8.5 billion per 
year at the 2 percent near-term Ramsey 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 final NSPS OOOOb and EG OOOOc, the EPA expects that the 
projected VOC emissions reductions will improve air quality and improve 
health and welfare associated with exposure to ozone, PM<INF>2.5</INF>, 
and HAP. In the national-level analysis of public health impacts, the 
EPA used the environmental Benefits Mapping and Analysis Program--
Community Edition (BenMAP-CE) software program to quantify counts of 
premature deaths and illnesses attributable to photochemical modeled 
changes in summer season average ozone concentrations resulting from 
VOC emissions changes. The methods for quantifying the number and value 
of air pollution-attributable premature deaths and illnesses are 
described in the TSD titled Estimating PM<INF>2.5</INF>- and Ozone-
Attributable Health Benefits \775\. The reductions in health-harming 
pollution would result in significant public health benefits including 
avoided premature deaths, reductions in new asthma cases and incidences 
of asthma symptoms, reductions in hospital admissions and emergency 
department visits, and reductions in lost school days. These health 
benefits are also monetized and the EPA estimated the PV of the ozone 
health benefits over the 2024 to 2038 period to be $7.0 billion at a 2 
percent discount rate, $6.1 billion at a 3 percent discount rate, and 
$3.5 billion at a 7 percent discount rate. The EAV of these benefits is 
estimated to be $540 million at a 2 percent discount rate, $510 million 
at a 3 percent discount rate, and $380 million at a 7 percent discount 
rate.
---------------------------------------------------------------------------

    \775\ https://www.epa.gov/system/files/documents/2023-01/Estimating%20PM2.5-%20and%20Ozone-Attributable%20Health%20Benefits%20TSD_0.pdf.
---------------------------------------------------------------------------

    These values represent only a partial accounting of the potential 
benefits of this final rule. Several categories of climate, human 
health, and welfare benefits from methane, VOC, and HAP emissions 
reductions remain unmonetized and are thus not directly reflected in 
the quantified benefit estimates. The RIA presents a series of 
qualitative discussions of these unquantified and unmonetized benefits.

F. What analyses of environmental justice did we conduct?

    As discussed earlier in this preamble and in the November 2021 
proposal, the EPA engaged extensively with representatives of 
communities with environmental justice concerns to inform this 
rulemaking, and heard directly from environmental justice

[[Page 17020]]

organizations and community representatives during the public hearings 
and as part of the public comment process for both the November 2021 
Proposal and December 2022 Supplemental Proposal. Our engagement with 
these stakeholders surfaced several concerns regarding the health 
effects of air pollution associated with oil and gas facilities, the 
implications of climate change and associated extreme weather events 
for health and well-being in overburdened and vulnerable communities, 
and accessibility to data and information regarding sources near 
environmental justice communities. These stakeholders also highlighted 
the importance of reducing emissions of methane and other health-
harming air pollutants from specific sources subject to this rule, such 
as from malfunctioning control devices and flaring of associated gas, 
super-emitter events, fugitive emissions from well sites, compressor 
stations, and storage vessels.
    The EPA gave these comments careful consideration as part of the 
overall record for this rulemaking. Consistent with applicable 
executive orders and EPA policy, the Agency has also carefully analyzed 
the environmental justice implications of the climate-related benefits 
that will result from this rule, as well as the benefits associated 
with reductions in emissions of ozone precursors (namely VOCs) and 
hazardous air pollutants. The EPA believes that the suite of regulatory 
protections established in this rule, and the resulting reductions in 
harmful air pollution from new and existing oil and gas sources, will 
have a range of significant benefits for communities with environmental 
justice concerns.
    Among other things, this rule will lead to significant reductions 
in methane pollution amounting to approximately 1.5 billion tons 
CO<INF>2</INF>-e through 2038, yielding climate-related benefits valued 
at $110 billion. Because climate change is already having 
disproportionate and adverse impacts on communities with environmental 
justice concerns, these methane reductions and their associated 
climate-related benefits are of particular importance for these 
communities.
    Along with these climate-related benefits, this final rule is also 
anticipated to achieve significant VOC reductions of 16 million tons 
and HAP reductions of 590 thousand tons. Many of these reductions come 
from applying available control measures to sources that environmental 
justice organizations and communities have identified as being 
frequently located near overburdened and vulnerable populations, and as 
posing important air quality and health concerns for communities. By 
ensuring that these sources are subject to nationally applicable 
requirements that reflect highly effective technologies and approaches 
for limiting and reducing emissions, the EPA believes that the NSPS and 
EG being finalized here will provide a high and consistent degree of 
protection against the full suite of harmful air pollutants associated 
with oil and gas sources, including in communities with environmental 
justice concerns that are located near these sources and exposed to 
these emissions.
1. Environmental Justice and the Impacts of Climate Change
    In 2009, under the Endangerment and Cause or Contribute Findings 
for Greenhouse Gases Under Section 202(a) of the Clean Air Act 
(``Endangerment Finding,'' 74 FR 66496), the Administrator considered 
how climate change threatens the health and welfare of the U.S. 
population.\776\ As part of that consideration, she also considered 
risks to minority and low-income individuals and communities, finding 
that certain parts of the U.S. population may be especially vulnerable 
based on their characteristics or circumstances. These groups include 
economically and socially disadvantaged communities, including those 
that have been historically marginalized or overburdened; individuals 
at vulnerable lifestages, such as the elderly, the very young, and 
pregnant or nursing women; those already in poor health or with 
comorbidities; the disabled; those experiencing homelessness, mental 
illness, or substance abuse; and/or Indigenous or minority populations 
dependent on one or limited resources for subsistence due to factors 
including but not limited to geography, access, and mobility.
---------------------------------------------------------------------------

    \776\ Earlier studies and reports can be found at https://www.epa.gov/cira/social-vulnerability-report.
---------------------------------------------------------------------------

    Scientific assessment reports produced over the past decade by the 
USGCRP,<SUP>777 778</SUP> the IPCC,<SUP>779 780 781 782</SUP> the 
National Academies of Science, Engineering, and 
Medicine,<SUP>783 784</SUP> and

[[Page 17021]]

the EPA \785\ add more evidence that the impacts of climate change 
raise potential EJ concerns. These reports conclude that less-affluent, 
traditionally marginalized and predominantly non-White communities can 
be especially vulnerable to climate change impacts because they tend to 
have limited resources for adaptation, are more dependent on climate-
sensitive resources such as local water and food supplies or have less 
access to social and information resources. Some communities of color, 
specifically populations defined jointly by ethnic/racial 
characteristics and geographic location (e.g., African-American, Black, 
and Hispanic/Latino communities; Native Americans, particularly those 
living on Tribal lands and Alaska Natives), may be uniquely vulnerable 
to climate change health impacts in the U.S., as discussed below. In 
particular, the 2016 scientific assessment on the Impacts of Climate 
Change on Human Health \786\ found with high confidence that 
vulnerabilities are place- and time-specific, lifestages and ages are 
linked to immediate and future health impacts, and social determinants 
of health are linked to greater extent and severity of climate change-
related health impacts.
---------------------------------------------------------------------------

    \777\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
    \778\ 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. https://dx.doi.org/10.7930/J0R49NQX.
    \779\ Oppenheimer, M., M. Campos, R. Warren, J. Birkmann, G. 
Luber, B. O'Neill, and K. Takahashi, 2014: Emergent risks and key 
vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of 
Working Group II to the Fifth Assessment Report of the 
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, 
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, 
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 
Cambridge University Press, Cambridge, United Kingdom and New York, 
NY, USA, pp. 1039-1099.
    \780\ Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M. 
Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food 
security and food production systems. In: Climate Change 2014: 
Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral 
Aspects. Contribution of Working Group II to the Fifth Assessment 
Report of the Intergovernmental Panel on Climate Change [Field, 
C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. 
Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, 
E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 
White (eds.)]. Cambridge University Press, Cambridge, United Kingdom 
and New York, NY, USA, pp. 485-533.
    \781\ Smith, K.R., A. Woodward, D. Campbell-Lendrum, D.D. 
Chadee, Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn, 
2014: Human health: impacts, adaptation, and co-benefits. In: 
Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: 
Global and Sectoral Aspects. Contribution of Working Group II to the 
Fifth Assessment Report of the Intergovernmental Panel on Climate 
Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. 
Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. 
Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. 
Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, 
Cambridge, United Kingdom and New York, NY, USA, pp. 709-754.
    \782\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special 
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission 
pathways, in the context of strengthening the global response to the 
threat of climate change, sustainable development, and efforts to 
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner, 
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. 
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. 
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. 
Waterfield (eds.)]. In Press.
    \783\ National Research Council. 2011. America's Climate 
Choices. Washington, DC: The National Academies Press. https://doi.org/10.17226/12781.
    \784\ National Academies of Sciences, Engineering, and Medicine. 
2017. Communities in Action: Pathways to Health Equity. Washington, 
DC: The National Academies Press. https://doi.org/10.17226/24624.
    \785\ EPA. 2021. Climate Change and Social Vulnerability in the 
United States: A Focus on Six Impacts. U.S. Environmental Protection 
Agency, EPA 430-R-21-003.
    \786\ USGCRP, 2016: The Impacts of Climate Change on Human 
Health in the United States: A Scientific Assessment.
---------------------------------------------------------------------------

    Per the NCA4, ``Climate change affects human health by altering 
exposures to heat waves, floods, droughts, and other extreme events; 
vector-, food- and waterborne infectious diseases; changes in the 
quality and safety of air, food, and water; and stresses to mental 
health and well-being.'' \787\ Many health conditions such as 
cardiopulmonary or respiratory illness and other health impacts are 
associated with and exacerbated by an increase in GHGs and climate 
change outcomes, which is problematic as these diseases occur at higher 
rates within vulnerable communities. Importantly, negative public 
health outcomes include those that are physical in nature, as well as 
mental, emotional, social, and economic.
---------------------------------------------------------------------------

    \787\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. 
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 
2018: Human Health. In Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, pp. 539-571. doi:10.7930/
NCA4.2018.CH14.
---------------------------------------------------------------------------

    The scientific assessment literature, including the previously 
referenced reports, demonstrates that there are myriad ways in which 
these populations may be affected at the individual and community 
levels. Outdoor workers, such as construction or utility workers and 
agricultural laborers, who are frequently part of already at-risk 
groups, are exposed to poor air quality and extreme temperatures 
without relief. Furthermore, individuals within EJ populations of 
concern face greater housing and clean water insecurity and bear 
disproportionate economic impacts and health burdens associated with 
climate change effects. They also have less or limited access to 
healthcare and affordable, adequate health or homeowner insurance. The 
urban heat island effect can add additional stress to vulnerable 
populations in densely populated cities who do not have access to air 
conditioning.\788\ Finally, resiliency and adaptation are more 
difficult for economically disadvantaged communities: They tend to have 
less liquidity, individually and collectively, to move or to make the 
types of infrastructure or policy changes necessary to limit or reduce 
the hazards they face. They frequently face systemic, institutional 
challenges that limit their power to advocate for and receive resources 
that would otherwise aid in resiliency and hazard reduction and 
mitigation.
---------------------------------------------------------------------------

    \788\ USGCRP, 2016.
---------------------------------------------------------------------------

    The assessment literature cited in the EPA's 2009 Endangerment 
Finding, as well as Impacts of Climate Change on Human Health, also 
concluded that certain populations and people in particular stages of 
life, including children, are most vulnerable to climate-related health 
effects. The assessment literature produced from 2016 to the present 
strengthens these conclusions by providing more detailed findings 
regarding related vulnerabilities and the projected impacts youth may 
experience. These assessments--including the NCA4 (2018) and The 
Impacts of Climate Change on Human Health in the United States (2016)--
describe how children's unique physiological and developmental factors 
contribute to making them particularly vulnerable to climate change. 
Impacts to children are expected from air pollution, infectious and 
waterborne illnesses, and mental health effects resulting from extreme 
weather events. In addition, children are among those especially 
susceptible to allergens, as well as health effects associated with 
heat waves, storms, and floods. Additional health concerns may arise in 
low-income households, especially those with children, if climate 
change reduces food availability and increases prices, leading to food 
insecurity within households. More generally, these reports note that 
extreme weather and flooding can cause or exacerbate poor health 
outcomes by affecting mental health because of stress; contributing to 
or worsening existing conditions, again due to stress or also as a 
consequence of exposures to water and air pollutants; or by impacting 
hospital and emergency services operations.\789\ Further, in urban 
areas in particular, flooding can have significant economic 
consequences due to effects on infrastructure, pollutant exposures, and 
drowning dangers. The ability to withstand and recover from flooding is 
dependent in part on the social vulnerability of the affected 
population and individuals experiencing an event.\790\ In addition, 
children are among those especially susceptible to allergens, as well 
as health effects associated with heat waves, storms, and floods. 
Additional health concerns may arise in low-income households, 
especially those with children, if climate change reduces food 
availability and increases prices, leading to food insecurity within 
households.
---------------------------------------------------------------------------

    \789\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. 
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 
2018: Human Health. In Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, pp. 539-571. doi:10.7930/
NCA4.2018.CH14.
    \790\ National Academies of Sciences, Engineering, and Medicine 
2019. Framing the Challenge of Urban Flooding in the United States. 
Washington, DC: The National Academies Press. https://doi.org/10.17226/25381.
---------------------------------------------------------------------------

    The Impacts of Climate Change on Human Health (USGCRP, 2016) also 
found that some communities of color, low-income groups, people with 
limited English proficiency, and certain immigrant groups (especially 
those who are undocumented) live with many of the factors that 
contribute to their vulnerability to the health impacts of climate 
change. While difficult to isolate from related socioeconomic factors, 
race appears to be an important factor in vulnerability to climate-
related stress, with elevated risks for mortality from high 
temperatures reported for Black or African-American individuals 
compared to White individuals after controlling for factors such as air 
conditioning use. Moreover, people of color are disproportionately 
exposed to air pollution based on where they live, and 
disproportionately vulnerable due to higher baseline prevalence of 
underlying diseases such as asthma, so

[[Page 17022]]

climate exacerbations of air pollution are expected to have 
disproportionate effects on these communities. Locations with greater 
health threats include urban areas (due to, among other factors, the 
``heat island'' effect where built infrastructure and lack of green 
spaces increases local temperatures), areas where airborne allergens 
and other air pollutants already occur at higher levels, and 
communities experienced depleted water supplies or vulnerable energy 
and transportation infrastructure.
    The recent EPA report on climate change and social vulnerability 
\791\ examined four socially vulnerable groups (individuals who are low 
income, minority, without high school diplomas, and/or 65 years and 
older) and their exposure to several different climate impacts (air 
quality, coastal flooding, extreme temperatures, and inland flooding). 
This report found that Black and African-American individuals were 40 
percent more likely to currently live in areas with the highest 
projected increases in mortality rates due to climate-driven changes in 
extreme temperatures, and 34 percent more likely to live in areas with 
the highest projected increases in childhood asthma diagnoses due to 
climate-driven changes in particulate air pollution. The report found 
that Hispanic and Latino individuals are 43 percent more likely to live 
in areas with the highest projected labor hour losses in weather-
exposed industries due to climate-driven warming, and 50 percent more 
likely to live in coastal areas with the highest projected increases in 
traffic delays due to increases in high-tide flooding. The report found 
that American Indian and Alaska Native individuals are 48 percent more 
likely to live in areas where the highest percentage of land is 
projected to be inundated due to sea level rise, and 37 percent more 
likely to live in areas with high projected labor hour losses. Asian 
individuals were found to be 23 percent more likely to live in coastal 
areas with projected increases in traffic delays from high-tide 
flooding. Those with low income or no high school diploma are about 25 
percent more likely to live in areas with high projected losses of 
labor hours, and 15 percent more likely to live in areas with the 
highest projected increases in asthma due to climate-driven increases 
in particulate air pollution, and in areas with high projected 
inundation due to sea level rise.
---------------------------------------------------------------------------

    \791\ EPA. 2021. Climate Change and Social Vulnerability in the 
United States: A Focus on Six Impacts. U.S. Environmental Protection 
Agency, EPA 430-R-21-003.
---------------------------------------------------------------------------

    In a more recent 2023 report, Climate Change Impacts on Children's 
Health and Well-Being in the U.S., the EPA considered the degree to 
which children's health and well-being may be impacted by five climate-
related environmental hazards--extreme heat, poor air quality, changes 
in seasonality, flooding, and different types of infectious diseases 
(U.S. EPA, 2023). The report found that children's academic achievement 
is projected to be reduced by 4-7 percent per child, as a result of 
moderate and higher levels of warming, impacting future income levels. 
The report also projects increases in the numbers of annual emergency 
department visits associated with asthma, and that the number of new 
asthma diagnoses increases by 4-11 percent due to climate-driven 
increases in air pollution relative to current levels. In addition, 
more than 1 million children in coastal regions are projected to be 
temporarily displaced from their homes annually due to climate-driven 
flooding, and infectious disease rates are similarly anticipated to 
rise, with the number of new Lyme disease cases in children living in 
22 states in the eastern and midwestern U.S. increasing by 
approximately 3,000-23,000 per year compared to current levels. 
Overall, the report confirmed findings of broader climate science 
assessments that children are uniquely vulnerable to climate-related 
impacts and that in many situations, children in the U.S. who identify 
as Black, Indigenous, and People of Color, are limited English-
speaking, do not have health insurance, or live in low-income 
communities may be disproportionately exposed to the most severe 
impacts of climate change.
2. Impacts of Climate Change on Indigenous Communities
    Indigenous communities face disproportionate risks from the impacts 
of climate change, particularly those communities impacted by 
degradation of natural and cultural resources within established 
reservation boundaries and threats to traditional subsistence 
lifestyles. Indigenous communities whose health, economic well-being, 
and cultural traditions depend upon the natural environment will likely 
be affected by the degradation of ecosystem goods and services 
associated with climate change. The IPCC indicates that losses of 
customs and historical knowledge may cause communities to be less 
resilient or adaptable.\792\ The NCA4 (2018) noted that while 
indigenous peoples are diverse and will be impacted by the climate 
changes universal to all Americans, there are several ways in which 
climate change uniquely threatens indigenous peoples' livelihoods and 
economies.\793\ In addition, there can be institutional barriers 
(including policy-based limitations and restrictions) to their 
management of water, land, and other natural resources that could 
impede adaptive measures.
---------------------------------------------------------------------------

    \792\ Porter, et al., 2014: Food security and food production 
systems.
    \793\ Jantarasami, L.C., R. Novak, R. Delgado, E. Marino, S. 
McNeeley, C. Narducci, J. Raymond-Yakoubian, L. Singletary, and K. 
Powys Whyte, 2018: Tribes and Indigenous Peoples. In Impacts, Risks, 
and Adaptation in the United States: Fourth National Climate 
Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. 
Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. 
Stewart (eds.)]. U.S. Global Change Research Program, Washington, 
DC, USA, pp. 572-603. doi:10.7930/NCA4. 2018. CH15.
---------------------------------------------------------------------------

    For example, indigenous agriculture in the Southwest is already 
being adversely affected by changing patterns of flooding, drought, 
dust storms, and rising temperatures leading to increased soil erosion, 
irrigation water demand, and decreased crop quality and herd sizes. The 
Confederated Tribes of the Umatilla Indian Reservation in the Northwest 
have identified climate risks to salmon, elk, deer, roots, and 
huckleberry habitat. Housing and sanitary water supply infrastructure 
are vulnerable to disruption from extreme precipitation events. 
Confounding general Native American response to natural hazards are 
limitations imposed by policies such as the Dawes Act of 1887 and the 
Indian Reorganization Act of 1934, which ultimately restrict Indigenous 
peoples' autonomy regarding land-management decisions through Federal 
trusteeship of certain Tribal lands and mandated Federal oversight of 
management decisions. Additionally, NCA4 noted that Indigenous peoples 
are subjected to institutional racism effects, such as poor 
infrastructure, diminished access to quality healthcare, and greater 
risk of exposure to pollutants. Consequently, Native Americans often 
have disproportionately higher rates of asthma, cardiovascular disease, 
Alzheimer's disease, diabetes, and obesity. These health conditions and 
related effects (disorientation, heightened exposure to 
PM<INF>2.5</INF>, etc.) can all contribute to increased vulnerability 
to climate-driven extreme heat and air pollution events, which also may 
be exacerbated by stressful situations, such as extreme weather events, 
wildfires, and other circumstances.

[[Page 17023]]

    NCA4 and IPCC's Fifth Assessment Report \794\ also highlighted 
several impacts specific to Alaskan Indigenous Peoples. Coastal erosion 
and permafrost thaw will lead to more coastal erosion, rendering winter 
travel riskier and exacerbating damage to buildings, roads, and other 
infrastructure--impacts on archaeological sites, structures, and 
objects that will lead to a loss of cultural heritage for Alaska's 
indigenous people. In terms of food security, the NCA4 discussed 
reductions in suitable ice conditions for hunting, warmer temperatures 
impairing the use of traditional ice cellars for food storage, and 
declining shellfish populations due to warming and acidification. While 
the NCA4 also noted that climate change provided more opportunity to 
hunt from boats later in the fall season or earlier in the spring, the 
assessment found that the net impact was an overall decrease in food 
security.
---------------------------------------------------------------------------

    \794\ Porter, et al., 2014: Food security and food production 
systems.
---------------------------------------------------------------------------

3. Environmental Justice Impacts of Ozone Exposure Due to Oil and 
Natural Gas VOC Impacts
    Although EJ concerns for each rulemaking are unique and should be 
considered on a case-by-case basis, the EPA's EJ Technical Guidance 
(U.S. EPA, 2015) states that ``[t]he analysis of potential EJ concerns 
for regulatory actions should address three questions:
    1. Are there potential EJ concerns associated with environmental 
stressors affected by the regulatory action for population groups of 
concern in the baseline?
    2. Are there potential EJ concerns associated with environmental 
stressors affected by the regulatory action for population groups of 
concern for the regulatory option(s) under consideration?
    3. For the regulatory option(s) under consideration, are potential 
EJ concerns created [, exacerbated,] or mitigated compared to the 
baseline?''
    To address these questions, the EPA developed an analytical 
approach that considers the purpose and specifics of this proposed 
rulemaking, as well as the nature of known and potential exposures and 
health impacts. The purpose of this RIA is to provide estimates of the 
potential costs and benefits of the illustrative national control 
strategies in 2038 for the selected policy option. The selected policy 
option evaluated in the RIA is expected to reduce VOC emissions. 
Consequently, this means that ozone formation and exposure is expected 
to be reduced such that some areas are expected to experience greater 
air quality improvements, and thus health improvements. As differences 
in both exposure and susceptibility (i.e., intrinsic individual risk 
factors) contribute to environmental impacts, the analytical approach 
used here first determines whether exposure and health effect 
disparities exist under the baseline scenario. The approach then 
evaluates if and how disparities are impacted when illustrative 
emissions control strategies are analyzed. Both the exposure and health 
effects analyses were developed using available scientific evidence 
from the selected policy option for the Oil & Gas rule, for the future 
year 2038, and are associated with various uncertainties. Consistent 
with the methods the EPA uses to fully characterize the benefits of a 
regulatory action, these EJ analyses evaluate the full set of exposure 
and health outcome distributions resulting from this proposed action at 
the national scale.
    The EJ exposure assessment portion of the analysis focuses on 
associating ambient ozone concentrations with various demographic 
variables. Because this type of analysis requires less a priori 
information, we were able to include a broad array of demographic 
characteristics. Estimating actual health outcomes modified by 
demographic population requires additional scientific information, 
which constrained the scope of the second portion of the assessment. We 
focused the EJ health effects analysis on populations and health 
outcomes with the strongest scientific support (U.S. EPA, 2019, U.S. 
EPA, 2020, U.S. EPA, 2022a). However, the EJ health effects analysis 
does not include information about differences in other factors that 
could affect the likelihood of adverse impacts (e.g., access to health 
care, BMI) across groups, due to limitations on the underlying 
data.\795\ Both the EJ exposure and health effects analyses are subject 
to uncertainties related to input parameters and assumptions. For 
example, both analyses focus on seasonal average ozone concentrations 
and do not evaluate whether concentrations experienced by different 
groups persist across the distribution of daily ozone exposures. 
Additionally, the EJ health effects analysis is subject to additional 
uncertainties related to concentration-response relationships and 
baseline incidence data.
---------------------------------------------------------------------------

    \795\ We do not ascribe differential health effects to be caused 
by race or ethnicity. Instead, race and ethnicity likely serve as 
proxies for a variety of environmental and social stressors.
---------------------------------------------------------------------------

    Complex analyses using estimated parameters and inputs from 
numerous models are likely to include multiple sources of uncertainty. 
As this analysis is based on the same ozone spatial fields as the 
benefits assessment, it is subject to similar types of uncertainty.

XVII. Statutory and Executive Order Reviews

    Additional information about these statutes and E.O. 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 14094: Modernizing Regulatory Review

    This action is a ``significant regulatory action'' as defined under 
section 3(f)(1) of Executive Order 12866, as amended by Executive Order 
14094. Accordingly, the EPA submitted this action to OMB for Executive 
Order 12866 review. Documentation of any changes made in response to 
the Executive Order 12866 review is available in the docket for this 
action. The EPA prepared an analysis of the potential costs and 
benefits associated with this action. This analysis, ``Regulatory 
Impact Analysis 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.
    The PV and EAV of the projected benefits, costs, and net benefits 
over the 2024 to 2038 period under the final rule using discount rates 
of 2, 3, and 7 percent is presented in table 28. A discussion of the 
costs of the final rule is in section 2 of the RIA and a discussion of 
the benefits is in section 3.

[[Page 17024]]



       Table 28--Benefits, Costs, Net Benefits, and Emissions Reductions Under the Final Rules, 2024-2038
                               [Dollar estimates in millions of 2019 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                      2 Percent near-term ramsey discount rate
                                   -----------------------------------------------------------------------------
                                         PV          EAV           PV          EAV           PV          EAV
----------------------------------------------------------------------------------------------------------------
Climate Benefits \b\..............     $110,000       $8,500     $110,000       $8,500     $110,000       $8,500
----------------------------------------------------------------------------------------------------------------
                                     2 Percent discount rate
                                     3 Percent discount rate
                                     7 Percent discount rate
----------------------------------------------------------------------------------------------------------------
                                             PV          EAV           PV          EAV           PV          EAV
----------------------------------------------------------------------------------------------------------------
Ozone Health Benefits \c\.........       $7,000         $540       $6,100         $510       $3,500         $380
Net Compliance Costs..............       19,000        1,500       18,000        1,500       14,000        1,600
    Compliance Costs..............       31,000        2,400       29,000        2,400       22,000        2,400
    Value of Product Recovery.....       13,000          980       11,000          950        7,400          820
Net Benefits \d\..................       97,000        7,600       97,000        7,500       98,000        7,300
----------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits............  Climate and ozone-related health benefits from reducing 58 million short
                                    tons of methane from 2024 to 2038.
                                    Benefits to provision of ecosystem services associated with reduced ozone
                                    concentrations from reducing 16 million short tons of VOC from 2024 to 2038.
                                    PM2.5-related health benefits from reducing 16 million short tons of VOC
                                    from 2024 to 2038.
                                    HAP benefits from reducing 590 thousand short tons of HAP from 2024 to 2038.
----------------------------------------------------------------------------------------------------------------
\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 three different
  estimates of the SC-CH4 (under 1.5 percent, 2.0 percent, and 2.5 percent near-term Ramsey discount rates). For
  the presentational purposes of this table, we show the climate benefits associated with the SC-CH4 at the 2
  percent near-term Ramsey discount rate. Please see tables 3.4 and 3.5 in the RIA for the full range of
  monetized climate benefit estimates. All net benefits are calculated using climate benefits discounted at the
  2 percent near-term rate.
\c\ Monetized benefits include those related to public health associated with reductions in ozone
  concentrations. The health benefits are associated with several point estimates.
\d\ Several categories of climate, human health, and welfare benefits from methane, VOC, and HAP emissions
  reductions remain unmonetized and are thus not directly reflected in the quantified benefit estimates in the
  table.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this rule 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. The information 
collection requirements are not enforceable until OMB approves them. As 
noted in section X.N, the templates for the semiannual and annual 
reports for these subparts will be on the CEDRI website.\796\
---------------------------------------------------------------------------

    \796\ https://www.epa.gov/electronic-reporting-air-emissions/cedri.
---------------------------------------------------------------------------

    40 CFR part 60, subpart OOOOa. The respondents are owners or 
operators of onshore oil and natural gas affected facilities. For the 
purposes of this ICR, it is assumed that oil and natural gas affected 
facilities located in the U.S. are owned and operated by the oil and 
natural gas industry, and that none of the affected facilities in the 
U.S. are owned or operated by Federal, state, Tribal, or local 
government. All affected facilities are assumed to be privately owned 
for-profit businesses.
    The EPA estimates an average of 4,250 respondents will be affected 
by NSPS OOOOa over the three-year period (2023-2025). The average 
annual burden for the recordkeeping and reporting requirements for 
these owners and operators is 375,338 person-hours, with an average 
annual cost of $126,543,957 over the three-year period.
    Respondents/affected entities: Oil and natural gas operators and 
owners.
    Respondent's obligation to respond: Mandatory.
    Estimated number of respondents: 4,250.
    Frequency of response: Varies depending on affected facility.\797\
---------------------------------------------------------------------------

    \797\ 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: 375,338 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $126,543,957 (2019$), which includes no 
capital costs or O&M costs.
    40 CFR part 60, subpart OOOOb. The respondents are owners or 
operators of onshore oil and natural gas affected facilities and third 
parties that are approved as notifiers of super-emitter emissions 
events. For the purposes of this ICR, it is assumed that oil and 
natural gas affected facilities located in the U.S. are owned and 
operated by the oil and natural gas industry, and that none of the 
affected facilities in the U.S. are owned or operated by Federal, 
state, Tribal, or local government. All affected facilities are assumed 
to be privately owned for-profit businesses.
    The EPA estimates an average of 1,849 respondents will be affected 
by NSPS OOOOb over the 3-year period 2023-2025. The average annual 
burden for the recordkeeping and reporting requirements for these 
owners and operators is 883,625 person-hours, with an average annual 
cost of $58,535,262 over the three-year period.
    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.\798\
---------------------------------------------------------------------------

    \798\ 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: $58,535,262 (2019$), 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

[[Page 17025]]

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 166,000 to 208,000 hours at a total annual labor cost of 
between $21 to $26 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 EG. Burden is defined at 5 CFR 1320.3(b).
    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. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    Pursuant to sections 603 and 609(b) of the RFA, the EPA prepared an 
initial regulatory flexibility analysis (IRFA) for the proposed rule 
and 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. Summaries of 
the IRFA and Panel recommendations are presented in the proposed rule 
at 86 FR 63260 (November 15, 2021) and 87 FR 74702 (December 6, 2022). 
The complete IRFA is available in the RIA for the December 2022 
Supplemental Proposal (see section 4.3 of the RIA).
    As required by section 604 of the RFA, the EPA prepared a final 
regulatory flexibility analysis (FRFA) for this action. The FRFA 
addresses the issues raised by public comments on the IRFA for the 
proposed rule. The complete FRFA is available for review in the docket 
and is summarized here. The scope of the FRFA is limited to the NSPS 
OOOOb. The impacts of the EG OOOOc are not evaluated here because the 
EG OOOOc does not place explicit requirements on the regulated 
industry. Those impacts will be evaluated pursuant to the development 
of a Federal plan.
    The final rulemaking takes a significant step forward in mitigating 
climate change and improving human health by reducing GHG and VOC 
emissions from the oil and natural gas industry, specifically the Crude 
Oil and Natural Gas source category. The oil and natural gas industry 
is the United States' largest industrial emitter of methane. Human 
emissions of methane, a potent GHG, are responsible for about one third 
of the warming due to well-mixed GHGs, the second most important human 
warming agent after carbon dioxide. The EPA is finalizing the actions 
described in the preamble in accordance with its legal obligations and 
authorities following a review directed by E.O. 13990, ``Protecting 
Public Health and the Environment and Restoring Science to Tackle the 
Climate Crisis,'' issued on January 20, 2021. The EPA intends for the 
rulemaking to address the far-reaching harmful consequences and real 
economic costs of climate change. According to the IPCC, ``It is 
unequivocal that human influence has warmed the atmosphere, ocean and 
land. Widespread and rapid changes in the atmosphere, ocean, cryosphere 
and biosphere have occurred.'' These changes have led to increases in 
heat waves and wildfire weather, reductions in air quality, more 
intense hurricanes and rainfall events, and rising sea level. These 
changes, along with future projected changes, endanger the physical 
survival, health, economic well-being, and quality of life of people 
living in America, especially those in the most vulnerable communities.
    The EPA finalizes certain NSPS and to promulgate additional NSPS 
for both methane and VOC emissions from new oil and natural gas sources 
in the production, processing, transmission and storage segments of the 
industry; and promulgates EG to require states to regulate methane 
emissions from existing sources in those segments. The large amount of 
methane emissions from the oil and natural gas industry coupled with 
the adverse effects of methane on the global climate compel immediate 
regulatory action. The final rule comports with the EPA's CAA section 
111 obligation to reduce dangerous pollution and responds to the 
urgency expressed by the current Congress. With the proposal, the EPA 
is taking additional steps in the regulation of the Crude Oil and 
Natural Gas source category to protect human health and the 
environment.
    The significant issues raised in public comments specifically in 
response to the initial regulatory flexibility analysis came from the 
Office of Advocacy within the Small Business Administration. In 
response to the Advocacy's comments, the EPA agreed that issuing a 
revised IRFA with the December 2022 Supplemental Proposal was 
warranted, and the revision was published as section 4.3 in the 
December 2022 Supplemental Proposal RIA. The revised IRFA addressed 
Advocacy's critiques of the IRFA contained in the November 2021 
Proposal RIA by providing a robust discussion of regulatory 
alternatives related to provisions for the following elements: fugitive 
emissions requirements, alternative technologies, associated gas 
requirements, process controller and pumps requirements, and 
reciprocating compressor requirements. For the final regulatory 
flexibility analysis, the EPA is also including discussion of 
regulatory alternatives for centrifugal compressor and liquids 
unloading requirements. Taken together, this discussion addresses 
Advocacy's concerns about the insufficiency of the discussion of 
regulatory alternatives in the November 2021 Proposal IRFA. In 
addition, the revised IRFA noted that the December 2022 Supplemental 
Proposal did not require OGI in accordance with the proposed appendix K 
for production sites. While equipment leaks at gas plants were still 
proposed to be monitored using OGI in accordance with appendix K in the 
December 2022 Supplemental Proposal, the burden estimates summarized in 
the revised IRFA reflected burden associated with appendix K. Finally, 
the

[[Page 17026]]

burden estimates were updated to reflect the proposed NSPS OOOOb.
    Following the issuance of the December 2022 Supplemental Proposal, 
Advocacy provided additional comments. While noting that it continued 
to have significant concerns about the impact the rule would have on 
small businesses in the oil and gas production sector, Advocacy 
acknowledged the work that the EPA did to improve its RFA compliance 
through the IRFA between proposals. More detailed responses to 
Advocacy's comments can be found in Chapter 21 of both Volume I and 
Volume II of the RTC document.
    The RFA defines small entities as including ``small businesses,'' 
``small governments,'' and ``small organizations'' (5 U.S.C. 601). The 
regulatory revisions being considered by the EPA for this rulemaking 
are expected to affect a variety of small businesses but would not 
affect any small governments or small organizations. The RFA references 
the definition of ``small business'' found in the Small Business Act, 
which authorizes the Small Business Administration (SBA) to further 
define ``small business'' by regulation. The detailed listing of SBA 
definitions of small business for oil and natural gas industries or 
sectors, by NAICS code, that are potentially affected by this proposal 
is included in table 4-12 of the RIA. The EPA conducted this initial 
regulatory flexibility analysis at the ultimate (i.e., highest) level 
of ownership, evaluating ultimate parent entities.
    To estimate the number of small businesses potentially impacted by 
the rule, the EPA developed a list of operators of oil and natural gas 
wells, natural gas processing plants, and natural gas compressor 
stations. The initial list of operators included 1,451 well site 
operators that completed a well in 2019, 297 processing plant 
operators, and 574 compressor station operators. The EPA then conducted 
a small business coding exercise as shown in table 4-13 of the RIA. In 
total, 998 of the 1,451 well site operators (69 percent) matched to 914 
ultimate parent companies; 270 of 297 processing plant operators (91 
percent) matched to 149 ultimate parent companies; and 519 of 574 
compressor station operators (90 percent) matched to 315 ultimate 
parent companies.
    To estimate the compliance cost impacts of the proposed rule on 
small entities, the EPA used the dataset of operators matched to 
ultimate parent companies discussed in the previous section and apply 
the sum of incremental costs for all relevant affected facility 
categories. Because the incremental costs depend on unknown 
characteristics of operator-specific well sites, processing plants, and 
compressor stations, we use average equipment counts at each facility 
type to derive estimates of average impacts at each facility type. 
Ultimately, the EPA estimated cost-to-sales ratios for each small 
entity to summarize the impacts of the proposed NSPS. See information 
and results presented in tables 4-14 to 4-16 of the RIA.
    Prior to the November 2021 Proposal, the EPA convened a SBAR Panel 
to obtain recommendations from small entity representatives on elements 
of the regulation. The Panel identified significant alternatives for 
consideration by the Administrator of the EPA, which were summarized in 
a final report.\799\ Based on the Panel recommendations, as well as 
comments received in response to the November 2021 Proposal and 
December 2022 Supplemental Proposal, the EPA is finalizing several 
regulatory alternatives that could accomplish the stated objectives of 
the CAA while minimizing any significant economic impact of the final 
rule on small entities. While the RIA included a full detailed 
discussion of these alternatives, the EPA is including two examples 
below.
---------------------------------------------------------------------------

    \799\ See Document ID EPA-HQ-OAR-2021-0317-0074.
---------------------------------------------------------------------------

    First, as described in section XI.A. of this preamble, the EPA 
finalizing certain changes to the fugitives emissions standards that 
were proposed in November 2021 for NSPS OOOOb and revised in the 
December 2022 Supplemental Proposal. The EPA believes that two of these 
proposed changes will reduce impacts on small businesses: (1) requiring 
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 and (2) defining monitoring technique and frequency based 
on the equipment present at a well site. The EPA describes these two 
changes below.
    In the final rule, the EPA is not requiring OGI monitoring in 
accordance with the proposed appendix K for well sites or centralized 
production facilities, as was proposed in the November 2021 Proposal. 
Instead, the EPA is requiring OGI surveys following the procedures 
specified in the regulatory text for NSPS OOOOb (at 40 CFR 60.5397b) or 
according to EPA Method 21. This change is consistent with the 
requirements for OGI surveys found in NSPS OOOOa at 40 CFR 60.5397a. 
This final change is a result of the extensive comments the EPA 
received from oil and natural 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 well 
sites.\800\ 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 finalizing 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 X.I.V of the preamble for additional 
information on what the EPA is finalizing for appendix K related to 
other sources (e.g., natural gas processing plants). The EPA believes 
this will particularly benefit small entities because it will 
streamline the requirements for conducting and documenting OGI surveys 
at these smaller, less complex sites. Additionally, this change 
provides a uniform set of requirements for regulated entities that may 
have assets subject to different subparts within the same region, which 
leads to increased regulatory certainty and eases the compliance 
burden. At the same time, the EPA believes this does not compromise the 
stated objectives of the Clean Air Act because these same requirements 
are already allowed in NSPS OOOOa and outline many of the same data 
elements required by appendix K.
---------------------------------------------------------------------------

    \800\ See final rule preamble section XI.A. and see Document ID 
Nos. EPA-HQ-OAR-2021-0317-0579, -0743, -0764, -0777, -0782, -0786, -
0793, -0802, -0807, -0808, -0810, -0814, -0817, -0820, -0831, -0834, 
and -0938.
---------------------------------------------------------------------------

    Next, the final rule includes fugitive monitoring frequencies and 
detection techniques that are based on the type of equipment located at 
a well site, instead of the baseline methane emissions threshold that 
was included in the November 2021 Proposal and revised in the December 
2022 Supplemental Proposal. Specifically, the EPA is finalizing four 
distinct subcategories of well sites:
    <bullet> Well sites with only a single wellhead,
    <bullet> Small well sites with a single wellhead and only one piece 
of major

[[Page 17027]]

production and processing equipment,\801\
---------------------------------------------------------------------------

    \801\ Small well sites are defined as 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, 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 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.
---------------------------------------------------------------------------

    <bullet> Well sites with only two or more wellheads and no other 
major production and processing equipment, and
    <bullet> Well sites with one or more controlled storage vessels, 
control devices, natural gas-driven pneumatic controllers or pumps, or 
two or more other major production and processing equipment, including 
centralized production facilities.
    The EPA is finalizing these distinct subcategories of well sites 
after consideration of comments on the November 2021 Proposal and the 
December 2022 Supplemental Proposal that stated the original baseline 
methane emissions threshold approach would be difficult to implement, 
especially for small businesses that may be less familiar with the use 
of emission factors from the EPA's Greenhouse Gas Reporting Program. 
The EPA believes that owners and operators, including small entities, 
can readily identify the number and types of major equipment located at 
a well site without the need for complicated calculations of emissions.
    Further, the EPA is finalizing specific monitoring frequencies and 
techniques as the BSER for each well site subcategory individually. For 
example, the EPA is finalizing the use of audible, visual, and 
olfactory (AVO) inspections at well sites containing only a single 
wellhead and at small well sites. This monitoring technique does not 
require specialized equipment or operator training, but does allow the 
identification of large leaks, which are of the most concern from an 
environmental standpoint. Further, AVO monitoring can easily be built 
into regular maintenance activities that are designed to keep the 
equipment at the site in good working order. The final requirements are 
responsive to a SER recommendation that the EPA allow AVO and soap 
bubble tests as an option for finding fugitive emissions, particularly 
because they are low cost and easy to implement alternatives for 
detecting leaks, and an Advocacy recommendation that the EPA allow AVO 
as an alternative in limited circumstances, such as part of an off-ramp 
for facilities unlikely to emit more than insignificant methane or with 
a demonstrated history of insignificant emissions. The EPA believes 
this will particularly benefit small entities because AVO surveys at 
these types of well sites are effective at identifying the types of 
large emissions from sources located at these well sites at a much 
lower cost than OGI surveys. For example, the costs associated with the 
quarterly AVO inspections are estimated at $660/year, whereas the costs 
associated with an annual OGI survey for this type of well site are 
estimated at approximately $2,000/yr. Inspections via AVO allow for 
more frequent inspections for large emissions events at these well 
sites, which results in faster emissions mitigation, than a single OGI 
survey each year.
    In a second example, in the November 2021 Proposal, the EPA 
proposed that an owner or operator of a reciprocating compressor 
affected facility would be 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 option of routing rod packing emissions to a process via a closed 
vent system under negative pressure in order to comply with the rule. 
The proposed option to route to a process would have been allowed as an 
alternative under NSPS OOOOb because implementing this option, where 
feasible, would achieve greater emission reductions than the proposed 
performance-based emissions threshold standard. The December 2022 
Supplemental Proposal proposed 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 proposed: (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, and 
(3) to allow for monitoring based on 8,760 hours of operation instead 
of based on a calendar year. The EPA also proposed regulatory text that 
defined the required flow rate measurement methods and/or procedure 
requirements, and recordkeeping and reporting requirements. For the 
alternative option of routing rod packing emissions to a process via a 
closed vent system under negative pressure, the EPA proposed to remove 
the negative pressure requirement.
    As described in the preamble to the final rule,\802\ the EPA is 
finalizing changes to the proposed requirements for reciprocating 
compressors in for NSPS OOOOb as a result of comments received on the 
November 2021 Proposal and December 2022 Supplemental Proposal. The EPA 
believes the following rule changes will reduce impacts on small 
businesses.
---------------------------------------------------------------------------

    \802\ See final rule preamble section XI.I.
---------------------------------------------------------------------------

    Concerns were expressed regarding the EPA's November 2021 Proposal 
and December 2022 Supplemental Proposal that shifted rod packing 
changeout requirements from a designated schedule of once every 3 years 
to a performance standard based on an annual flow rate measurement. 
While the November 2021 Proposal format of the performance standard 
based on volumetric flow rate measurements was as a work practice 
standard, the December 2022 Supplemental Proposal format of the 
performance standard was as a numeric standard. Commenters on the 
December 2022 Supplemental Proposal expressed that, as a numeric 
standard, the performance standard based on flow measurements was 
unworkable. It was also noted that a performance standard is often more 
expensive than a fixed equipment change-out standard because of the 
additional monitoring and recordkeeping necessary to demonstrate 
compliance with the performance standard, which they believed could 
negatively impact small businesses. These commenters also supported the 
fixed schedule rod packing change-out standard because this is the 
standard owners and operators have implemented for reciprocating 
compressors under NSPS OOOOa and stated that the annual flow rate 
performance work practice standard would lead to more rod packing 
changeouts than would be required based on the November OOOOa fixed-
schedule packing change out requirements.

[[Page 17028]]

    The EPA is finalizing the following requirement changes associated 
with the reciprocating compressor rod packing volumetric flow rate 
measurement performance standard based on November 2021 Proposal and 
December 2022 Supplemental Proposal comments: (1) a 2 scfm volumetric 
flow rate per cylinder performance work practice standard, (2) repair 
(in addition to replacement) of the rod packing is allowed to maintain 
an emission rate at or below 2 scfm per cylinder; and (3) monitoring 
based on 8,760 hours of operation instead of based on a calendar year. 
These final requirements for reciprocating compressors are responsive 
to comments and concerns expressed by industry (including small 
businesses).
    The EPA believes the final rule 2 scfm volumetric flow rate per 
cylinder performance work practice standard approach benefits small 
entities because facilities can use monitoring data to determine 
emission levels at which it is necessary to repair or replace rod 
packing. This approach can result in operational benefits, including a 
longer life for existing equipment, improvements in operating 
efficiencies, and long-term cost savings. Allowing an owner or operator 
to repair the rod packing (in addition to replacement of the rod 
packing) to maintain an emission rate at or below 2 scfm per cylinder 
alleviates the need to replace the rod packing when only a simple 
repair may be needed to maintain volumetric flow rate at or below 2 
scfm per cylinder. Requiring owners and operators to conduct volumetric 
flow rate monitoring based on 8,760 hours of operation instead of based 
on a calendar year reduces the burden on owners and operators where 
compressors are not operational for multiple months or are used 
intermittently. Additionally, by requiring that monitoring frequency 
based on hours of operation, owners and operators have the flexibility 
to stagger maintenance activity throughout the year. The final rule 
defines the required flow rate measurement methods and/or procedures, 
repair and replacement requirements, and recordkeeping and reporting 
requirements.
    In addition, the following regulatory options have been added to 
the final rule: (1) owners and operators are allowed to change out 
reciprocating compressor rod packing every 8,760 hours of operation in 
lieu of conducting volumetric flow rate monitoring every 8,760 hours; 
and (2) owners and operators are allowed to route emissions to a 
control device via a closed vent system in addition to routing 
emissions via a closed vent system to a process. For the alternative 
option of routing rod packing emissions to a process via a closed vent 
system under negative pressure, the EPA is finalizing the removal of 
the negative pressure requirement. By allowing owners and operators to 
change out rod packing every 8,760 hours of operation in lieu of 
conducting volumetric flow rate monitoring every 8,760 hours, owners 
and operators have the option to choose a more-stringent rod packing 
change out schedule (on or before every 8,760 hours of operation) and 
avoid the need to conduct volumetric flow rate monitoring. Lastly, by 
the final rule allowing owners and operators to route emissions to a 
control device in addition to routing emissions to a process, the EPA 
has added flexibility to the compliance options available for owners 
and operators.
    In addition, the EPA is preparing a Small Entity Compliance Guide 
to help small entities comply with this rule. The guide will be 
available on the 60 days after publication of the final rule at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/implementation-oil-and-natural-gas-air.

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 1 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 XVI of this preamble, and in Chapter 1 of the RIA.
    Consistent with section 205 of UMRA, the EPA has identified and 
considered a reasonable number of regulatory alternatives. These 
alternatives are described in section XI of this preamble.
    The EG is promulgated under CAA section 111(d) and does not impose 
any direct compliance requirements on designated facilities, apart from 
the requirement for states to develop state plans. As explained in 
section XIV.G of the November 2021 Proposal \803\ and section V of the 
December 2022 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 1 year. Thus, the EG is not 
subject to the requirements of section 203 or section 205 of the UMRA.
---------------------------------------------------------------------------

    \803\ See 86 FR 63256 (November 15, 2021) and 87 FR 74702 
(December 6, 2022).
---------------------------------------------------------------------------

    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 
outreach with national organizations representing states and Tribal 
governmental entities while formulating the proposed rule as discussed 
in the November 2021 Proposal, the December 2022 Supplemental Proposal, 
and section VII of this final preamble.\804\ The EPA considered the 
stakeholders' experiences and lessons learned to help inform how to 
better structure this final rule and consider ongoing challenges that 
will require continued collaboration with stakeholders.
---------------------------------------------------------------------------

    \804\ See 86 FR 63145 (November 15, 2021).
---------------------------------------------------------------------------

E. Executive Order 13132: Federalism

    The final NSPS OOOO, OOOOa, and OOOOb and final EG OOOOc do not 
have federalism implications. These actions will not have substantial 
direct effects on the states as defined in the E.O., 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 one or more Indian Tribes, 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.\805\ While many of the 
affected and designated facilities impacted by final NSPS and EG on

[[Page 17029]]

Tribal lands are owned by private entities, some Tribes also own 
affected and or designated facilities. There would 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 
final rule 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.
---------------------------------------------------------------------------

    \805\ 86 FR 63143 (November 15, 2021).
---------------------------------------------------------------------------

    Tribal consultations were completed after the November 2021 
Proposal at the request of the Northern Arapahoe Tribe, MHA Nation, and 
Eastern Shoshone Tribe.\806\ Additional Tribal consultation was 
completed at the request of MHA Nation and an informational meeting was 
held with the Ute Tribe after the December 2022 Supplemental 
Proposal.\807\ 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 as these 
rules become implemented.
---------------------------------------------------------------------------

    \806\ See Memorandum in EPA-HQ-OAR-2021-0317.
    \807\ See Memorandum in EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

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 a significant regulatory action as defined by E.O. 
12866(3)(f)(1), 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 
standards and guidelines 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, December 15, 2009). 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 \808\). These assessments describe how children's 
unique physiological and developmental factors contribute to making 
them particularly vulnerable to climate change. Impacts to children are 
expected from heat waves, air pollution, infectious and waterborne 
illnesses, and mental health effects resulting from extreme weather 
events. In addition, children are among those especially susceptible to 
most allergic diseases, as well as health effects associated with heat 
waves, storms, and floods. Additional health concerns may arise in low-
income households, especially those with children, if climate change 
reduces food availability and increases prices, leading to food 
insecurity within households. More detailed information on the impacts 
of climate change to human health and welfare is provided in sections 
III and VI of the November 2021 Proposal,\809\ section VII of the 
December 2022 Supplemental Proposal,\810\ and section XVI of this 
document. Under the final NSPS OOOOb and EG OOOOc, the EPA expects that 
VOC and methane emissions reductions will improve air quality and 
mitigate climate impacts which will benefit the health and welfare of 
children.
---------------------------------------------------------------------------

    \808\ 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.
    \809\ See 86 FR 63124 and 86 FR 63139 (November 15, 2021).
    \810\ See 87 FR 74702 (December 6, 2022).
---------------------------------------------------------------------------

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

    This action, which is a significant regulatory action under E.O. 
12866, has a significant adverse effect on the supply, distribution or 
use of energy as that phrase is defined in E.O. 13211. The 
documentation for this decision is contained in section 4.1.4 of the 
Regulatory Impact Analysis 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 
final action. To make this determination, we compare the projected 
change in crude oil and natural gas production to guidance articulated 
in a January 13, 2021, OMB memorandum, Furthering Compliance with 
Executive Order 13211, Titled ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use.'' \811\ With 
respect to crude oil production, the guidance indicates that a 
regulatory action produces a significant adverse effect if it is 
expected to produce reductions in crude oil supply in excess of 20 
million barrels per year. With respect to natural gas production, the 
guidance indicates that a regulatory action produces a significant 
adverse effect if it reduces natural gas production in excess of 40 
million mcf per year.\812\ We estimate maximum production reductions of 
about 41.4 million barrels of crude oil (1.05 percent of projected 
baseline production) and 272.5 million Mcf per year (0.75 percent).
---------------------------------------------------------------------------

    \811\ See https://www.whitehouse.gov/wp-content/uploads/2021/01/M-21-12.pdf.
    \812\ The 2021 E.O. 13211 guidance memo states that the natural 
gas production decrease that indicates the regulatory action is a 
significant energy action is 40 mcf per year. Because this is a 
relatively small amount of natural gas and previous guidance from 
2001 indicated a threshold of 25 million Mcf, we assume the 2021 
memo was intended to establish 40 million Mcf as the indicator of an 
adverse energy effect. See https://www.whitehouse.gov/wp-content/uploads/2017/11/2001-M-01-27-Guidance-for-Implementing-E.O.-13211.pdf.
---------------------------------------------------------------------------

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR 
Part 51

    This rulemaking 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, 25A of 40 CFR part 60, appendix A, EPA-454/B-
08-002, and EPA-600/R-12/531. No applicable voluntary consensus 
standards (VCS) 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 VCS for 
this rule. Two VCS were

[[Page 17030]]

identified as an acceptable alternative to EPA test methods for the 
purpose of this 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 CO<INF>2</INF>, carbon monoxide (CO), H<INF>2</INF>S, 
NO<INF>X</INF>, O<INF>2</INF>, and SO<INF>2</INF>. Second, ASTM 
International (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.'' \813\ In this rule, the EPA is including regulatory text for 
40 CFR part 60, subparts OOOOb and OOOOc that includes incorporation by 
reference. In accordance with requirements of 40 CFR 60.17, the EPA is 
incorporating the following sixteen standards by reference.
---------------------------------------------------------------------------

    \813\ See Document ID No. EPA-HQ-OAR-2021-0317-0072.
---------------------------------------------------------------------------

    <bullet> ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses 
[Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers 
measuring the O<INF>2</INF> or CO<INF>2</INF> content of the exhaust 
gas. It highlights and specifies methods, apparatus, and calculations 
which are used in conjunction with Performance Test Codes to determine 
quantitatively, the gaseous constituents of exhausts resulting from 
stationary combustion sources. The PTC Supplement also describes the 
most commonly used instrumentation and analytical procedures used for 
flue and exhaust gas analyses.
    <bullet> 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, kerosine, gas oils, distillate 
fuel oils, and similar petroleum products, utilizing either manual or 
automated equipment.
    <bullet> 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.
    <bullet> ASTM D1945-14 (Reapproved 2019), 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.
    <bullet> ASTM D2879-83, Test Method for Vapor Pressure-Temperature 
Relationship and Initial Decomposition Temperature of Liquids by 
Isoteniscope. This test method covers the determination of the vapor 
pressure of pure liquids, the vapor pressure exerted by mixtures in a 
closed vessel at 40 +/-5 percent ullage, and the initial thermal 
decomposition temperature of pure and mixed liquids.
    <bullet> ASTM D2879-96, Test Method for Vapor Pressure-Temperature 
Relationship and Initial Decomposition Temperature of Liquids by 
Isoteniscope. This method is a revision of ASTM D2879-83. It is suited 
for use over a wide range of temperature ranging from ambient to 748 K 
and can include below ambient temperature when suitable constant-
temperature bath for such temperature is used.
    <bullet> ASTM D2879-97, Test Method for Vapor Pressure-Temperature 
Relationship and Initial Decomposition Temperature of Liquids by 
Isoteniscope. This method is a revision of ASTM D2879-96. Most 
petroleum products boil over a fairly wide temperature range and an 
ideal combination will show a progressive reduction in vapor pressure 
as lighter fluid components and may exert pressure in a closed system. 
This test method is simulated in the isoteniscope -a constant volume 
apparatus.
    <bullet> 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.
    <bullet> 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.
    <bullet> ASTM D6348-12e1, Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared (FTIR) Spectroscopy. This field test method employs an 
extractive sampling system to direct stationary source effluent to an 
FTIR spectrometer for the identification and quantification of gaseous 
compounds. Also, this method employs converting the volume 
concentration to a mass emission rate utilizing a compound's molecular 
weight, and the effluent volumetric flow rate, temperature and pressure 
in determining the impact of that particular compound to the 
atmosphere.
    <bullet> ASTM D6522-20, 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 NO<INF>X</INF>, CO, and O<INF>2</INF> 
concentrations in controlled and uncontrolled emissions from natural 
gas-fired reciprocating engines, combustion turbines, boilers, and 
process heaters.
    <bullet> ASTM E168-16 (Reapproved 2023), Standard Practices for 
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.
    <bullet> ASTM E169-16 (Reapproved 2022), Standard Practices for 
General Techniques of Ultraviolet Quantitative Analysis 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.
    <bullet> ASTM E260-96, General Gas Chromatography Procedures is a 
general

[[Page 17031]]

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.
    <bullet> EPA-454/B-08-002, Quality Assurance Handbook for Air 
Pollution Measurement Systems Volume IV: Meteorological Measurements 
Version 2.0 (Final), March 2008. This guidance is designed to provide 
clear and concise information to the State/Local/Tribal (SLT) air 
pollution control agencies that operate meteorological monitoring 
equipment and systems.
    <bullet> EPA-600/R-12/531, EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards (Issued May 2012) is 
mandatory for certifying the calibration gases being used for the 
calibration and audit of ambient air quality analyzers and continuous 
emission monitors that are required by numerous parts of the CFR.
    The EPA determined that the ASTM and ASME/ANSI standards, 
notwithstanding the age of the standards, are reasonably available 
because they are available for purchase from the following addresses: 
ASTM International 100 Barr Harbor Drive, Post Office Box C700, West 
Conshohocken, PA 19428-2959, +1.610.832.9500, www.astm.org; or 
ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106, +1.877.779.6768, 
www.proquest.com; and the American Society of Mechanical Engineers 
(ASME), Three Park Avenue, New York, NY 10016-5990, +1.800.843.5990, 
<a href="/cdn-cgi/l/email-protection#85e6f0f6f1eae8e0f7e6e4f7e0c5e4f6e8e0abeaf7e2"><span class="__cf_email__" data-cfemail="70130503041f1d1502131102153011031d155e1f0217">[email protected]</span></a>, www.asme.org. 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.

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

    The EPA believes that the human health or environmental conditions 
that exist prior to this action result in or have the potential to 
result in disproportionate and adverse human health or environmental 
effects on communities with EJ concerns. With respect to exposure to 
ambient ground-level ozone, the baseline scenario is similar to that 
described by other RIAs in that there are small but disproportionate 
and adverse effects on some populations analyzed including American 
Indians, Asians, Hispanics, those who are Linguistically isolated, 
those living in Redlined areas, and those living on Tribal land. On 
average, these demographic groups are exposed to at least 0.9 ppb (and 
at most 2.0 ppb) higher ozone concentrations than the reference 
population.
    As described above, this final rulemaking will result in reductions 
in VOCs, which are an important precursor contributing to ground-level 
ozone formation in many regions of the country. VOC emissions from oil 
and gas operations are believed to be a factor contributing to elevated 
ozone levels in multiple areas of the country including Colorado, New 
Mexico, Texas, Utah and Wyoming. Although the EPA's analysis indicates 
that the final rulemaking will have relatively small effects on ambient 
ozone concentrations when compared to baseline conditions, the EPA 
nonetheless anticipates that communities with environmental justice 
concerns will benefit from reductions in VOC emissions that contribute 
to ozone formation in diverse areas of the country.
    At the same time, the reductions in ozone concentrations that will 
result from this rulemaking are expected to be evenly distributed 
across most demographic groups. The EPA believes that this action is 
likely to reduce existing disproportionate and adverse effects on 
people who live on Tribal lands in some states (most notably Colorado). 
However, for all other demographic groups and geographic locations, the 
EPA believes this action is not likely to meaningfully change existing 
disproportionate and adverse effects. The reductions in ozone 
concentrations due to the policy option are similar in magnitude across 
most demographic groups and small relative to baseline conditions, such 
that it is unlikely that the policy option will exacerbate or mitigate 
any disproportionate exposures to ozone that were present at baseline.
    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,\814\ 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 the December 2022 Supplemental 
Proposal,\815\ and in section 4 of the Regulatory Impact Analysis 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.
---------------------------------------------------------------------------

    \814\ See Document ID No. EPA-HQ-OAR-2021-0317-0173.
    \815\ See Document ID No. EPA-HQ-OAR-2021-0317-1566.
---------------------------------------------------------------------------

    This rulemaking will also reduce methane pollution that contributes 
to climate change, which itself has substantial and adverse impacts on 
environmental justice communities. Methane emissions represent a 
significant share of total GHG emissions and hence are a major 
contributor to climate change. In 2009, under the Endangerment and 
Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) 
of the Clean Air Act (``Endangerment Finding''), the Administrator 
considered how climate change threatens the health and welfare of the 
U.S. population. As part of that consideration, she also considered 
risks to people of color and low-income individuals and communities, 
finding that certain parts of the U.S. population may be especially 
vulnerable based on their characteristics or circumstances. These 
groups include economically and socially vulnerable communities; 
individuals at vulnerable life stages, such as the elderly, the very 
young, and pregnant or nursing women; those already in poor health or 
with comorbidities; the disabled; those experiencing homelessness, 
mental illness, or substance abuse; and/or Indigenous or people of 
color dependent on one or limited resources for subsistence due to 
factors including but not limited to geography, access, and mobility.
    Scientific assessment reports produced over the past decade by the 
U.S. Global Change Research Program (USGCRP), the IPCC, and the 
National Academies of Science, Engineering, and Medicine add more 
evidence that the impacts of climate change raise potential EJ 
concerns.\816\
---------------------------------------------------------------------------

    \816\ IPCC. (2018). Global Warming of 1.5 [deg]C. An IPCC 
Special Report on the impacts of global warming of 1.5 [deg]C above 
pre-industrial levels and related global greenhouse gas emission 
pathways, in the context of strengthening the global response to the 
threat of climate change, sustainable development, and efforts to 
eradicate poverty (V. Masson-Delmotte, P. Zhai, H.-O. P[ouml]rtner, 
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. 
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. 
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, a. M. Tignor, & T. 
Waterfield Eds.).; Oppenheimer, M., Campos, M., Warren, R., 
Birkmann, J., Luber, G., O'Neill, B., & Takahashi, K. (2014). 
Emergent risks and key vulnerabilities. In C.B. Field, V.R. Barros, 
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, 
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 
Levy, S. MacCracken, P.R. Mastrandrea, & L.L. White (Eds.), Climate 
Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global 
and Sectoral Aspects. Contribution of Working Group II to the Fifth 
Assessment Report of the Intergovernmental Panel on Climate Change 
(pp. 1039-1099). Cambridge, United Kingdom and New York, NY: 
Cambridge University Press; Porter, J.R., Xie, L., Challinor, A.J., 
Cochrane, K., Howden, M., Iqbal, M.M., & Lobell, D.B. (2014). Food 
security and food production systems. In C.B. Field, V.R. Barros, 
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, 
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 
Levy, S. MacCracken, P.R. Mastrandrea, & L.L. White (Eds.), Climate 
Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global 
and Sectoral Aspects. Contribution of Working Group II to the Fifth 
Assessment Report of the Intergovernmental Panel on Climate Change 
(pp. 485-533). Cambridge, United Kingdom and New York, NY: Cambridge 
University Press; Smith, K. R., Woodward, A., Campbell-Lendrum, D., 
Chadee, D. D., Honda, Y., Liu, Q., . . . Sauerborn, R. (2014). Human 
Health: Impacts, Adaptation, and Co-Benefits. In C.B. Field, V.R. 
Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 
Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 
Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, & L.L.White 
(Eds.), Climate Change 2014: Impacts, Adaptation, and Vulnerability. 
Part A: Global and Sectoral Aspects. Contribution of Working Group 
II to the Fifth Assessment Report of the Intergovernmental Panel on 
Climate Change (pp. 709-754). Cambridge, United Kingdom and New 
York, NY: Cambridge University Press; USGCRP. (2016). The Impacts of 
Climate Change on Human Health in the United States: A Scientific 
Assessment. Washington DC: U.S. Global Change Research Program. 
https://dx.doi.org/10.7930/J0R49NQX; USGCRP. (2018). Impacts, Risks, 
and Adaptation in the United States: Fourth National Climate 
Assessment, Volume II. Washington DC: U.S. Global Change Research 
Program. https://dx.doi.org/10.7930/NCA4.2018.

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

[[Page 17032]]

    These reports conclude that poorer or predominantly non-White 
communities can be especially vulnerable to climate change impacts 
because they tend to have limited adaptive capacities and are more 
dependent on climate-sensitive resources such as local water and food 
supplies, or have less access to social and information resources. Some 
communities of color, specifically populations defined jointly by 
ethnic/racial characteristics and geographic location, may be uniquely 
vulnerable to climate change health impacts in the U.S. In particular, 
the 2016 scientific assessment on the Impacts of Climate Change on 
Human Health found with high confidence that vulnerabilities are place- 
and time-specific, life stages and ages are linked to immediate and 
future health impacts, and social determinants of health are linked to 
greater extent and severity of climate change-related health impacts. 
The GHG emission reductions associated with this proposal would 
contribute to efforts to reduce the probability of severe impacts 
related to climate change. Individuals living in socially and 
economically disadvantaged communities, such as those living at or 
below the poverty line or who are experiencing homelessness or social 
isolation, are at greater risk of health effects from climate change. 
This is also true with respect to people at vulnerable life stages, 
specifically women who are pre- and perinatal, or are nursing; in utero 
fetuses; children at all stages of development; and the elderly. Per 
the Fourth National Climate Assessment (NCA4), ``Climate change affects 
human health by altering exposures to heat waves, floods, droughts, and 
other extreme events; vector-, food- and waterborne infectious 
diseases; changes in the quality and safety of air, food, and water; 
and stresses to mental health and well-being.'' Many health conditions 
such as cardiopulmonary or respiratory illness and other health impacts 
are associated with and exacerbated by an increase in GHGs and climate 
change outcomes, which is problematic as these diseases occur at higher 
rates within vulnerable communities. Importantly, negative public 
health outcomes include those that are physical in nature, as well as 
mental, emotional, social, and economic.
    To this end, the scientific assessment literature, including the 
aforementioned reports, demonstrates that there are myriad ways in 
which these populations may be affected at the individual and community 
levels. Individuals face differential exposure to criteria pollutants, 
in part due to the proximities of highways, trains, factories, and 
other major sources of pollutant-emitting sources to less-affluent 
residential areas. Outdoor workers, such as construction or utility 
crews and agricultural laborers, who frequently are comprised of 
already at-risk groups, are exposed to poor air quality and extreme 
temperatures without relief. Furthermore, individuals within EJ 
populations of concern face greater housing, clean water, and food 
insecurity and bear disproportionate economic impacts and health 
burdens associated with climate change effects. They have less or 
limited access to healthcare and affordable, adequate health or 
homeowner insurance. Finally, resiliency and adaptation are more 
difficult for economically disadvantaged communities: They have less 
liquidity, individually and collectively, to move or to make the types 
of infrastructure or policy changes to limit or reduce the hazards they 
face. They frequently are less able to self-advocate for resources that 
would otherwise aid in building resilience and hazard reduction and 
mitigation.
    In a 2021 report, Climate Change and Social Vulnerability in the 
United States: A Focus on Six Impacts, the EPA considered the degree to 
which four socially vulnerable populations--defined based on income, 
educational attainment, race and ethnicity, and age--may be more 
exposed to the highest impacts of climate change.\817\ The report found 
that Blacks and African American populations are approximately 40 
percent more likely to currently live in these areas of the U.S. 
projected to experience the highest increases in mortality rates due to 
changes in temperature. Additionally, Hispanic and Latino individuals 
in weather exposed industries were found to be 43 percent more likely 
to currently live in areas with the highest projected labor hour losses 
due to temperature changes. American Indian and Alaska Native 
individuals are projected to be 48 percent more likely to currently 
live in areas where the highest percentage of land may be inundated by 
sea level rise. Overall, the report confirmed findings of broader 
climate science assessments that Americans identifying as people of 
color, those with low-income, and those without a high school diploma 
face higher differential risks of experiencing the most damaging 
impacts of climate change.
---------------------------------------------------------------------------

    \817\ U.S. EPA. (2021c) Climate Change and Social Vulnerability 
in the United States: A Focus on Six Impacts (EPA-430-R-21-003) 
Retrieved from Washington, DC: https://epa.gov/cira/social-vulnerability-report.
---------------------------------------------------------------------------

    The assessment literature cited in the EPA's 2009 and 2016 
Endangerment and Cause or Contribute Findings, as well as Impacts of 
Climate Change on Human Health (2016) and the NCA4 (2018), also 
concluded that certain populations and life stages, including children, 
are especially sensitive to climate-related health effects. In a more 
recent 2023 report, Climate Change Impacts on Children's Health and 
Well-Being in the U.S., the EPA considered the degree to which 
children's health and well-being may be impacted by five climate-
related environmental hazards--extreme heat, poor air quality, changes 
in seasonality, flooding, and different types of infectious 
diseases.\818\ The report found that children's academic achievement is 
projected to be reduced by 4-7 percent per child, as a result of 
moderate and higher levels of warming, impacting future income levels. 
The report also projects increases in the numbers of

[[Page 17033]]

annual emergency department visits associated with asthma, and that the 
number of new asthma diagnoses increases by 4-11% due to climate-driven 
increases in air pollution relative to current levels. In addition, 
more than 1 million children in coastal regions are projected to be 
temporarily displaced from their homes annually due to climate-driven 
flooding, and infectious disease rates are similarly anticipated to 
rise, with the number of new Lyme disease cases in children living in 
22 states in the eastern and midwestern U.S. increasing by 
approximately 3,000-23,000 per year compared to current levels. 
Overall, the report confirmed findings of broader climate science 
assessments that children are uniquely vulnerable to climate-related 
impacts and that in many situations, children in the U.S. who identify 
as Black, Indigenous, and People of Color, are limited English-
speaking, do not have health insurance, or live in low-income 
communities may be disproportionately exposed to the most severe 
impacts of climate change.
---------------------------------------------------------------------------

    \818\ U.S. EPA. (2023b). Climate Change and Children's Health 
and Wellbeing in the United States. https://www.epa.gov/system/files/documents/2023-04/CLiME_Final%20Report.pdf.
---------------------------------------------------------------------------

    Native American Tribal communities possess unique vulnerabilities 
to climate change, particularly those impacted by degradation of 
natural and cultural resources within established reservation 
boundaries and threats to traditional subsistence lifestyles. Tribal 
communities whose health, economic well-being, and cultural traditions 
depend upon the natural environment will likely be affected by the 
degradation of ecosystem goods and services associated with climate 
change. The IPCC indicates that losses of customs and historical 
knowledge may cause communities to be less resilient or adaptable. The 
NCA4 noted that while Indigenous peoples are diverse and will be 
impacted by the climate changes universal to all Americans, there are 
several ways in which climate change uniquely threatens Indigenous 
peoples' livelihoods and economies. In addition, there can 
institutional barriers to their management of water, land, and other 
natural resources that could impede adaptive measures.
    For example, Indigenous agriculture in the Southwest is already 
being adversely affected by changing patterns of flooding, drought, 
dust storms, and rising temperatures leading to increased soil erosion, 
irrigation water demand, and decreased crop quality and herd sizes. The 
Confederated Tribes of the Umatilla Indian Reservation in the Northwest 
have identified climate risks to salmon, elk, deer, roots, and 
huckleberry habitat. Housing and sanitary water supply infrastructure 
are vulnerable to disruption from extreme precipitation events.
    NCA4 noted that Indigenous peoples often have disproportionately 
higher rates of asthma, cardiovascular disease, Alzheimer's, diabetes, 
and obesity, which can all contribute to increased vulnerability to 
climate-driven extreme heat and air pollution events. These factors 
also may be exacerbated by stressful situations, such as extreme 
weather events, wildfires, and other circumstances.
    NCA4 and IPCC Fifth Assessment Report also highlighted several 
impacts specific to Alaskan Indigenous Peoples. Coastal erosion and 
permafrost thaw will lead to more coastal erosion, exacerbated risks of 
winter travel, and damage to buildings, roads, and other 
infrastructure--these impacts on archaeological sites, structures, and 
objects that will lead to a loss of cultural heritage for Alaska's 
Indigenous people. In terms of food security, the NCA4 discussed 
reductions in suitable ice conditions for hunting, warmer temperatures 
impairing the use of traditional ice cellars for food storage, and 
declining shellfish populations due to warming and acidification. While 
the NCA also noted that climate change provided more opportunity to 
hunt from boats later in the fall season or earlier in the spring, the 
assessment found that the net impact was an overall decrease in food 
security.
    In addition, the U.S. Pacific Islands and the indigenous 
communities that live there are also uniquely vulnerable to the effects 
of climate change due to their remote location and geographic 
isolation. They rely on the land, ocean, and natural resources for 
their livelihoods, but face challenges in obtaining energy and food 
supplies that need to be shipped in at high costs. As a result, they 
face higher energy costs than the rest of the nation and depend on 
imported fossil fuels for electricity generation and diesel. These 
challenges exacerbate the climate impacts that the Pacific Islands are 
experiencing. NCA4 notes that Indigenous peoples of the Pacific are 
threatened by rising sea levels, diminishing freshwater availability, 
and negative effects to ecosystem services that threaten these 
individuals' health and well-being.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit the rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action meets the criteria set forth in 5 U.S.C. 
804(2).

List of Subjects in 40 CFR Part 60

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

Michael S. Regan,
Administrator.

    For the reasons stated in the preamble, the Environmental 
Protection Agency amends part 60 of title 40, chapter I, of the Code of 
Federal Regulations as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 4701, et seq.

Subpart A--General Provisions

0
2. Section 60.17 is amended by:
0
a. Revising paragraphs (a), (g) introductory text, (g)(14), and (h) 
introductory text;
0
b. Revising paragraphs (h)(19) and (h)(76);
0
c. Redesignating paragraphs(h)(213) through (223) as paragraphs 
(h)(218) through (228), paragraphs(h)(210) through (212) as paragraphs 
(h)(214) through (216), paragraphs (h)(197) through (209) as paragraphs 
(h)(200) through (212), paragraphs(h)(192) through (196) as paragraphs 
(h)(194) through (198), and paragraphs (h)(77) through (191) as 
paragraphs (h)(78) through (192), respectively;
0
d. Adding new paragraph (h)(77);
0
e. Revising newly redesignated paragraphs (h)(112), (113), (114), 
(142), and (h)(173);
0
f. Add new paragraphs (h)(193), (199), (213), and (217);
0
g. Revising newly redesignated paragraph (h)(220) and (j) introductory 
text;
0
j. Redesignating paragraphs (j)(2) through (j)(5) as paragraphs (j)(3) 
through (j)(6);
0
k. Adding new paragraph (j)(2); and
0
l. Revising the newly redesignated paragraph (j)(4).
    The revisions and additions read as follows:


Sec.  60.17  Incorporations by reference.

    (a) Certain material is incorporated by reference into this part 
with the approval of the Director of the Federal Register under 5 
U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than that 
specified in this section, the EPA must publish notice of change in the 
Federal Register and the material

[[Page 17034]]

must be available to the public. All approved incorporation by 
reference (IBR) material is available for inspection at the EPA and at 
the National Archives and Records Administration (NARA). Contact the 
EPA at: EPA Docket Center, Public Reading Room, EPA WJC West, Room 
3334, 1301 Constitution Ave. NW, Washington, DC, telephone: 202-566-
1744. For information on the availability of this material at NARA, 
visit www.archives.gov/federal-register/cfr/ibr-locations.html or email 
<a href="/cdn-cgi/l/email-protection#caacb8e4a3a4b9baafa9bea3a5a48aa4abb8abe4ada5bc"><span class="__cf_email__" data-cfemail="3452461a5d5a47445157405d5b5a745a5546551a535b42">[email protected]</span></a>. The material may be obtained from the sources 
in the following paragraphs of this section.
* * * * *
    (g) American Society of Mechanical Engineers (ASME), Two Park 
Avenue, New York, NY 10016-5990; phone: (800) 843-2763; email: 
<a href="/cdn-cgi/l/email-protection" class="__cf_email__" data-cfemail="43003630372c2e2631002231260322302e266d2c3124">[email protected]</a>; website: www.asme.org.
* * * * *
    (14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus], Issued August 31, 1981;, IBR approved 
for Sec. Sec.  60.56c(b); 60.63(f); 60.106(e); 60.104a(d), (h), (i), 
and (j); 60.105a(b), (d), (f), and (g); 60.106a(a); 60.107a(a), (c), 
and (d); 60.275(e); 60.275a(e); 60.275b(e); tables 1 and 3 to subpart 
EEEE; tables 2 and 4 to subpart FFFF; table 2 to subpart JJJJ; 
Sec. Sec.  60.285a(f); 60.396(a); 60.2145(s) and (t); 60.2710(s) and 
(t); 60.2730(q); 60.4415(a); 60.4900(b); 60.5220(b); tables 1 and 2 to 
subpart LLLL; tables 2 and 3 to subpart MMMM; Sec. Sec.  60.5406(c); 
60.5406a(c); 60.5406b(c); 60.5407a(g); 60.5407b(g); 60.5413(b); 
60.5413a(b) and (d); 60.5413b(b) and (d); Sec. Sec.  60.5413c(b) and 
(d).
* * * * *
    (h) ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, West 
Conshohocken, Pennsylvania 19428-2959; phone: (800) 262-1373; website: 
www.astm.org.
* * * * *
    (19) ASTM D86-96, Distillation of Petroleum Products, approved 
April 10, 1996; IBR approved for Sec. Sec.  60.562-2(d). 60.593(d). 
60.593a(d); 60.633(h); 60.5401(f); 60.5401a(f); 60.5402b(d); 
60.5402c(d).
* * * * *
    (76) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis 
of Natural Gas by Gas Chromatography, approved January 1, 2010; IBR 
approved for Sec. Sec.  60.107a(d); 60.5413(d); 60.5413a(d); 
60.5413b(d); 60.5413c(d).
    (77) ASTM D1945-14 (Reapproved 2019), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography, approved December 1, 
2019; IBR approved for Sec. Sec.  60.5417b(d); 60.5417c(d).
* * * * *
    (112) ASTM D2879-83, Test Method for Vapor Pressure-Temperature 
Relationship and Initial Decomposition Temperature of Liquids by 
Isoteniscope, approved 1983; IBR approved for Sec. Sec.  60.111b(f); 
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
    (113) ASTM D2879-96, Test Method for Vapor Pressure-Temperature 
Relationship and Initial Decomposition Temperature of Liquids by 
Isoteniscope, approved 1996; IBR approved for Sec. Sec.  60.111b(f); 
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
    (114) ASTM D2879-97, Test Method for Vapor Pressure-Temperature 
Relationship and Initial Decomposition Temperature of Liquids by 
Isoteniscope, approved 1997; IBR approved for Sec. Sec.  60.111b(f); 
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
* * * * *
    (142) ASTM D3588-98 (Reapproved 2003), Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels, approved May 10, 2003; IBR approved for Sec. Sec.  
60.107a(d); 60.5413(d); 60.5413a(d); 60.5413b(d); 60.5413c(d).
* * * * *
    (173) ASTM D4891-89 (Reapproved 2006), Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion, approved June 1, 2006; IBR approved for Sec. Sec.  
60.107a(d); 60.5413(d); 60.5413a(d); 60.5413b(d); 60.5413c(d).
* * * * *
    (193) ASTM D6348-12e1, Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared (FTIR) Spectroscopy, approved February 1, 2012; IBR approved 
for Sec.  60.5413c(b).
* * * * *
    (199) ASTM D6522-20, 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, 
approved June 1, 2020; IBR approved for Sec. Sec.  60.5413b(b); 
60.5413c(b).
* * * * *
    (213) ASTM E168-16, (Reapproved 2023), Standard Practices for 
General Techniques of Infrared Quantitative Analysis, approved January 
1, 2023; IBR approved for Sec. Sec.  60.5400b(a); 60.5400c(a); 
60.5401b(a); 60.5401c(a).
* * * * *
    (217) ASTM E169-16 (Reapproved 2022), Standard Practices for 
General Techniques of Ultraviolet-Visible Quantitative Analysis, 
approved November 1, 2022; IBR approved for Sec. Sec.  60.5400b(a); 
60.5400c; 60.5401b(a); 60.5401c(a).
* * * * *
    (220) ASTM E260-96, General Gas Chromatography Procedures, approved 
April 10, 1996; IBR approved for Sec. Sec.  60.485a(d), 60.593(b), 
60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f), 60.5406(b), 
60.5406a(b)(3), 60.5400b(a)(2), 60.5401b(a)(2), 60.5406b(b)(3), 
60.5400c(a), and 60.5401c(a).
    (j) U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue 
NW, Washington, DC 20460; phone: (202) 272-0167; website: www.epa.gov.
* * * * *
    (2) EPA-454/B-08-002, Quality Assurance Handbook for Air Pollution 
Measurement Systems; Volume IV: Meteorological Measurements, Version 
2.0 (Final), March 2008; IBR approved for Appendix K to this part.
* * * * *
    (4) EPA-600/R-12/531, EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards, Issued May 2012; IBR 
approved for Sec. Sec.  60.5413(d); 60.5413a(d); 60.5413b(d); 
60.5413c(d).
* * * * *

Subpart KKK--Standards of Performance for Equipment Leaks of VOC 
From Onshore Natural Gas Processing Plants for Which Construction, 
Reconstruction, or Modification Commenced After January 20, 1984, 
and on or Before August 23, 2011

0
3. Section 60.630 is amended by adding paragraph (f) to read as 
follows:


Sec.  60.630  Applicability and designation of affected facility.

* * * * *
    (f) An affected facility must continue to comply with the 
requirements of this subpart until it begins complying with a more 
stringent requirement, that applies to the same affected facility, in 
an approved, and effective, State or Federal plan that implements 
subpart OOOOc of this part, or modifies or reconstructs after December 
6, 2022, and thus becomes subject to subpart OOOOb of this part.

[[Page 17035]]

Subpart OOOO--Standards of Performance for Crude Oil and Natural 
Gas Facilities for Which Construction, Modification, or 
Reconstruction Commenced After August 23, 2011, and on or Before 
September 18, 2015

0
4. Section 60.5360 is revised to read as follows:


Sec.  60.5360  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance 
schedules for the control of volatile organic compounds (VOC) and 
sulfur dioxide (SO<INF>2</INF>) emissions from affected facilities that 
commence construction, modification, or reconstruction after August 23, 
2011, and on or before September 18, 2015.

0
5. Amend Sec.  60.5365 by:
0
a. Revising the introductory text, and paragraphs (b), (c), and (d)(1);
0
b. Adding paragraph (d)(2); and
0
c. Revising the introductory text of paragraph (e).
    The revisions and addition read as follows:


Sec.  60.5365  Am I subject to this subpart?

    You are subject to the applicable provisions of this subpart if you 
are the owner or operator of one or more of the onshore affected 
facilities listed in paragraphs (a) through (g) of this section for 
which you commence construction, modification, or reconstruction after 
August 23, 2011, and on or before September 18, 2015. An affected 
facility must continue to comply with the requirements of this subpart 
until it begins complying with a more stringent requirement, that 
applies to the same affected facility, in an approved, and effective, 
state or Federal plan that implements subpart OOOOc of this part, or 
modifies or reconstructs after December 6, 2022, and thus becomes 
subject to subpart OOOOb of this part.
* * * * *
    (b) Each centrifugal compressor affected facility, which is a 
single centrifugal compressor using wet seals that is located between 
the wellhead and the point of custody transfer to the natural gas 
transmission and storage segment. A centrifugal compressor located at a 
well site, or an adjacent well site and servicing more than one well 
site, is not an affected facility under this subpart.
    (c) Each reciprocating compressor affected facility, which is a 
single reciprocating compressor located between the wellhead and the 
point of custody transfer to the natural gas transmission and storage 
segment. A reciprocating compressor located at a well site, or an 
adjacent well site and servicing more than one well site, is not an 
affected facility under this subpart.
    (d)(1) For the oil production segment (between the wellhead and the 
point of custody transfer to an oil pipeline), each pneumatic 
controller affected facility, which is a single continuous bleed 
natural gas-driven pneumatic controller operating at a natural gas 
bleed rate greater than 6 standard cubic feet per hour.
    (2) For the natural gas production segment (between the wellhead 
and the point of custody transfer to the natural gas transmission and 
storage segment and not including natural gas processing plants), each 
pneumatic controller affected facility, which is a single continuous 
bleed natural gas-driven pneumatic controller operating at a natural 
gas bleed rate greater than 6 standard cubic feet per hour.
* * * * *
    (e) Each storage vessel affected facility, which is a single 
storage vessel located in the oil and natural gas production segment, 
natural gas processing segment or natural gas transmission and storage 
segment, and has the potential for VOC emissions equal to or greater 
than 6 tons per year (tpy) as determined according to this section by 
October 15, 2013, for Group 1 storage vessels and by April 15, 2014, or 
30 days after startup (whichever is later) for Group 2 storage vessels, 
except as provided in paragraphs (e)(1) through (4) of this section. 
The potential for VOC emissions must be calculated using a generally 
accepted model or calculation methodology, based on the maximum average 
daily throughput determined for a 30-day period of production prior to 
the applicable emission determination deadline specified in this 
section. The determination may take into account requirements under a 
legally and practically enforceable limit in an operating permit or 
other requirement established under a Federal, State, local or Tribal 
authority.
* * * * *

0
6. Add Sec.  60.5371 to read as follows:


Sec.  60.5371   What standards apply to super-emitter events?

    This section applies to super-emitter events. For purposes of this 
section, a super-emitter event is defined as any emissions event that 
is located at an individual well site or compressor station and that is 
detected using remote detection methods and has a quantified emission 
rate of 100 kg/hr of methane or greater. Upon receiving a notification 
of a super emitter event issued by the EPA under Sec.  60.5371b(c), 
owners or operators must take the actions listed in paragraphs (a) and 
(b) of this section. Within 5 calendar days of receiving a notification 
from the EPA of a super-emitter event, the owner or operator of an oil 
and natural gas facility (e.g., a well site, centralized production 
facility, natural gas processing plant, or compressor station) must 
initiate a super-emitter event investigation.
    (a) Identification of super-emitter events. (1) If you do not own 
or operate an oil and natural gas facility within 50 meters from the 
latitude and longitude provided in the notification subject to the 
regulation under this subpart, report this result to the EPA under 
paragraph (e) of this section. Your super-emitter event investigation 
is deemed complete under this subpart.
    (2) If you own or operate an oil and natural gas facility within 50 
meters from the latitude and longitude provided in the notification 
subject to regulation under this subpart, you must investigate to 
determine the source of super-emitter event. The investigation may 
include but is not limited to the actions specified below in paragraphs 
(a)(2)(i) through (iii) of this section.
    (i) Review any maintenance activities or process activities from 
the affected facilities subject to regulation under this subpart, 
starting from the date of detection of the super-emitter event as 
identified in the notification, until the date of investigation, to 
determine if the activities indicate any potential source(s) of the 
super-emitter event emissions.
    (ii) Review all monitoring data from control devices (e.g., flares) 
from the affected facilities subject to regulation under this subpart 
from the initial date of detection of the super-emitter event as 
identified in the notification, until the date of receiving the 
notification from the EPA to identify malfunctions of control devices 
or periods when the control devices were not in compliance with 
applicable requirements and that indicate a potential source of the 
super-emitter event emissions.
    (iii) Screen the entire well site or compressor station with OGI, 
or Method 21 of appendix A-7 to this part, or an alternative test 
method(s) approved per Sec.  60.5398b(d), to determine if a super-
emitter event is present.
    (b) Super-emitter event report. For equipment subject to regulation 
under this subpart, you must submit the results of the super-emitter 
event investigation conducted under paragraph (a) of this section to 
the EPA in accordance with paragraph (b)(1) of this section. If the 
super-emitter event (i.e., emission at 100 kg/hr of methane or more) is 
ongoing at the time of the

[[Page 17036]]

initial report, submit the additional information in accordance with 
paragraph (b)(2) of this section. You must attest to the information 
included in the report as specified in paragraph (b)(3) of this 
section.
    (1) Within 15 days of receiving a notification from the EPA under 
Sec.  60.5371b(c), you must submit a report of the super-emitter event 
investigation conducted under paragraph (a) of this section through the 
Super-Emitter Program Portal. You must include the applicable 
information in paragraphs (b)(1)(i) through (viii) of this section in 
the report. If you have identified a demonstrable error in the 
notification, the report may include a statement of the demonstrable 
error.
    (i) Notification Report ID of the super-emitter event notification.
    (ii) Identification of whether you are the owner or operator of an 
oil and natural gas facility within 50 meters from the latitude and 
longitude provided in the EPA notification. If you do not own or 
operate an oil and natural gas facility within 50 meters from the 
latitude and longitude provided in the EPA notification, you are not 
required to report the information in paragraphs (b)(1)(iii) through 
(viii) of this section.
    (iii) General identification information for the facility, 
including, facility name, the physical address, applicable ID Number 
(e.g., EPA ID Number, API Well ID Number), the owner or operator or 
responsible official (where applicable) and their email address.
    (iv) Identification of whether there is an affected facility or 
associated equipment subject to regulation under this subpart at a well 
site or compressor station you own or operate within 50 meters from the 
latitude and longitude provided in the EPA notification.
    (v) Indication of whether you were able to identify the source of 
the super-emitter event. If you indicate you were unable to identify 
the source of the super-emitter event, you must certify that all 
applicable investigations specified in paragraphs (d)(6)(i) through (v) 
of this section have been conducted for all affected facilities and 
associated equipment subject to this subpart that are at this oil and 
natural gas facility, and you have determined that the affected 
facilities and associated equipment are not the source of the super-
emitter event. If you indicate that you were not able to identify the 
source of the super-emitter event, you are not required to report the 
information in paragraphs (b)(1)(vi) through (viii) of this section.
    (vi) The source(s) of the super-emitter event.
    (vii) Identification of whether the source of the super-emitter 
event is an affected facility or associated equipment subject to 
regulation under of this subpart. If the source of the super-emitter 
event is equipment subject to regulation under this subpart, identify 
the applicable regulation(s) under this subpart.
    (viii) Indication of whether the super-emitter event is ongoing at 
the time of the initial report submittal (i.e., emission at 100 kg/hr 
of methane or more).
    (A) If the super-emitter event is not ongoing at the time of the 
initial report submittal, provide the estimated date and time the 
super-emitter event ended.
    (B) If the super-emitter event is ongoing at the time of the 
initial report submittal, provide a short narrative of your plan to end 
the super-emitter event, including the targeted end date for the 
efforts to be completed and the super-emitter event ended.
    (2) If the super-emitter event is ongoing at the time of the 
initial report submittal, within 5 business days of the date the super-
emitter event ends, you must update your initial report through the 
Super-Emitter Program Portal (available at http://www.epa.gov/super-emitter) to provide the end date and time of the super-emitter event.
    (3) You must sign the following attestation must be signed by the 
owner or operator into when submitting data into the Super-Emitter 
Program Portal: ``I certify that the information provided in this 
report regarding the specified super-emitter event was prepared under 
my direction or supervision. I further certify that the investigations 
were conducted, and this report was prepared pursuant to the 
requirements of Sec.  60.5371(a) and (b). Based on my professional 
knowledge and experience, and inquiry of personnel involved in the 
assessment, the certification submitted herein is true, accurate, and 
complete. I am aware that knowingly false statements may be punishable 
by fine or imprisonment.''

0
7. Amend Sec.  60.5420 by revising paragraph (c)(5)(iv) to read as 
follows:


Sec.  60.5420  What are my notification, reporting, and recordkeeping 
requirements?

* * * * *
    (c) * * *
    (5) * * *
    (iv) For storage vessels that are skid-mounted or permanently 
attached to something that is mobile (such as trucks, railcars, barges, 
or ships), records indicating the number of consecutive days that the 
vessel is located at a site in the oil and natural gas production 
segment, natural gas processing segment or natural gas transmission and 
storage segment. If a storage vessel is removed from a site and, within 
30 days, is either returned to or replaced by another storage vessel at 
the site to serve the same or similar function, then the entire period 
since the original storage vessel was first located at the site, 
including the days when the storage vessel was removed, will be added 
to the count towards the number of consecutive days.
* * * * *

0
8. Amend Sec.  60.5430 by:
0
a. Removing the definition for ``Crude Oil and Natural Gas Production 
source category'';
0
b. Revising the definition for ``Custody transfer''; and
0
c. Removing the definition for ``Local distribution company (LDC) 
custody transfer station'' and ``Natural gas transmission and storage 
segment''.
    The revision reads as follows:


Sec.  60.5430  What definitions apply to this subpart?

* * * * *
    Custody transfer means the transfer of natural gas after processing 
and/or treatment in the producing operations, or from storage vessels 
or automatic transfer facilities or other such equipment, including 
product loading racks, to pipelines or any other forms of 
transportation.
* * * * *

Subpart OOOOa--Standards of Performance for Crude Oil and Natural 
Gas Facilities for Which Construction, Modification or 
Reconstruction Commenced After September 18, 2015 and On or Before 
December 6, 2022

0
9. Revise the subpart heading of subpart OOOOa to read as set forth 
above.
0
10. Revise Sec.  60.5360a to read as follows:


Sec.  60.5360a  What is the purpose of this subpart?

    (a) Scope. This subpart establishes emission standards and 
compliance schedules for the control of the pollutant greenhouse gases 
(GHG). The greenhouse gas standard in this subpart is in the form of a 
limitation on emissions of methane from affected facilities in the 
crude oil and natural gas source category that commence construction, 
modification, or reconstruction after September 18, 2015. This subpart 
also establishes emission standards and compliance schedules for the 
control of volatile organic compounds (VOC) and sulfur dioxide

[[Page 17037]]

(SO<INF>2</INF>) emissions from affected facilities in the crude oil 
and natural gas source category that commence construction, 
modification, or reconstruction after September 18, 2015, and on or 
before December 6, 2022.
    (b) Prevention of Significant Deterioration (PSD) and title V 
thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR 
51.166(b)(49)(ii), with respect to GHG emissions from affected 
facilities, the ``pollutant that is subject to the standard promulgated 
under section 111 of the Act'' shall be considered to be the pollutant 
that otherwise is subject to regulation under the Act as defined in 40 
CFR 51.166(b)(48) and in any State Implementation Plan (SIP) approved 
by the EPA that is interpreted to incorporate, or specifically 
incorporates, 40 CFR 51.166(b)(48).
    (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to 
GHG emissions from affected facilities, the ``pollutant that is subject 
to the standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is subject to regulation 
under the Clean Air Act as defined in 40 CFR 52.21(b)(49).
    (3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas 
emissions from affected facilities, the ``pollutant that is subject to 
any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 70.2.
    (4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas 
emissions from affected facilities, the ``pollutant that is subject to 
any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 71.2.

0
11. Amend Sec.  60.5365a by revising the introductory text and 
paragraph (a)(4) to read as follows:


Sec.  60.5365a  Am I subject to this subpart?

    You are subject to the applicable provisions of this subpart if you 
are the owner or operator of one or more of the onshore affected 
facilities listed in paragraphs (a) through (j) of this section, that 
is located within the Crude Oil and Natural Gas source category, as 
defined in Sec.  60.5430a, for which you commence construction, 
modification, or reconstruction after September 18, 2015, and on or 
before December 6, 2022. Facilities located inside and including the 
Local Distribution Company (LDC) custody transfer station are not 
subject to this subpart. An affected facility must continue to comply 
with the requirements of this subpart until it begins complying with a 
more stringent requirement, that applies to the same affected facility, 
in an approved, and effective, state or Federal plan that implements 
subpart OOOOc of this part, or modifies or reconstructs after December 
6, 2022, and thus becomes subject to subpart OOOOb of this part.
    (a) * * *
    (4) A well initially constructed after September 18, 2015, and on 
or before December 6, 2022, that conducts a well completion operation 
following hydraulic refracturing is considered an affected facility 
regardless of this provision.
* * * * *

0
12. Add Sec.  60.5371a to read as follows:


Sec.  60.5371a   What standards apply to super-emitter events?

    This section applies to super-emitter events. For purposes of this 
section, a super-emitter event is defined as any emissions event that 
is located at or near an oil and gas facility (e.g., individual well 
site, natural gas processing plant or compressor station) and that is 
detected using remote detection methods and has a quantified emission 
rate of 100 kg/hr of methane or greater. Upon receiving a notification 
of a super emitter event issued by the EPA under Sec.  60.5371b(c) in 
subpart OOOOb of this part, owners or operators must take the actions 
listed in paragraphs (a) and (b) of this section. Within 5 calendar 
days of receiving a notification from the EPA of a super-emitter event, 
the owner or operator of an oil and natural gas facility (e.g., a well 
site, centralized production facility, natural gas processing plant, or 
compressor station) must initiate a super-emitter event investigation.
    (a) Identification of super-emitter events. (1) If you do not own 
or operate an oil and natural gas facility within 50 meters from the 
latitude and longitude provided in the notification subject to the 
regulation under this subpart, report this result to the EPA under 
paragraph (e) of this section. Your super-emitter event investigation 
is deemed complete under this subpart.
    (2) If you own or operate an oil and natural gas facility within 50 
meters from the latitude and longitude provided in the notification, 
and there is an affected facility or associated equipment subject to 
this subpart onsite, you must investigate to determine the source of 
the super-emitter event in accordance with paragraph (a)(2) of this 
section, maintain records of your investigation, and report the results 
in accordance with paragraph (b) of this section.
    (3) The investigation required by paragraph (a)(2) of this section 
may include but is not limited to the actions specified below in 
paragraphs (a)(3)(i) through (iv) of this section.
    (i) Review any maintenance activities or process activities from 
the affected facilities subject to regulation under this subpart, 
starting from the date of detection of the super-emitter event as 
identified in the notification, until the date of investigation, to 
determine if the activities indicate any potential source(s) of the 
super-emitter event emissions.
    (ii) Review all monitoring data from control devices (e.g., flares) 
from the affected facilities subject to regulation under this subpart 
from the initial date of detection of the super-emitter event as 
identified in the notification, until the date of receiving the 
notification from the EPA to identify malfunctions of control devices 
or periods when the control devices were not in compliance with 
applicable requirements and that indicate a potential source of the 
super-emitter event emissions.
    (iii) If you conducted a fugitive emissions survey in accordance 
with Sec.  60.5397a between the initial date of detection of the super-
emitter event as identified in the notification and the date the 
notification from the EPA was received, review the results of the 
survey to identify any potential source(s) of the super-emitter event 
emissions.
    (iv) Screen the entire facility with OGI, Method 21 of appendix A-7 
to this part, or an alternative test method(s) approved per Sec.  
60.5398b(d) of subpart OOOOb of this part, to determine if a super-
emitter event is present.
    (b) Super-emitter event report. You must submit the results of the 
super-emitter event investigation conducted under paragraph (a) of this 
section to the EPA in accordance with paragraph (b)(1) of this section. 
If the super-emitter event (i.e., emission at 100 kg/hr of methane or 
more) is ongoing at the time of this initial report, submit the 
additional information in accordance with paragraph (b)(2) of this 
section. You must attest to the information included in the report as 
specified in paragraph (b)(3) of this section.
    (1) Within 15 days of receiving a notification from the EPA under 
Sec.  60.5371b(c), you must submit a report of the super-emitter event 
investigation conducted under paragraph (a) of this section through the 
Super-Emitter Program Portal, at www.epa.gov/super-emitter. You must 
include the applicable information in paragraphs (b)(1)(i) through 
(viii) of this section in the report. If you have identified a 
demonstrable error in the notification,

[[Page 17038]]

the report may include a statement of the demonstrable error.
    (i) Notification Report ID of the super-emitter event notification 
(which is provided in the EPA notification).
    (ii) Identification of whether you are the owner or operator of an 
oil and natural gas facility within 50 meters from the latitude and 
longitude provided in the EPA notification. If you do not own or 
operate an oil and natural gas facility within 50 meters from the 
latitude and longitude provided in the EPA notification, you are not 
required to report the information in paragraphs (b)(1)(iii) through 
(viii) of this section.
    (iii) General identification information for the facility, 
including facility name, the physical address, applicable ID Number 
(e.g., EPA ID Number, API Well ID Number), the owner or operator or 
responsible official (where applicable), and their email address.
    (iv) Identification of whether there is an affected facility or 
associated equipment subject to regulation under this subpart at this 
oil and natural gas facility.
    (v) Indication of whether you were able to identify the source of 
the super-emitter event. If you indicate you were unable to identify 
the source of the super-emitter event, you must certify that all 
applicable investigations specified in paragraphs (a)(2)(i) through 
(iv) of this section have been conducted for all affected facilities 
and associated equipment subject to regulation under this subpart that 
are at this oil and natural gas facility, and you have determined that 
these affected facilities and associated equipment are not the source 
of the super-emitter event. If you indicate that you were not able to 
identify the source of the super-emitter event, you are not required to 
report the information in paragraphs (b)(1)(vi) through (viii) of this 
section.
    (vi) The source(s) of the super-emitter event.
    (vii) Identification of whether the source of the super-emitter 
event is an affected facility or associated equipment subject to 
regulation under of this subpart. If the source of the super-emitter 
event is an affected facility or associated equipment subject to 
regulation under this subpart, identify the applicable regulation(s) 
under this subpart.
    (viii) Indication of whether the super-emitter event is ongoing at 
the time of the initial report submittal (i.e., emissions at 100 kg/hr 
of methane or more).
    (A) If the super-emitter event is not ongoing at the time of the 
initial report submittal, provide the actual (or if not known, 
estimated) date and time the super-emitter event ended.
    (B) If the super-emitter event is ongoing at the time of the 
initial report submittal, provide a short narrative of your plan to end 
the super-emitter event, including the targeted end date for the 
efforts to be completed and the super-emitter event ended.
    (2) If the super-emitter event is ongoing at the time of the 
initial report submittal, within 5 business days of the date the super-
emitter event ends you must update your initial report through the 
Super-Emitter Program Portal, to provide the end date and time of the 
super-emitter event.
    (3) You must sign the following attestation when submitting data 
into the Super-Emitter Program Portal: ``I certify that the information 
provided in this report regarding the specified super-emitter event was 
prepared under my direction or supervision. I further certify that the 
investigations were conducted, and this report was prepared pursuant to 
the requirements of Sec.  60.5371a(a) and (b). Based on my professional 
knowledge and experience, and inquiry of personnel involved in the 
assessment, the certification submitted herein is true, accurate, and 
complete. I am aware that knowingly false statements may be punishable 
by fine or imprisonment.''

0
13. Amend Sec.  60.5375a by revising the section heading and the 
introductory text to read as follows:


Sec.  60.5375a  What GHG and VOC standards apply to well affected 
facilities?

    If you are the owner or operator of a well affected facility as 
described in Sec.  60.5365a(a) that also meets the criteria for a well 
affected facility in Sec.  60.5365(a) (in subpart OOOO of this part), 
you must reduce GHG (in the form of a limitation on emissions of 
methane) and VOC emissions by complying with paragraphs (a) through (g) 
of this section. If you own or operate a well affected facility as 
described in Sec.  60.5365a(a) that does not meet the criteria for a 
well affected facility in Sec.  60.5365(a) (in subpart OOOO of this 
part), you must reduce GHG and VOC emissions by complying with 
paragraphs (f)(3) and (4) or paragraph (g) of this section for each 
well completion operation with hydraulic fracturing prior to November 
30, 2016, and you must comply with paragraphs (a) through (g) of this 
section for each well completion operation with hydraulic fracturing on 
or after November 30, 2016.
* * * * *

0
14. Amend Sec.  60.5380a by revising the section heading, introductory 
text, and paragraph (a)(1) to read as follows:


Sec.  60.5380a  What GHG and VOC standards apply to centrifugal 
compressor affected facilities?

    You must comply with the GHG and VOC standards in paragraphs (a) 
through (d) of this section for each centrifugal compressor affected 
facility.
    (a)(1) You must reduce methane and VOC emissions from each 
centrifugal compressor wet seal fluid degassing system by 95.0 percent.
* * * * *

0
15. Amend Sec.  60.5385a by revising the section heading, introductory 
text, and paragraph (a)(3) to read as follows:


Sec.  60.5385a  What GHG and VOC standards apply to reciprocating 
compressor affected facilities?

    You must reduce GHG (in the form of a limitation on emissions of 
methane) and VOC emissions by complying with the standards in 
paragraphs (a) through (d) of this section for each reciprocating 
compressor affected facility.
    (a) * * *
    (3) Collect the methane and VOC emissions from the rod packing 
using a rod packing emissions collection system that operates under 
negative pressure and route the rod packing emissions to a process 
through a closed vent system that meets the requirements of Sec.  
60.5411a(a) and (d).
* * * * *

0
16. Amend Sec.  60.5390a by revising the section heading and 
introductory text to read as follows:


Sec.  60.5390a  What GHG and VOC standards apply to pneumatic 
controller affected facilities?

    For each pneumatic controller affected facility you must comply 
with the GHG and VOC standards, based on natural gas as a surrogate for 
GHG and VOC, in either paragraph (b)(1) or (c)(1) of this section, as 
applicable. Pneumatic controllers meeting the conditions in paragraph 
(a) of this section are exempt from the requirements in paragraph 
(b)(1) or (c)(1) of this section.
* * * * *

0
17. Amend Sec.  60.5393a by revising the section heading and 
introductory text to read as follows:


Sec.  60.5393a  What GHG and VOC standards apply to pneumatic pump 
affected facilities?

    For each pneumatic pump affected facility you must comply with the 
GHG and VOC standards, based on natural gas as a surrogate for GHG and 
VOC, in either paragraph (a) or (b) of this

[[Page 17039]]

section, as applicable, on or after November 30, 2016.
* * * * *

0
18. Amend Sec.  60.5397a by:
0
a. Revising the section heading, introductory text, and paragraph (a);
0
b. Revising the introductory text of paragraph (g) and paragraph 
(g)(2);
0
c. Adding paragraph (g)(6); and
0
d. Revising paragraph (h)(3).
    The revisions and addition read as follows:


Sec.  60.5397a  What fugitive emissions GHG and VOC standards apply to 
the affected facility which is the collection of fugitive emissions 
components at a well site and the affected facility which is the 
collection of fugitive emissions components at a compressor station?

    For each affected facility under Sec.  60.5365a(i) and (j), you 
must reduce GHG (in the form of a limitation on emissions of methane) 
and VOC emissions by complying with the requirements of paragraphs (a) 
through (j) of this section. The requirements in this section are 
independent of the closed vent system and cover requirements in Sec.  
60.5411a. Alternatively, you may comply with the requirements of Sec.  
60.5398b, including the notification, recordkeeping, and reporting 
requirements outlined in Sec.  60.5424b. For the purpose of this 
subpart, compliance with the requirements in Sec.  60.5398b will be 
deemed compliance with this section. When complying with Sec.  
60.5398b, the definitions in Sec.  60.5430b shall apply for those 
activities conducted under Sec.  60.5398b.
    (a) You must monitor all fugitive emission components, as defined 
in Sec.  60.5430a, in accordance with paragraphs (b) through (g) of 
this section. You must repair all sources of fugitive emissions in 
accordance with paragraph (h) of this section. You must keep records in 
accordance with paragraph (i) of this section and report in accordance 
with paragraph (j) of this section. For purposes of this section, 
fugitive emissions are defined as any visible emission from a fugitive 
emissions component observed using optical gas imaging or an instrument 
reading of 500 parts per million (ppm) or greater using Method 21 of 
appendix A-7 to this part.
* * * * *
    (g) A monitoring survey of each collection of fugitive emissions 
components at a well site or at a compressor station must be performed 
at the frequencies specified in paragraphs (g)(1) and (2) of this 
section, with the exceptions noted in paragraphs (g)(3) through (6) of 
this section.
* * * * *
    (2) Except as provided in this paragraph (g)(2), a monitoring 
survey of the collection of fugitive emissions components at a 
compressor station must be conducted at least quarterly after the 
initial survey. Consecutive quarterly monitoring surveys must be 
conducted at least 60 days apart. A monitoring survey of the collection 
of fugitive emissions components at a compressor station located on the 
Alaskan North Slope must be conducted at least annually. Consecutive 
annual monitoring surveys must be conducted at least 9 months apart and 
no more than 13 months apart.
* * * * *
    (6) The requirements of paragraph (g)(2) of this section are waived 
for any collection of fugitive emissions components at a compressor 
station located within an area that has an average calendar month 
temperature below 0 [deg]F for two of three consecutive calendar months 
of a quarterly monitoring period. The calendar month temperature 
average for each month within the quarterly monitoring period must be 
determined using historical monthly average temperatures over the 
previous three years as reported by a National Oceanic and Atmospheric 
Administration source or other source approved by the Administrator. 
The requirements of paragraph (g)(2) of this section shall not be 
waived for two consecutive quarterly monitoring periods.
    (h) * * *
    (3) Delay of repair will be allowed if the conditions in paragraphs 
(h)(3)(i) or (ii) of this section are met.
    (i) If the repair is technically infeasible, would require a vent 
blowdown, a compressor station shutdown, a well shutdown or well shut-
in, or would be unsafe to repair during operation of the unit, the 
repair must be completed during the next scheduled compressor station 
shutdown for maintenance, scheduled well shutdown, scheduled well shut-
in, after a scheduled vent blowdown, or within 2 years of detecting the 
fugitive emissions, whichever is earliest. For purposes of this 
paragraph (h)(3), a vent blowdown is the opening of one or more 
blowdown valves to depressurize major production and processing 
equipment, other than a storage vessel.
    (ii) If the repair requires replacement of a fugitive emissions 
component or a part thereof, but the replacement cannot be acquired and 
installed within the repair timelines specified in paragraphs (h)(1) 
and (2) of this section due to either of the conditions specified in 
paragraphs (h)(3)(ii)(A) or (B) of this section, the repair must be 
completed in accordance with paragraph (h)(3)(ii)(C) of this section 
and documented in accordance with Sec.  60.5420a(c)(15)(vii)(I).
    (A) Valve assembly supplies had been sufficiently stocked but are 
depleted at the time of the required repair.
    (B) A replacement fugitive emissions component or a part thereof 
requires custom fabrication.
    (C) The required replacement must be ordered no later than 10 
calendar days after the first attempt at repair. The repair must be 
completed as soon as practicable, but no later than 30 calendar days 
after receipt of the replacement component, unless the repair requires 
a compressor station or well shutdown. If the repair requires a 
compressor station or well shutdown, the repair must be completed in 
accordance with the timeframe specified in paragraph (h)(3)(i) of this 
section.
* * * * *

0
19. Amend Sec.  60.5398a by revising the section heading and paragraph 
(a) to read as follows:


Sec.  60.5398a  What are the alternative means of emission limitations 
for GHG and VOC from well completions, reciprocating compressors, the 
collection of fugitive emissions components at a well site and the 
collection of fugitive emissions components at a compressor station?

    (a) If, in the Administrator's judgment, an alternative means of 
emission limitation will achieve a reduction in GHG (in the form of a 
limitation on emissions of methane) and VOC emissions at least 
equivalent to the reduction in GHG and VOC emissions achieved under 
Sec.  60.5375a, Sec.  60.5385a, or Sec.  60.5397a, the Administrator 
will publish, in the Federal Register, a document permitting the use of 
that alternative means for the purpose of compliance with Sec.  
60.5375a, Sec.  60.5385a, or Sec.  60.5397a. The authority to approve 
an alternative means of emission limitation is retained by the 
Administrator and shall not be delegated to States under section 111(c) 
of the Clean Air Act (CAA).
* * * * *

0
20. Amend Sec.  60.5399a by revising paragraphs (a), (f), (i), and (m) 
to read as follows:

[[Page 17040]]

Sec.  60.5399a  What alternative fugitive emissions standards apply to 
the affected facility which is the collection of fugitive emissions 
components at a well site and the affected facility which is the 
collection of fugitive emissions components at a compressor station: 
Equivalency with state, local, and Tribal programs?

* * * * *
    (a) Alternative fugitive emissions standards. If, in the 
Administrator's judgment, an alternative fugitive emissions standard 
will achieve a reduction in methane and VOC emissions at least 
equivalent to the reductions achieved under Sec.  60.5397a, the 
Administrator will publish, in the Federal Register, a notice 
permitting use of the alternative fugitive emissions standard for the 
purpose of compliance with Sec.  60.5397a. The authority to approve 
alternative fugitive emissions standards is retained by the 
Administrator and shall not be delegated to States under section 111(c) 
of the CAA.
* * * * *
    (f) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a well site or a compressor 
station in the State of California. An affected facility, which is the 
collection of fugitive emissions components, as defined in Sec.  
60.5430a, located at a well site or a compressor station in the State 
of California may elect to comply with the monitoring, repair, and 
recordkeeping requirements in the California Code of Regulations, title 
17, sections 95665-95667, effective January 1, 2020, as an alternative 
to complying with the requirements in Sec.  60.5397a(f)(1) and (2), 
(g)(1) through (4), (h), and (i). The information specified in Sec.  
60.5420a(b)(7)(iii)(A) and the information specified in either Sec.  
60.5420a(b)(7)(iii)(B) or (C) may be provided as an alternative to the 
requirements in Sec.  60.5397a(j).
* * * * *
    (i) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a compressor station in the 
State of Ohio. An affected facility, which is the collection of 
fugitive emissions components, as defined in Sec.  60.5430a, located at 
a compressor station in the State of Ohio may elect to comply with the 
monitoring, repair, and recordkeeping requirements in Ohio General 
Permit 18.1, effective February 7, 2017, as an alternative to complying 
with the requirements in Sec.  60.5397a(f)(2), (g)(2) through (4), (h), 
and (i), provided the monitoring instrument used is optical gas imaging 
or a Method 21 instrument (see appendix A-7 to this part) with a leak 
definition and reading of 500 ppm or greater. Monitoring must be 
conducted on at least a quarterly basis and skip periods cannot be 
applied. The information specified in Sec.  60.5420a(b)(7)(iii)(A) and 
the information specified in either Sec.  60.5420a(b)(7)(iii)(B) or (C) 
may be provided as an alternative to the requirements in Sec.  
60.5397a(j).
* * * * *
    (m) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a compressor station in the 
State of Texas. An affected facility, which is the collection of 
fugitive emissions components, as defined in Sec.  60.5430a, located at 
a compressor in the State of Texas may elect to comply with the 
monitoring, repair, and recordkeeping requirements in the Air Quality 
Standard Permit for Oil and Gas Handling and Production Facilities, 
section I(6), effective November 8, 2012, or at 30 Texas Administrative 
Code section 116.620, effective September 4, 2000, as an alternative to 
complying with the requirements in Sec.  60.5397a(f)(2), (g)(2) through 
(4), (h), and (i), provided the monitoring instrument used is optical 
gas imaging or a Method 21 instrument (see appendix A-7 to this part) 
with a leak definition and reading of 500 ppm or greater. Monitoring 
must be conducted on at least a quarterly basis and skip periods may 
not be applied. If using the alternative in this paragraph (m), the 
information specified in Sec.  60.5420a(b)(7)(iii)(A) and (C) must be 
provided in lieu of the requirements in Sec.  60.5397a(j).
* * * * *

0
21. Amend Sec.  60.5400a by revising the section heading and paragraph 
(c) to read as follows:


Sec.  60.5400a  What equipment leak GHG and VOC standards apply to 
affected facilities at an onshore natural gas processing plant?

* * * * *
    (c) You may apply to the Administrator for permission to use an 
alternative means of emission limitation that achieves a reduction in 
emissions of methane and VOC at least equivalent to that achieved by 
the controls required in this subpart according to the requirements of 
Sec.  60.5402a.
* * * * *


Sec.  60.5401a   What are the exceptions to the equipment leak GHG and 
VOC standards for affected facilities at onshore natural gas processing 
plants?

0
22. Amend Sec.  60.5401a by revising the section heading to read as set 
forth above.

0
23. Amend Sec.  60.5402a by revising the section heading, paragraph 
(a), and paragraph (d)(2) introductory text to read as follows:


Sec.  60.5402a  What are the alternative means of emission limitations 
for GHG and VOC equipment leaks from onshore natural gas processing 
plants?

    (a) If, in the Administrator's judgment, an alternative means of 
emission limitation will achieve a reduction in GHG and VOC emissions 
at least equivalent to the reduction in GHG and VOC emissions achieved 
under any design, equipment, work practice or operational standard, the 
Administrator will publish, in the Federal Register, a document 
permitting the use of that alternative means for the purpose of 
compliance with that standard. The document may condition permission on 
requirements related to the operation and maintenance of the 
alternative means.
* * * * *
    (d) * * *
    (2) The application must include operation, maintenance, and other 
provisions necessary to assure reduction in methane and VOC emissions 
at least equivalent to the reduction in methane and VOC emissions 
achieved under the design, equipment, work practice or operational 
standard in paragraph (a) of this section by including the information 
specified in paragraphs (d)(2)(i) through (x) of this section.
* * * * *

0
24. Amend Sec.  60.5410a by:
0
a. Revising paragraphs (a) introductory text, (b)(1), (d) introductory 
text, and (f); and
0
b. Removing paragraph (k).
    The revisions read as follows:


Sec.  60.5410a  How do I demonstrate initial compliance with the 
standards for my well, centrifugal compressor, reciprocating 
compressor, pneumatic controller, pneumatic pump, storage vessel, 
collection of fugitive emissions components at a well site, collection 
of fugitive emissions components at a compressor station, and equipment 
leaks at onshore natural gas processing plants and sweetening unit 
affected facilities?

* * * * *
    (a) To achieve initial compliance with the methane and VOC 
standards for each well completion operation conducted at your well 
affected facility

[[Page 17041]]

you must comply with paragraphs (a)(1) through (4) of this section.
* * * * *
    (b)(1) To achieve initial compliance with standards for your 
centrifugal compressor affected facility you must reduce methane and 
VOC emissions from each centrifugal compressor wet seal fluid degassing 
system by 95.0 percent or greater as required by Sec.  60.5380a(a) and 
as demonstrated by the requirements of Sec.  60.5413a.
* * * * *
    (d) To achieve initial compliance with methane and VOC emission 
standards for your pneumatic controller affected facility you must 
comply with the requirements specified in paragraphs (d)(1) through (6) 
of this section, as applicable.
* * * * *
    (f) For affected facilities at onshore natural gas processing 
plants, initial compliance with the methane and VOC standards is 
demonstrated if you are in compliance with the requirements of Sec.  
60.5400a.
* * * * *

0
25. Amend Sec.  60.5412a by revising paragraphs (a)(1)(i) and (a)(2) to 
read as follows:


Sec.  60.5412a  What additional requirements must I meet for 
determining initial compliance with control devices used to comply with 
the emission standards for my centrifugal compressor, and storage 
vessel affected facilities?

* * * * *
    (a) * * *
    (1) * * *
    (i) You must reduce the mass content of methane and VOC in the 
gases vented to the device by 95.0 percent by weight or greater as 
determined in accordance with the requirements of Sec.  60.5413a(b), 
with the exceptions noted in Sec.  60.5413a(a).
* * * * *
    (2) Each vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device must be designed and 
operated to reduce the mass content of methane and VOC in the gases 
vented to the device by 95.0 percent by weight or greater as determined 
in accordance with the requirements of Sec.  60.5413a(b). As an 
alternative to the performance testing requirements in Sec.  
60.5413a(b), you may demonstrate initial compliance by conducting a 
design analysis for vapor recovery devices according to the 
requirements of Sec.  60.5413a(c).
* * * * *

0
26. Amend Sec.  60.5413a by revising paragraphs (b)(4) introductory 
text, (b)(4)(ii) and (d)(11)(iii) to read as follows:


Sec.  60.5413a  What are the performance testing procedures for control 
devices used to demonstrate compliance at my centrifugal compressor and 
storage vessel affected facilities?

* * * * *
    (b) * * *
    (4) You must use Method 25A of appendix A-7 to this part to measure 
TOC, as propane, to determine compliance with the TOC exhaust gas 
concentration limit specified in Sec.  60.5412a(a)(1)(ii) or 
(d)(1)(iv)(B). If you are determining compliance with the TOC exhaust 
gas concentration limit specified in Sec.  60.5412a(d)(1)(iv)(B), you 
may also use Method 18 of appendix A-6 to this part to measure methane 
and ethane, and you may subtract the measured concentration of methane 
and ethane from the Method 25A measurement to demonstrate compliance 
with the concentration limit. You must determine the concentration in 
parts per million by volume on a wet basis and correct it to 3 percent 
oxygen, using the procedures in paragraphs (b)(4)(i) through (iii) of 
this section.
* * * * *
    (ii) If you are determining compliance with the TOC exhaust gas 
concentration limit specified in Sec.  60.5412a(d)(1)(iv)(B), you may 
subtract the concentration of methane and ethane from the Method 25A 
TOC, as propane, concentration for each run.
* * * * *
    (d) * * *
    (11) * * *
    (iii) A manufacturer must demonstrate a destruction efficiency of 
at least 95 percent for THC, as propane. A control device model that 
demonstrates a destruction efficiency of 95 percent for THC, as 
propane, will meet the control requirement for 95 percent destruction 
of VOC and methane (if applicable) required under this subpart.
* * * * *

0
27. Amend Sec.  60.5415a by:
0
a. Revising paragraphs (b)(1) and paragraph (f); and
0
b. Removing paragraphs (i) and (j).
    The revisions read as follows:


Sec.  60.5415a  How do I demonstrate continuous compliance with the 
standards for my well, centrifugal compressor, reciprocating 
compressor, pneumatic controller, pneumatic pump, storage vessel, 
collection of fugitive emissions components at a well site, and 
collection of fugitive emissions components at a compressor station 
affected facilities, equipment leaks at onshore natural gas processing 
plants and sweetening unit affected facilities?

* * * * *
    (b) * * *
    (1) You must reduce methane and VOC emissions from the wet seal 
fluid degassing system by 95.0 percent or greater.
* * * * *
    (f) For affected facilities at onshore natural gas processing 
plants, continuous compliance with methane and VOC requirements is 
demonstrated if you are in compliance with the requirements of Sec.  
60.5400a.
* * * * *

0
28. Amend Sec.  60.5420a by:
0
a. Removing and reserving paragraph (b)(7)(i)(C);
0
b. Adding paragraph (b)(7)(iv);
0
c. Revising paragraphs (b)(9)(i), (b)(11), and (c)(5)(iv);
0
d. Removing and reserving paragraphs (c)(15)(ii) through (iv);
0
e. Revising the introductory text of paragraph (c)(15)(vii)(I) and 
paragraph (c)(15)(vii)(I)(8); and
0
f. Adding paragraphs (c)(15)(vii)(I)(9) and (c)(15)(ix).
    The additions and revisions read as follows:


Sec.  60.5420a  What are my notification, reporting, and recordkeeping 
requirements?

* * * * *
    (b) * * *
    (7) * * *
    (iv) If you comply with the alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraph 
(b)(7)(ii) of this section, you must provide the information specified 
in Sec.  60.5424b.
* * * * *
    (9) * * *
    (i) For data collected using test methods supported by the EPA's 
Electronic Reporting Tool (ERT) as listed on the EPA's ERT website 
(https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test, you must submit the 
results of the performance test to the EPA via the Compliance and 
Emissions Data Reporting Interface (CEDRI), except as outlined in this 
paragraph (b)(9)(i). (CEDRI can be accessed through the

[[Page 17042]]

EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Performance 
test data must be submitted in a file format generated through the use 
of the EPA's ERT or an alternate electronic file format consistent with 
the extensible markup language (XML) schema listed on the EPA's ERT 
website. The EPA will make all the information submitted through CEDRI 
available to the public without further notice to you. Do not use CEDRI 
to submit information you claim as confidential business information 
(CBI). Although we do not expect persons to assert a claim of CBI, if 
you wish to assert a CBI claim, you must submit a complete file 
generated through the use of the EPA's ERT or an alternate electronic 
file consistent with the XML schema listed on the EPA's ERT website, 
including information claimed to be CBI, to the EPA following the 
procedures in paragraphs (b)(9)(i)(A) and (B) of this section. Clearly 
mark the part or all of the information that you claim to be CBI. 
Information not marked as CBI may be authorized for public release 
without prior notice. Information marked as CBI will not be disclosed 
except in accordance with procedures set forth in 40 CFR part 2. All 
CBI claims must be asserted at the time of submission. Anything 
submitted using CEDRI cannot later be claimed CBI. Furthermore, under 
CAA section 114(c), emissions data is not entitled to confidential 
treatment, and the EPA is required to make emissions data available to 
the public. Thus, emissions data will not be protected as CBI and will 
be made publicly available. The same ERT or alternate file submitted to 
the CBI office with the CBI omitted must be submitted to the EPA via 
the EPA's CDX as described earlier in this paragraph (b)(9)(i).
    (A) The preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol, or 
other online file sharing services. Electronic submissions must be 
transmitted directly to the OAQPS CBI Office at the email address 
<a href="/cdn-cgi/l/email-protection#5a353b2b2a293938331a3f2a3b743d352c"><span class="__cf_email__" data-cfemail="117e70606162727378517461703f767e67">[email protected]</span></a>, and as described above, should include clear CBI 
markings. ERT files should be flagged to the attention of the Group 
Leader, Measurement Policy Group. 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 <a href="/cdn-cgi/l/email-protection#bad5dbcbcac9d9d8d3fadfcadb94ddd5cc"><span class="__cf_email__" data-cfemail="57383626272434353e1732273679303821">[email protected]</span></a> to request a file transfer link.
    (B) If you cannot transmit the file electronically, you may send 
CBI information through the postal service to the following address: 
U.S. EPA, Attn: OAQPS Document Control Officer and Measurement Policy 
Group Leader, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 
12055, RTP, NC 27711. The mailed CBI material should be double wrapped 
and clearly marked. Any CBI markings should not show through the outer 
envelope.
* * * * *
    (11) You must submit reports to the EPA via CEDRI, except as 
outlined in this paragraph (b)(11). CEDRI can be accessed through the 
EPA's CDX (https://cdx.epa.gov/). You must use the appropriate 
electronic report template on the CEDRI website for this subpart 
(https://www.epa.gov/electronic-reporting-air-emissions/cedri/). If the 
reporting form specific to this subpart is not available on the CEDRI 
website at the time that the report is due, you must submit the report 
to the Administrator at the appropriate address listed in Sec.  60.4. 
Once the form has been available in CEDRI for at least 90 calendar 
days, you must begin submitting all subsequent reports via CEDRI. The 
date reporting forms become available will be listed on the CEDRI 
website. Unless the Administrator or delegated state agency or other 
authority has approved a different schedule for submission of reports, 
the reports must be submitted by the deadlines specified in this 
subpart, regardless of the method in which the reports are submitted. 
The EPA will make all the information submitted through CEDRI available 
to the public without further notice to you. Do not use CEDRI to submit 
information you claim as CBI. Although we do not expect persons to 
assert a claim of CBI, if you wish to assert a CBI claim for some of 
the information in the report, submit a complete file using the 
appropriate electronic report template on the CEDRI website, including 
information claimed to be CBI, to the EPA following the procedures in 
paragraphs (b)(11)(i) and (ii) of this section. Clearly mark the part 
or all of the information that you claim to be CBI. Information not 
marked as CBI may be authorized for public release without prior 
notice. Information marked as CBI will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2. All CBI claims 
must be asserted at the time of submission. Anything submitted using 
CEDRI cannot later be claimed CBI. Furthermore, under CAA section 
114(c), emissions data is not entitled to confidential treatment, and 
the EPA is required to make emissions data available to the public. 
Thus, emissions data will not be protected as CBI and will be made 
publicly available. Submit the same file submitted to the CBI office 
with the CBI omitted must be submitted to the EPA via the EPA's CDX as 
described earlier in this paragraph (b)(11).
    (i) The preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol, or 
other online file sharing services. Electronic submissions must be 
transmitted directly to the OAQPS CBI Office at the email address 
<a href="/cdn-cgi/l/email-protection#d7b8b6a6a7a4b4b5be97b2a7b6f9b0b8a1"><span class="__cf_email__" data-cfemail="ec838d9d9c9f8f8e85ac899c8dc28b839a">[email protected]</span></a>, and as described above, should include clear CBI 
markings. Files should be flagged to the attention of the Oil and 
Natural Gas Sector Lead. 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 
<a href="/cdn-cgi/l/email-protection#8ae5ebfbfaf9e9e8e3caeffaeba4ede5fc"><span class="__cf_email__" data-cfemail="93fcf2e2e3e0f0f1fad3f6e3f2bdf4fce5">[email protected]</span></a> to request a file transfer link.
    (ii) If you cannot transmit the file electronically, you may send 
CBI information through the postal service to the following address: 
U.S. EPA, Attn: OAQPS Document Control Officer and Oil and Natural Gas 
Sector Lead, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 
12055, RTP, NC 27711. The mailed CBI material should be double wrapped 
and clearly marked. Any CBI markings should not show through the outer 
envelope.
* * * * *
    (c) * * *
    (5) * * *
    (iv) For storage vessels that are skid-mounted or permanently 
attached to something that is mobile (such as trucks, railcars, barges, 
or ships), records indicating the number of consecutive days that the 
vessel is located at a site in the crude oil and natural gas production 
segment, natural gas processing segment, or natural gas transmission 
and storage segment. If a storage vessel is removed from a site and, 
within 30 days, is either returned to the site or replaced by another 
storage vessel at the site to serve the same or similar function, then 
the entire period since the original storage vessel was first located 
at the site, including the days when the storage vessel was removed, 
will be added to the count towards the number of consecutive days.
* * * * *
    (15) * * *
    (vii) * * *
    (I) Documentation of each fugitive emission detected during the 
monitoring survey, including the information specified in paragraphs 
(c)(15)(vii)(I)(1) through (9) of this section.
* * * * *
    (8) For each fugitive emission component placed on delay of repair 
for

[[Page 17043]]

reason of replacement component unavailability, the operator must 
document: the date the component was added to the delay of repair list, 
the date the replacement fugitive component or part thereof was 
ordered, the anticipated component delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the component.
    (9) Date of planned shutdowns that occur while there are any 
components that have been placed on delay of repair.
* * * * *
    (ix) If you comply with the alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(c)(15)(vi) through (vii) of this section, you must maintain the 
records specified in Sec.  60.5424b.
* * * * *


Sec.  60.5421a  What are my additional recordkeeping requirements for 
my affected facility subject to GHG and VOC requirements for onshore 
natural gas processing plants?

0
29. Amend Sec.  60.5421a by revising the section heading to read as set 
forth above.


Sec.  60.5422a  What are my additional reporting requirements for my 
affected facility subject to GHG and VOC requirements for onshore 
natural gas processing plants?

0
30. Amend Sec.  60.5422a by revising the section heading to read as set 
forth above.

0
31. Amend Sec.  60.5430a by:
0
a. Revising definitions for ``Compressor station'', ``Crude Oil and 
Natural Gas Production source category'', ``Equipment'', and ``Fugitive 
emissions component''; and
0
b. Removing definition for ``Natural gas transmission and storage 
segment''.
    The revisions read as follows:


Sec.  60.5430a  What definitions apply to this subpart?

* * * * *
    Compressor station means any permanent combination of one or more 
compressors that move natural gas at increased pressure through 
gathering or transmission pipelines, or into or out of storage. This 
includes, but is not limited to, gathering and boosting stations and 
transmission compressor stations. The combination of one or more 
compressors located at a well site, or located at an onshore natural 
gas processing plant, is not a compressor station for purposes of Sec.  
60.5397a.
* * * * *
    Crude oil and natural gas source category means:
    (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.
* * * * *
    Equipment, as used in the standards and requirements in this 
subpart relative to the equipment leaks of GHG (in the form of methane) 
VOC from onshore natural gas processing plants, means each pump, 
pressure relief device, open-ended valve or line, valve, and flange or 
other connector that is in VOC service or in wet gas service, and any 
device or system required by those same standards and requirements in 
this subpart.
* * * * *
    Fugitive emissions component means any component that has the 
potential to emit fugitive emissions of methane or VOC at a well site 
or compressor station, including valves, connectors, pressure relief 
devices, open-ended lines, flanges, covers and closed vent systems not 
subject to Sec.  60.5411 or Sec.  60.5411a, thief hatches or other 
openings on a controlled storage vessel not subject to Sec.  60.5395 or 
Sec.  60.5395a, compressors, instruments, and meters. Devices that vent 
as part of normal operations, such as natural gas-driven pneumatic 
controllers or natural gas-driven pumps, are not fugitive emissions 
components, insofar as the natural gas discharged from the device's 
vent is not considered a fugitive emission. Emissions originating from 
other than the device's vent, such as the thief hatch on a controlled 
storage vessel, would be considered fugitive emissions.
* * * * *

0
32. Add subpart OOOOb, to part 60 to read as follows:

Subpart OOOOb--Standards of Performance for Crude Oil and Natural 
Gas Facilities for Which Construction, Modification or 
Reconstruction Commenced After December 6, 2022

60.5360b What is the purpose of this subpart?
60.5365b Am I subject to this subpart?
60.5370b When must I comply with this subpart?
60.5371b What GHG and VOC standards apply to super-emitter events?
60.5375b What GHG and VOC standards apply to well completions at 
well affected facilities?
60.5376b What GHG and VOC standards apply to gas well liquids 
unloading operations at well affected facilities?
60.5377b What GHG and VOC standards apply to associated gas wells at 
well affected facilities?
60.5380b What GHG and VOC standards apply to centrifugal compressor 
affected facilities?
60.5385b What GHG and VOC standards apply to reciprocating 
compressor affected facilities?
60.5386b What test methods and procedures must I use for my 
centrifugal compressor and reciprocating compressor affected 
facilities?
60.5390b What GHG and VOC standards apply to process controller 
affected facilities?
60.5393b What GHG and VOC standards apply to pump affected 
facilities?
60.5395b What GHG and VOC standards apply to storage vessel affected 
facilities?
60.5397b What GHG and VOC standards apply to fugitive emissions 
components affected facilities?
60.5398b What alternative GHG and VOC standards apply to fugitive 
emissions components affected facilities and what inspection and 
monitoring requirements apply to covers and closed vent systems when 
using an alternative technology?
60.5399b What are the alternative means of emission limitations for 
GHG and VOC from well completions, liquids unloading operations, 
centrifugal compressors, reciprocating compressors, fugitive 
emissions components, and process unit equipment affected 
facilities; and what are the alternative fugitive emissions 
standards based on State, local, and Tribal programs?
60.5400b What GHG and VOC standards apply to process unit equipment 
affected facilities?
60.5401b What are the alternative GHG and VOC standards for process 
unit equipment affected facilities?
60.5402b What are the exceptions to the GHG and VOC standards for 
process unit equipment affected facilities?
60.5403b What test methods and procedures must I use for my process 
unit equipment affected facilities?
60.5405b What standards apply to sweetening unit affected 
facilities?
60.5406b What test methods and procedures must I use for my 
sweetening unit affected facilities?
60.5407b What are the requirements for monitoring of emissions and 
operations from my sweetening unit affected facilities?
60.5408b What is an optional procedure for measuring hydrogen 
sulfide in acid gas--Tutwiler Procedure?
60.5410b How do I demonstrate initial compliance with the standards 
for each of my affected facilities?
60.5411b What additional requirements must I meet to determine 
initial compliance for my covers and closed vent systems?
60.5412b What additional requirements must I meet for determining 
initial compliance of my control devices?

[[Page 17044]]

60.5413b What are the performance testing procedures for control 
devices?
60.5415b How do I demonstrate continuous compliance with the 
standards for each of my affected facilities?
60.5416b What are the initial and continuous cover and closed vent 
system inspection and monitoring requirements?
60.5417b What are the continuous monitoring requirements for my 
control devices?
60.5420b What are my notification, reporting, and recordkeeping 
requirements?
60.5421b What are my additional recordkeeping requirements for 
process unit equipment affected facilities?
60.5422b What are my additional reporting requirements for process 
unit equipment affected facilities?
60.5423b What are my additional recordkeeping and reporting 
requirements for sweetening unit affected facilities?
60.5424b What are my additional recordkeeping and reporting 
requirements if I comply with the alternative GHG and VOC standards 
for fugitive emissions components affected facilities and covers and 
closed vent systems?
60.5425b What parts of the General Provisions apply to me?
60.5430b What definitions apply to this subpart?
60.5432b How do I determine whether a well is a low pressure well 
using the low pressure well equation?
60.5433b-60.5439b [Reserved]
Table 1 to Subpart OOOOb of Part 60--Alternative Technology Periodic 
Screening Frequency at Well Sites, Centralized Production, and 
Compressor Stations Facilities Subject to AVO Inspections with 
Quarterly OGI or EPA Method 21 Monitoring
Table 2 to Subpart OOOOb of Part 60--Alternative Technology Periodic 
Screening Frequency at Well Sites and Centralized Production 
Facilities Subject to AVO Inspections and/or Semiannual OGI or EPA 
Method 21 Monitoring
Table 3 to Subpart OOOOb of Part 60--Required Minimum Initial SO2 
Emission Reduction Efficiency (Zi)
Table 4 to Subpart OOOOb of Part 60--Required Minimum SO2 Emission 
Reduction Efficiency (Zc)
Table 5 to Subpart OOOOb of Part 60--Applicability of General 
Provisions to Subpart OOOOb


Sec.  60.5360b  What is the purpose of this subpart?

    (a) Scope. This subpart establishes emission standards and 
compliance schedules for the control of the pollutant greenhouse gases 
(GHG). The greenhouse gas standard in this subpart is in the form of a 
limitation on emissions of methane from affected facilities in the 
crude oil and natural gas source category that commence construction, 
modification, or reconstruction after December 6, 2022. This subpart 
also establishes emission standards and compliance schedules for the 
control of volatile organic compounds (VOC) and sulfur dioxide 
(SO<INF>2</INF>) emissions from affected facilities in the crude oil 
and natural gas source category that commence construction, 
modification, or reconstruction after December 6, 2022.
    (b) Prevention of Significant Deterioration (PSD) and title V 
thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR 
51.166(b)(49)(ii), with respect to GHG emissions from affected 
facilities, the ``pollutant that is subject to the standard promulgated 
under section 111 of the Act'' shall be considered the pollutant that 
otherwise is subject to regulation under the Act as defined in 40 CFR 
51.166(b)(48) and in any State Implementation Plan (SIP) approved by 
the EPA that is interpreted to incorporate, or specifically 
incorporates, 40 CFR 51.166(b)(48).
    (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to 
GHG emissions from affected facilities, the ``pollutant that is subject 
to the standard promulgated under section 111 of the Act'' shall be 
considered the pollutant that otherwise is subject to regulation under 
the Clean Air Act as defined in 40 CFR 52.21(b)(49).
    (3) For the purposes of 40 CFR 70.2, with respect to GHG emissions 
from affected facilities, the ``pollutant that is subject to any 
standard promulgated under section 111 of the Act'' shall be considered 
the pollutant that otherwise is ``subject to regulation'' as defined in 
40 CFR 70.2.
    (4) For the purposes of 40 CFR 71.2, with respect to GHG emissions 
from affected facilities, the ``pollutant that is subject to any 
standard promulgated under section 111 of the Act'' shall be considered 
the pollutant that otherwise is ``subject to regulation'' as defined in 
40 CFR 71.2.
    (c) Exemption. You are exempt from the obligation to obtain a 
permit under 40 CFR part 70 or 40 CFR part 71, provided you are not 
otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 
CFR 71.3(a). Notwithstanding the previous sentence, you must continue 
to comply with the provisions of this subpart.


Sec.  60.5365b  Am I subject to this subpart?

    You are subject to the applicable provisions of this subpart if you 
are the owner or operator of one or more of the onshore affected 
facilities listed in paragraphs (a) through (i) of this section, that 
is located within the Crude Oil and Natural Gas source category, as 
defined in Sec.  60.5430b, for which you commence construction, 
modification, or reconstruction after December 6, 2022. Facilities 
located inside and including the Local Distribution Company (LDC) 
custody transfer station are not subject to this subpart.
    (a) Each well affected facility, which is a single well drilled for 
the purpose of producing oil or natural gas.
    (1) In addition to Sec.  60.14, a ``modification'' of an existing 
well occurs when:
    (i) An existing well is hydraulically fractured, or
    (ii) An existing well is hydraulically refractured.
    (2) For the purposes of a well affected facility, a liquids 
unloading event is not considered to be a modification.
    (3) Except as provided in Sec.  60.5365b(e)(3)(ii)(C) and 
(i)(3)(ii), any action described by paragraphs (a)(1)(i) and (ii) of 
this section, by itself, does not affect the modification status of 
process unit equipment, centrifugal or reciprocating compressors, 
pumps, or process controllers.
    (b) Each centrifugal compressor affected facility, which is a 
single centrifugal compressor. A centrifugal compressor located at a 
well site is not an affected facility under this subpart. A centrifugal 
compressor located at a centralized production facility is an affected 
facility under this subpart.
    (c) Each reciprocating compressor affected facility, which is a 
single reciprocating compressor. A reciprocating compressor located at 
a well site is not an affected facility under this subpart. A 
reciprocating compressor located at a centralized production facility 
is an affected facility under this subpart.
    (d) Each process controller affected facility, which is the 
collection of natural gas-driven process controllers at a well site, 
centralized production facility, onshore natural gas processing plant, 
or a compressor station. Natural gas-driven process controllers that 
function as emergency shutdown devices and process controllers that are 
not driven by natural gas are not included in the affected facility.
    (1) For the purposes of Sec.  60.5390b, in addition to the 
definition in Sec.  60.14, a modification occurs when the number of 
natural gas-driven process controllers in the affected facility is 
increased by one or more.
    (2) For the purposes of Sec.  60.5390b, owners and operators may 
choose to apply reconstruction as defined in Sec.  60.15(b) based on 
the fixed capital cost of the new process controllers in accordance 
with paragraph (d)(2)(i) of this section, or the definition of 
reconstruction based on the number of natural gas-driven process 
controllers in

[[Page 17045]]

the affected facility in accordance with paragraph (d)(2)(ii) of this 
section. Owners and operators may choose which definition of 
reconstruction to apply and whether to comply with paragraph (d)(2)(i) 
or (ii) of this section; they do not need to apply both. If owners and 
operators choose to comply with paragraph (d)(2)(ii) of this section 
they may demonstrate compliance with Sec.  60.15(b)(1) by showing that 
more than 50 percent of the number of natural gas-driven process 
controllers in the affected facility is replaced. That is, if an owner 
or operator meets the definition of reconstruction through the ``number 
of controllers'' criterion in (d)(2)(ii) of this section, they will 
have shown 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,'' as required in Sec.  
60.15(b)(1). Therefore, an owner or operator may comply with the 
remaining provisions of Sec.  60.15 that reference ``fixed capital 
cost'' through an initial showing that the number of natural gas-driven 
process controllers replaced exceeds 50 percent. For purposes of 
paragraphs (d)(2)(i) and (ii), ``commenced'' means that an owner or 
operator has undertaken a continuous program of natural gas-driven 
process controller replacement or that an owner or operator has entered 
into a contractual obligation to undertake and complete, within a 
reasonable time, a continuous program of natural gas-driven process 
controller replacement.
    (i) If the owner or operator applies the definition of 
reconstruction in Sec.  60.15(b)(1), reconstruction occurs when the 
fixed capital cost of the new process controllers exceeds 50 percent of 
the fixed capital cost that would be required to replace all the 
natural gas-driven process controllers in the affected facility. The 
``fixed capital cost of the new process controllers'' includes the 
fixed capital cost of all natural gas-driven process controllers which 
are or will be replaced pursuant to all continuous programs of 
component replacement which are commenced within any 24-month rolling 
period following December 6, 2022.
    (ii) If the owner or operator applies the definition of 
reconstruction based on the percentage of natural gas-driven process 
controllers replaced, reconstruction occurs when greater than 50 
percent of the natural gas-driven process controllers at a site are 
replaced. The percentage includes all natural gas-driven process 
controllers which are or will be replaced pursuant to all continuous 
programs of natural gas-driven process controller replacement which are 
commenced within any 24-month rolling period following December 6, 
2022. If an owner or operator determines reconstruction based on the 
percentage of natural gas-driven process controllers that are replaced, 
the owner or operator must also comply with Sec.  60.15(a).
    (e) Each storage vessel affected facility, which is a tank battery 
that has the potential for emissions as specified in either paragraph 
(e)(1)(i) or (ii) of this section. A tank battery with the potential 
for emissions below both of the thresholds specified in paragraphs 
(e)(1)(i) and (ii) of this section is not a storage vessel affected 
facility provided the owner/operator keeps records of the potential for 
emissions calculation for the life of the storage vessel or until such 
time the tank battery becomes a storage vessel affected facility 
because the potential for emissions meets or exceeds either threshold 
specified in either paragraph (e)(1)(i) or (ii) of this section.
    (1)(i) Potential for VOC emissions equal to or greater than 6 tons 
per year (tpy) as determined in paragraph (e)(2) of this section.
    (ii) Potential for methane emissions equal to or greater than 20 
tpy as determined in paragraph (e)(2) of this section.
    (2) The potential for VOC and methane emissions must be calculated 
as the cumulative emissions from all storage vessels within the tank 
battery as specified by the applicable requirements in paragraphs 
(e)(2)(i) through (iii) of this section. The determination may take 
into account requirements under a legally and practicably enforceable 
limit in an operating permit or other requirement established under a 
Federal, state, local, or Tribal authority.
    (i) For purposes of determining the applicability of a storage 
vessel tank battery as an affected facility, a legally and practicably 
enforceable limit must include the elements provided in paragraphs 
(e)(2)(i)(A) through (F) of this section.
    (A) A quantitative production limit and quantitative operational 
limit(s) for the equipment, or quantitative operational limits for the 
equipment;
    (B) An averaging time period for the production limit in 
(e)(2)(i)(A) of this section, if a production-based limit is used, that 
is equal to or less than 30 days;
    (C) Established parametric limits for the production and/or 
operational limit(s) in (e)(1)(i)(A) of this section, and where a 
control device is used to achieve an operational limit, an initial 
compliance demonstration (i.e., performance test) for the control 
device that establishes the parametric limits;
    (D) Ongoing monitoring of the parametric limits in (e)(2)(i)(C) of 
this section that demonstrates continuous compliance with the 
production and/or operational limit(s) in (e)(2)(i)(A) of this section;
    (E) Recordkeeping by the owner or operator that demonstrates 
continuous compliance with the limit(s) in (e)(2)(i)(A) through (D) of 
this section; and
    (F) Periodic reporting that demonstrates continuous compliance.
    (ii) For each tank battery located at a well site or centralized 
production facility, you must determine the potential for VOC and 
methane emissions within 30 days after startup of production, or within 
30 days after an action specified in paragraphs (e)(3)(i) and (ii) of 
this section, except as provided in paragraph (e)(5)(iv) of this 
section. The potential for VOC and methane emissions must be calculated 
using a generally accepted model or calculation methodology that 
accounts for flashing, working, and breathing losses, based on the 
maximum average daily throughput to the tank battery determined for a 
30-day period of production.
    (iii) For each tank battery not located at a well site or 
centralized production facility, including each tank battery located at 
a compressor station or onshore natural gas processing plant, you must 
determine the potential for VOC and methane emissions prior to startup 
of the compressor station, onshore natural gas processing plant, or 
other facility within 30 days after an action specified in paragraphs 
(e)(3)(i) and (ii) of this section, using either method described in 
paragraph (e)(2)(iii)(A) or (B) of this section.
    (A) Determine the potential for VOC and methane emissions using a 
generally accepted model or calculation methodology that accounts for 
flashing, working and breathing losses and based on the throughput to 
the tank battery established in a legally and practicably enforceable 
limit in an operating permit or other requirement established under a 
Federal, state, local, or Tribal authority; or
    (B) Determine the potential for VOC and methane emissions using a 
generally accepted model or calculation methodology that accounts for 
flashing, working and breathing losses and based on projected maximum 
average daily throughput. Maximum average daily throughput is 
determined using a generally accepted engineering model (e.g., 
volumetric condensate rates from the tank battery based on the maximum

[[Page 17046]]

gas throughput capacity of each producing facility) to project the 
maximum average daily throughput for the tank battery.
    (3) For the purposes of Sec.  60.5395b, the following definitions 
of ``reconstruction'' and ``modification'' apply for determining when 
an existing tank battery becomes a storage vessel affected facility 
under this subpart.
    (i) ``Reconstruction'' of a tank battery occurs when the potential 
for VOC or methane emissions to meet or exceed either of the thresholds 
specified in paragraphs (e)(1)(i) or (ii) of this section and
    (A) at least half of the storage vessels are replaced in the 
existing tank battery that consists of more than one storage vessel; or
    (B) the provisions of Sec.  60.15 are met for the existing tank 
battery.
    (ii) ``Modification'' of a tank battery occurs when any of the 
actions in paragraphs (e)(3)(ii)(A) through (D) of this section occurs 
and the potential for VOC or methane emissions meet or exceed either of 
the thresholds specified in paragraphs (e)(1)(i) or (ii) of this 
section.
    (A) A storage vessel is added to an existing tank battery;
    (B) One or more storage vessels are replaced such that the 
cumulative storage capacity of the existing tank battery increases;
    (C) For tank batteries at well sites or centralized production 
facilities, an existing tank battery receives additional crude oil, 
condensate, intermediate hydrocarbons, or produced water throughput 
from actions, including but not limited to, the addition of operations 
or a production well, or changes to operations or a production well 
(including hydraulic fracturing or refracturing of the well).
    (D) For tank batteries not located at a well site or centralized 
production facility, including each tank battery at compressor stations 
or onshore natural gas processing plants, an existing tank battery 
receives additional fluids which cumulatively exceed the throughput 
used in the most recent (i.e., prior to an action in paragraphs 
(e)(3)(ii)(A), (B) or (D) of this section) determination of the 
potential for VOC or methane emissions.
    (4) A storage vessel affected facility that subsequently has its 
potential for VOC emissions decrease to less than 6 tpy shall remain an 
affected facility under this subpart.
    (5) For storage vessels not subject to a legally and practicably 
enforceable limit in an operating permit or other requirement 
established under Federal, state, local, or Tribal authority, any vapor 
from the storage vessel that is recovered and routed to a process 
through a vapor recovery unit designed and operated as specified in 
this section is not required to be included in the determination of 
potential for VOC or methane emissions for purposes of determining 
affected facility status, provided you comply with the requirements of 
paragraphs (e)(5)(i) through (iv) of this section.
    (i) You meet the cover requirements specified in Sec.  60.5411b(b).
    (ii) You meet the closed vent system requirements specified in 
Sec.  60.5411b(a)(2) through (4) and (c).
    (iii) You must maintain records that document compliance with 
paragraphs (e)(5)(i) and (ii) of this section.
    (iv) In the event of removal of apparatus that recovers and routes 
vapor to a process, or operation that is inconsistent with the 
conditions specified in paragraphs (e)(5)(i) and (ii) of this section, 
you must determine the storage vessel's potential for VOC emissions 
according to this section within 30 days of such removal or operation.
    (6) The requirements of this paragraph (e)(6) apply to each storage 
vessel affected facility immediately upon startup, startup of 
production, or return to service. A storage vessel affected facility or 
portion of a storage vessel affected facility that is reconnected to 
the original source of liquids remains a storage vessel affected 
facility subject to the same requirements that applied before being 
removed from service. Any storage vessel that 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 
assumes the affected facility status of the storage vessel affected 
facility being replaced or expanded.
    (7) A storage vessel with a capacity greater than 100,000 gallons 
used to recycle water that has been passed through two stage separation 
is not a storage vessel affected facility.
    (f) Each process unit equipment affected facility, which is the 
group of all equipment within a process unit at an onshore natural gas 
processing plant is an affected facility.
    (1) Addition or replacement of equipment for the purpose of process 
improvement that is accomplished without a capital expenditure shall 
not by itself be considered a modification under this subpart.
    (2) Equipment associated with a compressor station, dehydration 
unit, sweetening unit, underground storage vessel, field gas gathering 
system, or liquefied natural gas unit is covered by Sec. Sec.  
60.5400b, 60.5401b, 60.5402b, 60.5421b, and 60.5422b if it is located 
at an onshore natural gas processing plant. Equipment not located at 
the onshore natural gas processing plant site is exempt from the 
provisions of Sec. Sec.  60.5400b, 60.5401b, 60.5402b, 60.5421b, and 
60.5422b.
    (g) Each sweetening unit affected facility as defined by paragraphs 
(g)(1) and (2) of this section.
    (1) Each sweetening unit that processes natural gas produced from 
either onshore or offshore wells is an affected facility; and
    (2) Each sweetening unit that processes natural gas followed by a 
sulfur recovery unit is an affected facility.
    (3) Facilities that have a design capacity less than 2 long tons 
per day (LT/D) of hydrogen sulfide (H<INF>2</INF>S) in the acid gas 
(expressed as sulfur) are required to comply with recordkeeping and 
reporting requirements specified in Sec.  60.5423b(c) but are not 
required to comply with Sec. Sec.  60.5405b through 60.5407b and 
Sec. Sec.  60.5410b(i) and 60.5415b(i).
    (4) Sweetening facilities producing acid gas that is completely re-
injected into oil-or-gas-bearing geologic strata or that is otherwise 
not released to the atmosphere are not subject to Sec. Sec.  60.5405b 
through 60.5407b, 60.5410b(i), 60.5415b(i), and 60.5423b.
    (h) Each pump affected facility, which is the collection of natural 
gas-driven pumps at a well site, centralized production facility, 
onshore natural gas processing plant, or a compressor station. Pumps 
that are not driven by natural gas are not included in the pump 
affected facility.
    (1) For the purposes of Sec.  60.5393b, in addition to the 
definition in Sec.  60.14, a modification occurs when the number of 
natural gas-driven pumps in the affected facility is increased by one 
or more.
    (2) For the purposes of Sec.  60.5390b, owners and operators may 
choose to apply reconstruction as defined in Sec.  60.15(b) based on 
the fixed capital cost of the new pumps in accordance with paragraph 
(h)(2)(i) of this section, or the definition of reconstruction based on 
the number of natural gas-driven pumps in the affected facility in 
accordance with paragraph (h)(2)(ii) of this section. Owners and 
operators may choose which definition of reconstruction to apply and 
whether to comply with paragraph (h)(2)(i) or (ii) of this section; 
they do not need to apply both. If owners and operators choose to 
comply with paragraph (h)(2)(ii) of this section they may demonstrate 
compliance with Sec.  60.15(b)(1) by showing that more than 50 percent 
of the number of natural gas-

[[Page 17047]]

driven pumps is replaced. That is, if an owner or operator meets the 
definition of reconstruction through the ``number of pumps'' criterion 
in (h)(2)(ii) of this section, they will have shown 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,'' as required in Sec.  60.15(b)(1). Therefore, an owner 
or operator may comply with the remaining provisions of Sec.  60.15 
that reference ``fixed capital cost'' through an initial showing that 
the number of natural gas-driven pumps replaced exceeds 50 percent. For 
purposes of paragraphs (h)(2)(i) and (ii) of this section, 
``commenced'' means that an owner or operator has undertaken a 
continuous program of component replacement or that an owner or 
operator has entered into a contractual obligation to undertake and 
complete, within a reasonable time, a continuous program of natural 
gas-driven pump replacement.
    (i) If the owner or operator applies the definition of 
reconstruction in Sec.  60.15, reconstruction occurs when the fixed 
capital cost of the new pumps exceeds 50 percent of the fixed capital 
cost that would be required to replace all the natural gas-driven pumps 
in the affected facility. The ``fixed capital cost of the new pumps'' 
includes the fixed capital cost of all natural gas-driven pumps which 
are or will be replaced pursuant to all continuous programs of 
component replacement which are commenced within any 24-month rolling 
period following December 6, 2022.
    (ii) If the owner or operator applies the definition of 
reconstruction based on the percentage of natural gas-driven pumps 
replaced, reconstruction occurs when greater than 50 percent of the 
natural gas-driven pumps in the affected facility are replaced. The 
percentage includes all natural gas-driven pumps which are or will be 
replaced pursuant to all continuous programs of component replacement 
which are commenced within any 24-month rolling period following 
December 6, 2022. If an owner or operator determines reconstruction 
based on the percentage of natural gas-driven pumps that are replaced, 
the owner or operator must comply with Sec.  60.15(a).
    (3) A natural gas-driven pump that is in operation less than 90 
days per calendar year is not part of an affected facility under this 
subpart. For the purposes of this section, any period of operation 
during a calendar day counts toward the 90-calendar day threshold.
    (i) Each fugitive emissions components affected facility, which is 
the collection of fugitive emissions components at a well site, 
centralized production facility, or a compressor station.
    (1) For purposes of Sec.  60.5397b and Sec.  60.5398b, a 
``modification'' to a well site occurs when:
    (i) A new well is drilled at an existing well site;
    (ii) A well at an existing well site is hydraulically fractured; or
    (iii) A well at an existing well site is hydraulically refractured.
    (2) For purposes of Sec.  60.5397b and Sec.  60.5398b, a 
``modification'' to centralized production facility occurs when:
    (i) Any of the actions in paragraphs (i)(1)(i) through (iii) of 
this section occurs at an existing centralized production facility;
    (ii) A well sending production to an existing centralized 
production facility is modified, as defined in paragraphs (i)(1)(i) 
through (iii) of this section; or
    (iii) A well site subject to the requirements of Sec.  60.5397b or 
Sec.  60.5398b removes all major production and processing equipment, 
such that it becomes a wellhead only well site and sends production to 
an existing centralized production facility.
    (3) For purposes of Sec.  60.5397b, a ``modification'' to a 
compressor station occurs when:
    (i) An additional compressor is installed at a compressor station; 
or
    (ii) One or more compressors at a compressor station is replaced by 
one or more compressors of greater total horsepower than the 
compressor(s) being replaced. When one or more compressors is replaced 
by one or more compressors of an equal or smaller total horsepower than 
the compressor(s) being replaced, installation of the replacement 
compressor(s) does not trigger a modification of the compressor station 
for purposes of Sec.  60.5397b.


Sec.  60.5370b  When must I comply with this subpart?

    (a) You must be in compliance with the standards of this subpart no 
later than May 7, 2024 or upon initial startup, whichever date is 
later, except as specified in paragraph (a)(1) of this section for 
reciprocating compressor affected facilities, paragraphs (a)(2) and (3) 
of this section for storage vessel affected facilities, paragraph 
(a)(4) of this section for process unit equipment affected facilities 
at onshore natural gas processing plants, paragraph (a)(5) of this 
section for process controllers, paragraph (a)(6) of this section for 
pumps, paragraph (a)(7) of this section for centrifugal compressor 
affected facilities, and paragraphs Sec.  60.5377b(b) or (c) for 
associated gas wells.
    (1) You must comply with the requirements of Sec.  60.5385b(a) for 
your reciprocating compressor affected facility as specified in 
paragraph (a)(1)(i), (ii), or (iii) of this section, as applicable.
    (i) You must comply with the requirements of Sec.  60.5385b(a)(1) 
and (d)(3) on or before 8,760 hours of operation after May 7, 2024, on 
or before 8,760 hours of operation after last rod packing replacement, 
or on or before 8,760 hours of operation after startup, whichever date 
is later; and
    (ii) You must comply with the requirements of Sec.  60.5385b(a)(2) 
within 8,760 hours after compliance with Sec.  60.5385b(a)(1) and 
(d)(3).
    (iii) You must comply with the requirements of Sec.  60.5385b(d)(1) 
and (2) for your reciprocating compressor upon initial startup.
    (2) You must comply with the requirements of paragraphs Sec.  
60.5395b(a)(1) for your storage vessel affected facility as specified 
in paragraphs (a)(2)(i) or (ii) of this section, as applicable.
    (i) Within 30 days after startup of production, or within 30 days 
after reconstruction or modification of the storage vessel affected 
facility, for each storage vessel affected facility located at a well 
site or centralized production facility.
    (ii) Prior to startup of the compressor station or onshore natural 
gas processing plant, or within 30 days after reconstruction or 
modification of the storage vessel affected facility, for each storage 
vessel affected facility located at a compressor station or onshore 
natural gas processing plant.
    (3) You must comply with the requirements of paragraph Sec.  
60.5395b(a)(2) as specified in paragraph (a)(3)(i) or (ii) of this 
section, as applicable:
    (i) For each storage vessel affected facility located at a well 
site or centralized production facility, you must achieve the required 
emissions reductions within 30 days after the determination in 
paragraph (a)(2)(i) of this section.
    (ii) For storage vessel affected facilities located at a compressor 
station or onshore natural gas processing plant, you must achieve the 
required emissions reductions within 30 days after the determination in 
paragraph (a)(2)(ii) of this section.
    (4) You must comply with the requirements of Sec.  60.5400b for all 
process unit equipment affected facilities at a natural gas processing 
plant, as soon as practicable but no later than 180 days after the 
initial startup of the process unit.

[[Page 17048]]

    (5) For process controller affected facilities, you must comply 
with the requirements of paragraph (a)(5)(i) or (ii) of this section, 
as applicable.
    (i) Any process controller affected facilities may comply with 
Sec.  60.5390b(b)(1) and (2) or (3) as an alternative to compliance 
with Sec.  60.5390b(a) until [May 7, 2025.
    (ii) On or after May 7, 2025, process controller affected 
facilities must comply with Sec.  60.5390b(a) or (b), as specified in 
those paragraphs.
    (6) For pump affected facilities, you must comply with the 
requirements of paragraph (a)(6)(i) or (ii) of this section, as 
applicable.
    (i) Any pump affected facility may comply with Sec.  60.5393b(b)(2) 
through (8), as applicable, as an alternative to compliance with Sec.  
60.5393b(a) until May 7, 2025.
    (ii) On or after May 7, 2025, pump affected facilities must comply 
with Sec.  60.5393b(a) or (b), as specified in those paragraphs.
    (7) For centrifugal compressor affected facilities, you must comply 
with the requirements of paragraph (a)(7)(i) or (ii) of this section, 
as applicable.
    (i) You must comply with the requirements of Sec.  60.5380b(a)(1) 
and (2), or (a)(3) for your reciprocating compressor upon initial 
startup.
    (ii) Each centrifugal compressor affected facility that uses dry 
seals, each self-contained wet seal compressor, and each centrifugal 
compressor on the Alaska North Slope equipped with sour seal oil 
separator and capture system, complying with one of the alternatives in 
Sec.  60.5380b(a)(4), (5), or (6), must comply with the specified 
performance-based volumetric flow rate work practice standards on or 
before 8,760 hours of operation after May 7, 2024, on or before 8,760 
hours of operation after last seal replacement, or on or before 8,760 
hours of operation after startup, whichever date is later.
    (b) At all times, including periods of startup, shutdown, and 
malfunction, owners and operators shall maintain and operate any 
affected facility including associated air pollution control equipment 
in a manner consistent with good air pollution control practice for 
minimizing emissions. Determination of whether acceptable operating and 
maintenance procedures are being used will be based on information 
available to the Administrator which may include, but is not limited 
to, monitoring results, opacity observations, review of operating and 
maintenance procedures, and inspection of the source. The provisions 
for exemption from compliance during periods of startup, shutdown and 
malfunctions provided for in 40 CFR 60.8(c) do not apply to this 
subpart.
    (c) You are exempt from the obligation to obtain a permit under 40 
CFR part 70 or 40 CFR part 71, provided you are not otherwise required 
by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). 
Notwithstanding the previous sentence, you must continue to comply with 
the provisions of this subpart.


Sec.  60.5371b  What GHG and VOC standards apply to super-emitter 
events?

    This section applies to super-emitter events. For purposes of this 
section, a super-emitter event is defined as any emissions event that 
is located at or near an oil and natural gas facility (e.g., individual 
well site, centralized production facility, natural gas processing 
plant, or compressor station) and that is detected using remote 
detection methods and has quantified emission rate of 100 kg/hr of 
methane or greater. Paragraph (a) of this section describes the 
qualifications one must meet to apply to be a third-party notifier of 
super-emitter events. Paragraph (b) of this section describes the 
procedures for certifying third-party notifiers, as well as the 
procedures for petitioning the Agency for removal of a third-party 
notifier from the list of certified notifiers. Paragraph (c) of this 
section contains the required information that must be included in any 
notification submitted to the EPA from a certified third-party notifier 
and a timetable for notifications. The EPA shall review these 
notifications and if the EPA determines the notification is complete 
and does not contain information that the EPA finds to be erroneous or 
inaccurate to a reasonable degree of certainty, the EPA shall assign 
the notification a unique notification identification number, provide 
the notification to the owner or operator of the oil and natural gas 
facility identified in the notification, and post the notification, 
except for the owner/operator attribution, at www.epa.gov/super-emitter. Upon receiving such notification, owners or operators must 
take the actions listed in paragraphs (d) and (e) of this section. The 
EPA shall post the reports submitted under paragraph (e) of this 
section, Sec.  60.5371(b) and Sec.  60.5371a(b) of subparts OOOO and 
OOOOa of this part, and applicable State or Federal plan implementing 
Sec.  60.5388c(b) of subpart OOOOc of this part, including owner/
operator attributions that have been confirmed by the reports; where 
the reporting deadlines have passed but no reports have been received, 
the EPA intends to post owner/operator attributions that the EPA 
reasonably believes to be accurate. The reports will be publicly 
available at www.epa.gov/super-emitter.
    (a) Qualifications for third-party notifiers. An entity may apply 
to the Administrator under paragraph (b) of this section for approval 
as a third-party notifier if it meets the qualifications in this 
paragraph (a). The entity must be a person, as defined in 42 U.S.C. 
7602(e), excluding the owner or operator of the site where the super-
emitter event is detected, the Administrator, or the delegated 
authority. The entity must use a method that has been approved under 
Sec.  60.5398b(d) for one of the technologies specified in paragraphs 
(a)(1) through (3) of this section.
    (1) Satellite detection of methane emissions.
    (2) Remote-sensing equipment on aircraft.
    (3) Mobile monitoring platforms.
    (b) Third-party notifier certification. An entity meeting the 
qualifications in paragraph (a) of this section may apply to be 
certified as a third-party notifier. Only entities certified as third-
party notifiers may submit information on super-emitter events to the 
EPA under paragraph (c) of this section. An entity seeking 
certification as a third-party notifier must submit a request to the 
Administrator as described in paragraph (b)(1) of this section. 
Certified third-party notifiers must follow the recordkeeping 
requirements in paragraph (b)(2) of this section; failure to maintain 
the required records may result in loss of certification status. The 
Administrator will determine whether the request for certification is 
adequate and issue an approval or disapproval of the request as 
described in paragraph (b)(3) of this section. A certified third-party 
notifier must re-apply when material changes are made, as described in 
paragraph (b)(4) of this section. A third-party notifier may be removed 
from the list of certified notifiers as detailed in paragraph (b)(5) of 
this section.
    (1) A request to be certified as a third-party notifier must be 
submitted to: U.S. EPA, Attn: Leader, Measurement Technology Group, 
Mail Drop: E143-02, 109 T.W. Alexander Drive, P.O. Box 12055, RTP, NC 
27711. The request must include the supporting information in 
paragraphs (b)(1)(i) through (vi) of this section. If your submittal 
includes information claimed to be CBI, submit the portion of the 
information claimed as CBI to the OAQPS CBI office. The preferred 
method to receive CBI is for it to be

[[Page 17049]]

transmitted electronically using email attachments, File Transfer 
Protocol, or other online file sharing services. Electronic submissions 
must be transmitted directly to the OAQPS CBI Office at the email 
address <a href="/cdn-cgi/l/email-protection#6f000e1e1f1c0c0d062f0a1f0e41080019"><span class="__cf_email__" data-cfemail="3d525c4c4d4e5e5f547d584d5c135a524b">[email protected]</span></a> and should include clear CBI markings and be 
flagged to the attention of the Leader, Measurement Technology Group. 
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 <a href="/cdn-cgi/l/email-protection#0e616f7f7e7d6d6c674e6b7e6f20696178"><span class="__cf_email__" data-cfemail="89e6e8f8f9faeaebe0c9ecf9e8a7eee6ff">[email protected]</span></a> to 
request a file transfer link. If you cannot transmit the file 
electronically, you may send CBI information through the postal service 
to the following address: U.S. EPA, Attn: OAQPS Document Control 
Officer and Measurement Technology Group Leader, Mail Drop: C404-02, 
109 T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. The mailed CBI 
material should be double wrapped and clearly marked. Any CBI markings 
should not show through the outer envelope.
    (i) General identification information for the candidate third-
party notifier requesting certification as a third-party notifier 
including the mailing address, the physical address, the name of a 
principal officer and an email address for the principal officer, and 
name of the certifying official(s) and the certifying official(s)'s 
email address.
    (ii) Description of the technologies the entity will use to 
identify emissions that are 100 kg/hr of methane or greater. At a 
minimum, the description must include the following:
    (A) Reference to the approval of the method to be used under Sec.  
60.5398b(d).
    (B) Memorandum of Understanding (MOU) or contracting agreements 
with the technology provider(s) that will be used to identify super-
emitter events (if applicable).
    (iii) Curriculum vitae of the certifying official(s) detailing 
their work history, education, skill set, and training for evaluating 
the results of the technologies that will be used to identify super-
emitter events.
    (iv) The candidate third-party notifier's standard operating 
procedure(s) detailing the procedures and processes for data review. At 
a minimum, this must include the following:
    (A) Procedures for evaluating the emission data provided by the 
technology, including the accuracy of the data and whether the data was 
collected in compliance with the method requirements approved under 
Sec.  60.5398b(d).
    (B) Process for verifying the accuracy of the locality of 
emissions.
    (C) Process for identifying and verifying the owner or operator of 
a site where a super-emitter event occurs, including the source of 
information that will be used to make the identification.
    (D) Procedures for handling potentially erroneous data.
    (v) Description of the systems used for maintaining essential 
records identified in paragraph (b)(2) of this section.
    (vi) A Quality Management Plan consistent with EPA's Quality 
Management Plan Standard (Directive No: CIO 2015-S-01.0, January 17, 
2023) for Non-EPA organizations.
    (2) Certified third-party notifiers must maintain the records 
identified in paragraphs (b)(2)(i) through (iii) of this section. Upon 
request, the certified third-party notifier must make these records 
available to the Administrator for review.
    (i) Records for all surveys conducted by or sponsored by the 
certified third-party notifier, including outputs (e.g., emission 
rates, locations) and associated data needed to confirm the accuracy of 
the outputs and the performance of the method used.
    (ii) Records of all notifications of super-emitter events provided 
to the EPA. Retain any information collected that is used to evaluate 
the validity of a super-emitter event but which is not required to be 
submitted as part of the notification.
    (iii) A copy of any records and/or identification of any databases 
used in the identification of the potential owner or operator of the 
site where a super-emitter event occurred.
    (3) Based upon the Administrator's judgment of the completeness, 
reasonableness, and accuracy of the entity's request, the Administrator 
will approve or disapprove the entity for certification as a third-
party notifier. For those third parties that receive approval, the 
Administrator will provide you a unique notifier ID. Starting 15 
calendar days after being approved as a certified third-party notifier, 
the notifier may submit notifications of super-emitter events to the 
EPA as outlined in paragraph (c) of this section. All approved third-
party notifiers shall be posted on the EPA website at www.epa.gov/emc-third-party-certifications.
    (4) If a third-party notifier intends to make any significant 
changes to their procedures for identifying super-emitter events, 
meaning a change to the technology used to identify super-emitter 
events or a change to the certifying official(s), you must request an 
amendment to your certification and be recertified under paragraph 
(b)(1) of this section.
    (5) A certified third-party notifier may be removed from the list 
of approved third-party notifiers in any of the circumstances listed in 
paragraphs (b)(5)(i) through (iii) of this section. Entities removed 
from the list of approved third-party notifiers cannot submit 
notifications to the EPA under paragraph (c) of this section. Entities 
may be added back to the list of approved third-party notifiers by 
receiving approval of a new certification request submitted under 
paragraph (b)(1) of this section.
    (i) If a certified third-party notifier has made material changes 
to their procedures for identifying super-emitter events, meaning a 
change to the technology used to identify super-emitter events or a 
change to the certifying official, without seeking recertification.
    (ii) If the Administrator finds that the certified third-party 
notifier has persistently submitted data with significant errors (e.g., 
misidentification of the owner or operator) or if the third-party 
notifier has engaged in illegal activity during the during the 
assessment of a super-emitter event (e.g., trespassing).
    (iii) If the Administrator receives a petition from an owner or 
operator to remove a certified third-party notifier from the list of 
approved notifiers, as set forth below, and the Administrator makes the 
finding noted below. Any owner or operator that has received more than 
three notices with meaningful and/or demonstrable errors of a super-
emitter event at the same oil and natural gas facility (e.g., a well 
site, centralized production facility, natural gas processing plant, or 
compressor station) from the EPA that were submitted to the EPA by the 
same third party may petition the Administrator to remove that third 
party from the list of approved notifiers, by providing evidence that 
the claimed super-emitter events did not occur. Such petitions may not 
be used to dispute the methodology that were approved through the 
process described in Sec.  60.5398b(d). The third party will be given 
the opportunity to respond to the petition. If, in the Administrator's 
discretion, the Administrator determines that the three notifications 
contain meaningful and/or demonstrable errors, including that the third 
party did not use the methane detection technology identified in their 
submittal, the emissions event did not exceed the threshold of 100 kg/
hr of methane, the third-party knowingly misidentified the date of a 
super-emitter event, the third party may be removed by the 
Administrator from the list of

[[Page 17050]]

approved notifiers. The failure of the owner or operator to find the 
source of the super-emitter event upon subsequent inspection shall not 
be proof, by itself, of demonstrable error.
    (c) Notification of super-emitter events. Notifications must be 
submitted to the EPA using the Super-Emitter Program Portal (available 
at http://www.epa.gov/super-emitter). Notifications must contain the 
information specified in paragraphs (c)(1) through (8) of this section. 
The EPA will review the submitted notifications of super-emitter events 
for completeness and accuracy. If the EPA determines that the 
notification is complete and does not contain information that the EPA 
finds to be inaccurate to a reasonable degree of certainty, the EPA 
will assign the notification a unique notification report 
identification number, make the notification publicly available at 
www.epa.gov/super-emitter, and provide the super-emitter event 
notification to the owner or operator identified in the notification. 
The EPA will not review and provide the notification to an owner or 
operator if the notification is submitted after the date specified in 
paragraph (c)(9) of this section.
    (1) Unique Third-Party Notifier ID.
    (2) Date of detection of the super-emitter event. If multiple 
surveys were required to detect and quantify the super-emitter event, 
the date of detection is the date of the final survey.
    (3) Location of super-emitter event in latitude and longitude 
coordinates in decimal degrees to an accuracy and precision of four (4) 
decimals of a degree using the North American Datum of 1983.
    (4) Owner(s) or operator(s) of any oil and natural gas facility 
(e.g., individual well site, centralized production facility, natural 
gas processing plant, or compressor station) within 50 meters of the 
latitude and longitude coordinates of the super-emitter event.
    (5) Identification of the detection technology and reference to the 
approval of the technology used under Sec.  60.5398b(d).
    (6) Documentation (e.g., imagery) depicting the detected super-
emitter event and the site from which the super-emitter event was 
detected.
    (7) Quantified emission rate of the super-emitter event in kg/hr 
and associated uncertainty bounds (e.g., 1-[sigma]) of the measurement.
    (8) Attestation statement, signed and dated by the third-party 
notifier certifying official submitting the data collected. The 
attestation must state: ``I certify that I have been approved to be a 
notifier under 40 CFR 60.5371b(b) and that the emission detection 
information included in this notification was collected and interpreted 
as described in this notification. Based on my professional knowledge 
and experience, and inquiry of personnel involved in the collection and 
analysis of the data, the certification submitted herein is true, 
accurate, and complete.''
    (9) The third-party notifier must submit the notification within 15 
calendar days of the date of detection of the super-emitter event.
    (d) Identification of super-emitter events. Within 5 calendar days 
of receiving a notification from the EPA of a super-emitter event, the 
owner or operator of an oil and natural gas facility (e.g., a well 
site, centralized production facility, natural gas processing plant, or 
compressor station) must initiate a super-emitter event investigation. 
The investigation must be conducted in accordance with this paragraph 
(d) and completed within 15 days of receiving the notification from the 
EPA. The owner or operator must maintain records of its super-emitter 
event investigations and report the findings from the investigation 
according to the requirements in paragraph (e) of this section.
    (1) If you do not own or operate an oil and natural gas facility 
within 50 meters from the latitude and longitude provided in the 
notification, report this result to the EPA under paragraph (e) of this 
section. Your super-emitter event investigation is deemed complete.
    (2) If you own or operate an oil and natural gas facility within 50 
meters from the latitude and longitude provided in the notification, 
you must investigate to determine the source of super-emitter event. 
The investigation may include but is not limited to the actions 
specified below in paragraphs (d)(6)(i) through (v) of this section.
    (i) Review any maintenance activities (e.g., liquids unloading) or 
process activities from the affected facilities subject to regulation 
under this subpart, starting from the date of detection of the super-
emitter event as identified in the notification, until the date of 
investigation, to determine if the activities indicate any potential 
source(s) of the super-emitter event emissions.
    (ii) Review all monitoring data from control devices (e.g., flares) 
from the affected facilities subject to regulation under this subpart 
from the initial date of detection of the super-emitter event as 
identified in the notification until the date of receiving the 
notification from the EPA. Identify any malfunctions of control devices 
or periods when the control devices were not in compliance with 
applicable requirements and that indicate a potential source of the 
super-emitter event emissions.
    (iii) If you conducted a fugitive emissions survey or periodic 
screening event in accordance with Sec.  60.5397b or Sec.  60.5398b(b) 
between the initial date of detection of the super-emitter event as 
identified in the notification and the date the notification from the 
EPA was received, review the results of the survey to identify any 
potential source(s) of the super-emitter event emissions.
    (iv) If you conduct continuous monitoring with advanced methane 
detection technology in accordance with Sec.  60.5398b(c), review the 
monitoring data collected on or after the initial date of detection of 
the super-emitter event as identified in the notification, until the 
date of receiving the notification from the EPA.
    (v) Screen the entire oil and natural gas facility with OGI, Method 
21 of appendix A-7 to this part, or an alternative test method(s) 
approved per Sec.  60.5398b(d), to determine if a super-emitter event 
is present.
    (3) If the source of the super-emitter event was found to be from 
fugitive emission components at a well site, centralized production 
facility, or compressor station subject to this subpart, you must 
comply with the repair requirements under Sec.  60.5397b and the 
associated recordkeeping and reporting requirements under Sec.  
60.5420b(b)(9) and (c)(14).
    (e) Super-emitter event report. You must submit the results of the 
super-emitter event investigation conducted under paragraph (d) of this 
section to the EPA in accordance with paragraph (e)(1) of this section. 
If the super-emitter event (i.e., emission at 100 kg/hr of methane or 
more) is ongoing at the time of the initial report, submit the 
additional information in accordance with paragraph (e)(2) of this 
section. You must attest to the information included in the report as 
specified in paragraph (e)(3) of this section.
    (1) Within 15 days of receiving a notification from the EPA under 
paragraph (c) of this section, you must submit a report of the super-
emitter event investigation conducted under paragraph (d) of this 
section through the Super-Emitter Program Portal. You must include the 
applicable information in paragraphs (e)(1)(i) through (viii) of this 
section in the report. If you have identified a demonstrable error in 
the notification, the report may include a statement of the 
demonstrable error.
    (i) Notification Report ID of the super-emitter event notification.

[[Page 17051]]

    (ii) Identification of whether you are the owner or operator of an 
oil and natural gas facility within 50 meters from the latitude and 
longitude provided in the EPA notification. If you do not own or 
operate an oil and natural gas facility within 50 meters from the 
latitude and longitude provided in the EPA notification, you are not 
required to report the information in paragraphs (e)(1)(iii) through 
(viii) of this section.
    (iii) General identification information for the facility, 
including, facility name, the physical address, applicable ID Number 
(e.g., EPA ID Number, API Well ID Number), the owner or operator or 
responsible official (where applicable) and their email address.
    (iv) Identification of whether there is an affected facility or 
associated equipment subject to regulation under this subpart at this 
oil and natural gas facility.
    (v) Indication of whether you were able to identify the source of 
the super-emitter event. If you indicate you were unable to identify 
the source of the super-emitter event, you must certify that all 
applicable investigations specified in paragraph (d)(6)(i) through(v) 
of this section have been conducted for all affected facilities and 
associated equipment subject to this subpart that are at this oil and 
natural gas facility, and you have determined that the affected 
facilities and associated equipment are not the source of the super-
emitter event. If you indicate that you were not able to identify the 
source of the super-emitter event, you are not required to report the 
information in paragraphs (e)(1)(vi) through (viii) of this section.
    (vi) The source(s) of the super-emitter event.
    (vii) Identification of whether the source of the super-emitter 
event is equipment subject to regulation under this subpart. If the 
source of the super-emitter event is equipment subject to regulation 
under this subpart, identify the applicable regulation(s) under this 
subpart.
    (viii) Indication of whether the super-emitter event is ongoing at 
the time of the initial report submittal (i.e., emissions at 100 kg/hr 
of methane or more).
    (A) If the super-emitter event is not ongoing at the time of the 
initial report submittal, provide the actual (or if unknown) estimated 
date and time the super-emitter event ended.
    (B) If the super-emitter event is ongoing at the time of the 
initial report submittal, provide a short narrative of your plan to end 
the super-emitter event, including the targeted end date for the 
efforts to be completed and the super-emitter event ended.
    (2) If the super-emitter event is ongoing at the time of the 
initial report submittal, within 5 business days of the date the super-
emitter event ends, you must update your initial report through the 
Super-Emitter Program Portal to provide the end date and time of the 
super-emitter event.
    (3) You must sign the following attestation when submitting data 
into the Super-Emitter Program Portal: ``I certify that the information 
provided in this report regarding the specified super-emitter event was 
prepared under my direction or supervision. I further certify that the 
investigations were conducted, and this report was prepared pursuant to 
the requirements of Sec.  60.5371b(d) and (e). Based on my professional 
knowledge and experience, and inquiry of personnel involved in the 
assessment, the certification submitted herein is true, accurate, and 
complete. I am aware that knowingly false statements may be punishable 
by fine or imprisonment.''


Sec.  60.5375b   What GHG and VOC standards apply to well completions 
at well affected facilities?

    (a) You must comply with the requirements of paragraphs (a)(1) 
through (3) of this section for each well completion operation with 
hydraulic fracturing and refracturing at a well affected facility, 
except as provided in paragraphs (f), (g) and (h) of this section. You 
must maintain a log as specified in paragraph (b) of this section.
    (1) For each stage of the well completion operation, follow the 
requirements specified in paragraphs (a)(1)(i) through (iii) of this 
section.
    (i) During the initial flowback stage, route the flowback into one 
or more well completion vessels or storage vessels and commence 
operation of a separator unless it is technically infeasible for a 
separator to function. The separator may be a production separator, but 
the production separator also must be designed to accommodate flowback. 
Any gas present in the initial flowback stage is not subject to control 
under this section.
    (ii) During the separation flowback stage, route all recovered 
liquids from the separator to one or more well completion vessels or 
storage vessels, re-inject the recovered liquids into the well or 
another well, or route the recovered liquids to a collection system. 
Route the recovered gas from the separator into a gas flow line or 
collection system, re-inject the recovered gas into the well or another 
well, use the recovered gas as an onsite fuel source, or use the 
recovered gas for another useful purpose that a purchased fuel or raw 
material would serve. If it is technically infeasible to route the 
recovered gas as required above, follow the requirements of paragraph 
(a)(2) of this section. If, at any time during the separation flowback 
stage, it is technically infeasible for a separator to function, you 
must comply with paragraph (a)(1)(i) of this section.
    (iii) You must have the separator onsite or otherwise available for 
use at a centralized production facility or well pad that services the 
well completion affected facility during well completions. The 
separator must be available and ready for use to comply with paragraph 
(a)(1)(ii) of this section during the entirety of the flowback period, 
except as provided in paragraphs (a)(1)(iii)(A) through (C) of this 
section.
    (A) A well that is not hydraulically fractured or refractured with 
liquids, or that does not generate condensate, intermediate hydrocarbon 
liquids, or produced water such that there is no liquid collection 
system at the well site is not required to have a separator onsite.
    (B) If conditions allow for liquid collection, then the operator 
must immediately stop the well completion operation, install a 
separator, and restart the well completion operation in accordance with 
paragraph (a)(1) of this section.
    (C) The owner or operator of a well that meets the criteria of 
paragraph (a)(1)(iii)(A) or (B) of this section must submit the report 
in Sec.  60.5420b(b)(2) and maintain the records in Sec.  
60.5420b(c)(1)(iii).
    (2) If it is technically infeasible to route the recovered gas as 
required in Sec.  60.5375b(a)(1)(ii), then you must capture and direct 
recovered gas to a completion combustion device, except 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. Completion combustion devices must be 
equipped with a reliable continuous pilot flame.
    (3) You have a general duty to safely maximize resource recovery 
and minimize releases to the atmosphere during flowback and subsequent 
recovery.
    (b) You must maintain a log for each well completion operation at 
each well affected facility. The log must be completed on a daily basis 
for the duration of the well completion operation and must contain the 
records specified in Sec.  60.5420b(c)(1)(iii).

[[Page 17052]]

    (c) You must demonstrate initial compliance with the well 
completion operation standards that apply to well affected facilities 
as required by Sec.  60.5410b(a).
    (d) You must demonstrate continuous compliance with the well 
completion operation standards that apply to well affected facilities 
as required by Sec.  60.5415b(a).
    (e) You must perform the required notification, reporting and 
recordkeeping as required by Sec.  60.5420b(a)(2), (b)(1) and (2), and 
(c)(1).
    (f) For each well affected facility specified in paragraphs (f)(1) 
and (2) of this section, you must comply with the requirements of 
paragraphs (f)(3) and (4) of this section.
    (1) Each well completion operation with hydraulic fracturing at a 
wildcat or delineation well.
    (2) Each well completion operation with hydraulic fracturing at a 
non-wildcat low pressure well or non-delineation low pressure well.
    (3) You must comply with paragraph (f)(3)(i) of this section. You 
must also comply with paragraph (b) of this section. As an alternative, 
if you are able to operate a separator, you may comply with paragraph 
(b) and (f)(3)(ii) of this section. Compliance with paragraphs 
(f)(3)(i) or (ii) of this section is not required if you meet the 
requirements of paragraph (g) of this section.
    (i) Route all flowback to a completion combustion device, except 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. Completion combustion devices 
must be equipped with a reliable continuous pilot flame.
    (ii) 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. You must have the separator 
onsite or otherwise available for use at the wildcat well, delineation 
well, or low pressure well. The separator must be available and ready 
for use to comply with paragraph (f)(3)(ii) of this section during the 
entirety of the flowback period. 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, except 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. 
Completion combustion devices must be equipped with a reliable 
continuous pilot flame.
    (4) You must submit the notification as specified in Sec.  
60.5420b(a)(2), submit annual reports as specified in Sec.  
60.5420b(b)(1) and (2) and maintain records specified in Sec.  
60.5420b(c)(1)(i) through (iii) and (vii) for each wildcat well, each 
delineation well, and each low pressure well.
    (g) For each well completion affected facility with less than 300 
scf of gas per stock tank barrel of oil produced, you must comply with 
paragraphs (g)(1) and (2) of this section.
    (1) You must maintain records specified in Sec.  
60.5420b(c)(1)(vi).
    (2) You must submit reports specified in Sec.  60.5420b(b)(1) and 
(2).
    (h) A well modified in accordance with Sec.  60.5365b(a)(1)(ii) 
(i.e., an existing well that is hydraulically refractured) is exempt 
from the well completion operation standards in paragraphs (b) through 
(d) of this section, when the requirements of paragraphs (a)(1) through 
(3) of this section are met.


Sec.  60.5376b   What GHG and VOC standards apply to gas well liquids 
unloading operations at well affected facilities?

    (a) General requirements. You must comply with the requirements of 
this section for each gas well liquids unloading operation at your gas 
well affected facility as specified by paragraphs (a)(1) and (2) of 
this section. You have a general duty to safely maximize resource 
recovery and minimize releases to the atmosphere during gas well 
liquids unloading operations.
    (1) If a gas well liquids unloading operation technology or 
technique employed does not result in venting of methane and VOC 
emissions to the atmosphere, you must comply with the requirements 
specified in paragraphs (a)(1)(A) and (B). If an unplanned venting 
event occurs, you must meet the requirements specified in paragraphs 
(c) through (f) of this section.
    (A) Comply with the recordkeeping requirements specified in Sec.  
60.5420b(c)(2)(i).
    (B) Submit the information specified in Sec.  60.5420b(b)(1) and 
(b)(3)(i) in the annual report.
    (2) If a gas well liquids unloading operation technology or 
technique vents methane and VOC emissions to the atmosphere, you must 
comply with the requirements specified in paragraphs (b) and (c), or 
paragraph (g) of this section.
    (b) Work Practice Standards. If a gas well liquids unloading 
operation employs a technology or technique that vents methane and VOC 
emissions to the atmosphere, you must comply with the requirements in 
paragraphs (b)(1) through (3) and paragraphs (c) through (f) of this 
section.
    (1) Employ best management practices to minimize venting of methane 
and VOC emissions as specified in paragraph (c) of this section for 
each gas well liquids unloading operation.
    (2) Comply with the recordkeeping requirements specified in Sec.  
60.5420b(c)(2)(ii).
    (3) Submit the information specified in Sec.  60.5420b(b)(1) and 
(b)(3)(ii) in the annual report.
    (c) Best management practice requirements. For each gas well 
liquids unloading operation complying with paragraphs (a)(2) and (b) of 
this section, you must develop, maintain, and follow a best management 
practice plan to minimize venting of methane and VOC emissions to the 
maximum extent possible from each gas well liquids unloading operation. 
This best management practice plan must meet the minimum criteria 
specified in paragraphs (c)(1) through (4) of this section.
    (1) Include steps that create a differential pressure to minimize 
the need to vent a well to unload liquids,
    (2) Include steps to reduce wellbore pressure as much as possible 
prior to opening the well to the atmosphere,
    (3) Unload liquids through the separator where feasible, and
    (4) Close all wellhead vents to the atmosphere and return the well 
to production as soon as practicable.
    (d) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to well liquids unloading operations at 
your well affected facilities as required by Sec.  60.5410b(b).
    (e) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to well liquids unloading 
operations at your well affected facilities as required by Sec.  
60.5415b(b).
    (f) Recordkeeping and reporting. You must perform the required 
notification, recordkeeping and reporting requirements as specified in 
Sec.  60.5420b(b)(3) and (c)(2).
    (g) Other compliance options. Reduce methane and VOC emissions from 
well affected facility gas wells that unload liquids by 95.0 percent by 
complying with the requirements specified in paragraphs (g)(1) and (2) 
of this section and meeting the initial and continuous compliance and 
recordkeeping and reporting requirements specified in paragraphs (g)(3) 
through (5) of this section.
    (1) You must route emissions through a closed vent system to a 
control device

[[Page 17053]]

that meets the conditions specified in Sec.  60.5412b.
    (2) You must route emissions through a closed vent system that 
meets the requirements of Sec.  60.5411b(a) and (c).
    (3) You must demonstrate initial compliance with standards that 
apply to well affected facility gas well liquids unloading as required 
by Sec.  60.5410b(b).
    (4) You must demonstrate continuous compliance with standards that 
apply to well affected facility gas well liquids unloading as required 
by Sec.  60.5415b(f).
    (5) You must perform the reporting as required by Sec.  
60.5420b(b)(1), (3), and (11) through (13), as applicable, and the 
recordkeeping as required by Sec.  60.5420b(c)(2), (8), and (10) 
through (13), as applicable.


Sec.  60.5377b   What GHG and VOC standards apply to associated gas 
wells at well affected facilities?

    (a) You must comply with either paragraph (a)(1), (2), (3), or (4) 
of this section for each associated gas well upon startup and at all 
times, except as provided in paragraphs (b) through (f) of this 
section. You must also comply with paragraphs (h), (i), and (j) of this 
section.
    (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.
    (4) Recover the associated gas from the separator and reinject the 
recovered gas into the well or inject the recovered gas into another 
well.
    (b) For associated gas wells that commenced construction between 
May 7, 2024 and May 7, 2026, you can comply with the requirements in 
paragraph (f) of this section continually upon startup instead of 
paragraph (a) of this section until May 7, 2026 if you demonstrate and 
certify that it is not feasible to comply with paragraphs (a)(1), (2), 
(3), and (4) of this section due to technical reasons in accordance 
with paragraph (g) of this section. After May 7, 2026 you must 
continually comply with paragraph (a) of this section at all times.
    (c) For associated gas wells that commenced construction between 
December 6, 2022, and May 7, 2024, and for associated gas wells that 
undergo reconstruction or modification after December 6, 2022, you can 
comply with the requirements in paragraph (f) of this section instead 
of paragraph (a) of this section if you demonstrate and certify that it 
is not feasible to comply with paragraph (a)(1), (2), (3), and (4) of 
this section due to technical reasons in accordance with paragraph (g) 
of this section. Associated gas wells that are modified or 
reconstructed must comply with paragraph (a) or (f) of this section 
upon startup and at all times thereafter.
    (d) If you are complying with paragraph (a) of this section, you 
may temporarily route the associated gas to a flare or control device 
that achieves a 95.0 percent reduction in VOC and methane emissions in 
the situations and for the durations identified in paragraphs (d)(1), 
(2), (3), or (4) of this section. The associated gas must be routed 
through a closed vent system that meets the requirements of Sec.  
60.5411b(a) and (c) and the control device must meet the conditions 
specified in Sec.  60.5412b during the period when the associated gas 
is routed to the flare. Records must be kept of all instances in which 
associated gas is temporarily routed to a flare or to a control device 
in accordance with Sec.  60.5420b(c)(3)(i)(B) and reported in the 
annual report in accordance with Sec.  60.5420b(b)(4)(i)(B).
    (1) During a malfunction or incident that endangers the safety of 
operator personnel or the public you are allowed to route to a flare or 
control device for 24 hours or less per incident.
    (2) During repair, maintenance including blow downs, a production 
test, or commissioning, you are allowed to route to a flare or control 
device for 24 hours or less per incident.
    (3) For wells complying with paragraph (a)(1) of this section, 
during a temporary interruption in service from the gathering or 
pipeline system you are allowed to route to a flare or route to a 
control device for the duration of the temporary interruption not to 
exceed 30 days per incident.
    (4) During periods when the composition of the associated gas does 
not meet pipeline specifications for sources complying with paragraph 
(a)(1) of this section, or when the composition of the associated gas 
does not meet the quality requirements for use as a fuel for sources 
complying with paragraph (a)(2) of this section, or when the 
composition of the associated gas does not meet the quality 
requirements for another useful purpose for sources complying with 
paragraph (a)(3) of this section, you are allowed to route to a flare 
or control device until the associated gas meets the required 
specifications or for 72 hours per incident, whichever is less.
    (e) If you are complying with paragraph (a), (d), or (f) of this 
section, you may vent the associated gas in the situations and for the 
durations identified in paragraphs (e)(1), (2), or (3) of this section 
per incident. The cumulative period of venting must not exceed 24 hours 
for any calendar year. Records must be kept of all venting instances in 
accordance with Sec.  60.5420b(c)(3)(ii) and reported in the annual 
report in accordance with Sec.  60.5420b(b)(4)(ii).
    (1) For up to 12 hours per incident to protect the safety of 
personnel.
    (2) For up to 30 minutes per incident during bradenhead monitoring.
    (3) For up to 30 minutes per incident during a packer leakage test.
    (f) You must route the associated gas to a control device that 
reduces methane and VOC emissions by at least 95.0 percent. The 
associated gas must be routed through a closed vent system that meets 
the requirements of Sec.  60.5411b(a) and (c) and the control device 
must meet the conditions specified in Sec.  60.5412b.
    (1) For associated gas wells identified in paragraph (b) of this 
section, you can comply with the requirements in paragraph (f) of this 
section for up to a one year period if you demonstrate and certify that 
it is not feasible to comply with paragraph (a)(1), (2), (3), and (4) 
of this section due to technical reasons in accordance with paragraph 
(g) of this section. This allowance is renewable each year with an 
updated technical infeasibility demonstration and certification in 
accordance with paragraph (g) of this section. Associated gas wells 
identified in paragraph (b) of this section are not allowed to comply 
with the requirements in paragraph (f) of this section after May 7, 
2026.
    (2) For associated gas wells identified in paragraph (c) of this 
section, you can comply with the requirements in paragraph (f) of this 
section for up to a one year period if you demonstrate and certify that 
it is not feasible to comply with paragraph (a)(1), (2), (3), and (4) 
of this section due to technical reasons in accordance with paragraph 
(g) of this section. This allowance is renewable each year with an 
updated technical infeasibility demonstration and certification in 
accordance with paragraph (g) of this section.
    (g) For affected sources identified in paragraphs (b) and (c) of 
this section that are complying with the requirements in paragraph (f) 
of this section, you must demonstrate that it is not feasible to comply 
with paragraph (a)(1), (2), (3), and (4) of this section due to 
technical reasons by providing a detailed analysis documenting and 
certifying the technical reasons for this infeasibility.
    (1) The demonstration must address the technical infeasibility for 
all options

[[Page 17054]]

identified in (a)(1), (2), (3), and (4) of this section.
    (2) This demonstration must be certified by a professional engineer 
or another qualified individual with expertise in the uses of 
associated gas. The following certification, signed and dated by the 
qualified professional engineer or other qualified individual shall 
state: ``I certify that the assessment of technical and safety 
infeasibility was prepared under my direction or supervision. I further 
certify that the assessment was conducted, and this report was prepared 
pursuant to the requirements of Sec.  60.5377b(b)(1). Based on my 
professional knowledge and experience, and inquiry of personnel 
involved in the assessment, the certification submitted herein is true, 
accurate, and complete.''
    (3) This demonstration and certification are valid for no more than 
12 months. You must re-analyze the feasibility of complying with 
paragraphs (a)(1), (2), (3), and (4) of this section and finalize a new 
demonstration and certification each year.
    (4) Documentation of these demonstrations, along with the 
certifications, must be maintained in accordance with Sec.  
60.5420b(c)(3)(iii) and submitted in annual reports in accordance with 
Sec.  60.5420b(b)(4)(iii)(C) and (D).
    (h) You must demonstrate initial compliance with the standards that 
apply to associated gas wells as required by Sec.  60.5410b(c).
    (i) You must demonstrate continuous compliance with the standards 
that apply to associated gas wells as required by Sec.  60.5415b(c).
    (j) You must perform the reporting as required by Sec.  
60.5420b(b)(1) and (4), and (b)(11) and (12), as applicable; and the 
recordkeeping as required by Sec.  60.5420b(c)(3) and (8), and (c)(10) 
through (13), as applicable.


Sec.  60.5380b   What GHG and VOC standards apply to centrifugal 
compressor affected facilities?

    Each centrifugal compressor affected facility must comply with the 
GHG and VOC standards in paragraphs (a) through (d) of this section.
    (a) Each centrifugal compressor affected facility that uses wet 
seals must comply with the GHG and VOC standards in paragraphs (a)(1), 
(2), or (3) of this section. Each self-contained wet seal compressor, 
and each centrifugal compressor on the Alaska North Slope equipped with 
sour seal oil separator and capture system, must comply with the GHG 
and VOC standards in paragraphs (a)(1) and (2) of this section, or one 
of the alternatives in (a)(3) through (5) of this section, as 
applicable, and (a)(8) of this section. Each centrifugal compressor 
affected facility that uses dry seals must comply with paragraphs 
(a)(6) through (8) of this section, or with of the alternatives in 
paragraph (a)(9) of this section.
    (1) You must reduce methane and VOC emissions from each centrifugal 
compressor wet seal fluid degassing system by 95.0 percent.
    (2) If you use a control device to reduce emissions, you must equip 
the wet seal fluid degassing system with a cover that meets the 
requirements of Sec.  60.5411b(b). The cover must be connected through 
a closed vent system that meets the requirements of Sec.  60.5411b(a) 
and (c) and the closed vent system must be routed to a control device 
that meets the conditions specified in Sec.  60.5412b.
    (3) As an alternative to routing the closed vent system to a 
control device, you may route the closed vent system to a process. If 
you route the emissions to a process, you must equip the wet seal fluid 
degassing system with a cover that meets the requirements of Sec.  
60.5411b(b). The cover must be connected through a closed vent system 
that meets the requirements of Sec.  60.5411b(a) and (c).
    (4) If you own or operate a self-contained wet seal centrifugal 
compressor you may comply with the GHG and VOC requirements as 
specified in paragraph (a)(4)(i) through (iii) of this section, using 
volumetric flow rate as a surrogate, in lieu of meeting the 
requirements specified in paragraphs (a)(1) and (2) of this section. 
You must determine the volumetric flow rate in accordance with 
paragraph (a)(7)(i) of this section.
    (i) The volumetric flow rate must not exceed 3 standard cubic feet 
per minute (scfm) per seal. If the individual seals are manifolded to a 
single open-ended vent line, the volumetric flow rate must not exceed 
the sum of the individual seals multiplied by 3 scfm. If the volumetric 
flow rate, measured in accordance with paragraph (a)(7)(i) of this 
section exceeds 3 scfm multiplied by the number of wet seals connected 
to the vent, the seals connected to the measured vent must be repaired 
as provided in paragraph (a)(8) of this section.
    (ii) You must conduct your first volumetric flow rate measurement 
from your self-contained wet seal compressor on or before 8,760 hours 
of operation after May 7, 2024 or on or before 8,760 hours of operation 
after startup, whichever date is later.
    (iii) You must conduct subsequent volumetric flow rate measurements 
from your self-contained wet seal centrifugal compressor on or before 
8,760 hours of operation after the previous measurement which 
demonstrates compliance with the 3 scfm volumetric flow rate per seal. 
If the individual seals are manifolded to a single open-ended vent 
line, the volumetric flow rate must not exceed the sum of the 
individual seals multiplied by 3 scfm.
    (5) If you own or operate a centrifugal compressor on the Alaska 
North Slope equipped with seal oil separator and capture system, you 
may comply with the GHG and VOC requirements specified in paragraphs 
(a)(5)(i) through (iii) of this section using volumetric flow rate as a 
surrogate, in lieu of meeting the requirements specified in paragraphs 
(a)(1) and (2). You must determine the volumetric flow rate in 
accordance with paragraph (a)(7)(ii) of this section.
    (i) The volumetric flow rate per seal must not exceed 9 scfm per 
seal. If the individual seals are manifolded to a single open-ended 
vent line, the volumetric flow rate must not exceed the sum of the 
individual seals multiplied by 9 scfm. If the volumetric flow rate, 
measured in accordance with paragraph (a)(7)(ii) of this section 
exceeds 9 scfm multiplied by the number of wet seals connected to the 
vent, the seals connected to the measured vent must be repaired as 
provided in paragraph (a)(8) of this section.
    (ii) You must conduct your first volumetric flow rate measurement 
from your Alaska North Slope centrifugal compressor equipped with a 
sour seal oil separator and capture system on or before 8,760 hours of 
operation after May 7, 2024 or on or before 8,760 hours of operation 
after startup, whichever date is later.
    (iii) You must conduct subsequent volumetric flow rate measurements 
from your Alaska North Slope centrifugal compressor equipped with sour 
seal separator and capture system on or before 8,760 hours of operation 
after the previous measurement which demonstrates compliance with the 9 
scfm volumetric flow rate per seal. If the individual seals are 
manifolded to a single open-ended vent line, the volumetric flow rate 
must not exceed the sum of the individual seals multiplied by 9 scfm.
    (6) If you own or operate a centrifugal compressor equipped with 
dry seals, you must comply with the GHG and VOC requirements as 
specified in paragraphs (a)(6)(i) through (iii), using volumetric flow 
rate as a surrogate. You must determine the volumetric flow rate in 
accordance with paragraph (a)(7)(iii) of this section.

[[Page 17055]]

    (i) The volumetric flow rate per seal must not exceed 10 standard 
cubic feet per minute (scfm) per seal. If the individual seals are 
manifolded to a single open-ended vent line, the volumetric flow rate 
must not exceed the sum of the individual seals multiplied by 10 scfm. 
If the volumetric flow rate, measured in accordance with paragraph 
(a)(7)(iii) of this section exceeds 10 scfm multiplied by the number of 
dry seals connected to the vent, the seals connected to the measured 
vent must be repaired as provided in paragraph (a)(8) of this section.
    (ii) You must conduct your first volumetric flow rate measurement 
from your centrifugal compressor equipped with a dry seal on or before 
8,760 hours of operation after May 7, 2024 or on or before 8,760 hours 
of operation after startup, whichever date is later.
    (iii) You must conduct subsequent volumetric flow rate measurements 
from your centrifugal compressor equipped with dry seals on or before 
8,760 hours of operation after the previous measurement which 
demonstrates compliance with the 10 scfm volumetric flow rate per seal. 
If the individual seals are manifolded to a single open-ended vent 
line, the volumetric flow rate must not exceed the sum of the 
individual seals multiplied by 10 scfm.
    (7) You must determine the volumetric flow rate for your 
centrifugal compressor, as specified in paragraphs (a)(7)(i) through 
(iii) of this section.
    (i) You must determine the volumetric flow rate from your self-
contained wet seal centrifugal compressor wet seal as specified in 
paragraph (a)(7)(i)(A) or (B) of this section. If the volumetric flow 
rate exceeds 3 scfm multiplied by the number of wet seals connected to 
the vent, the wet seals connected to the measured vent must be repaired 
as provided in paragraph (a)(8) of this section.
    (A) For self-contained wet seal centrifugal compressors in 
operating-mode or in standby-pressurized-mode, determine volumetric 
flow rate at standard conditions from each self-contained wet seal 
centrifugal compressor wet seal using one of the methods specified in 
paragraphs (a)(7)(i)(A)(1) through (3) of this section.
    (1) You may choose to use any of the methods set forth in Sec.  
60.5386b(a) to screen for leaks/emissions. For the purposes of this 
paragraph, when using any of the methods in Sec.  60.5386b(a), 
emissions are detected whenever a leak is detected according to the 
method. If emissions are detected using the methods set forth in Sec.  
60.5386b(a), then you must use one of the methods specified in 
paragraph (a)(7)(i)(A)(2) or (3) of this section to determine the 
volumetric flow rate. If emissions are not detected using the methods 
in Sec.  60.5386b(a), then you may assume that the volumetric emissions 
are zero.
    (2) Use a temporary or permanent flow meter according to methods 
set forth in Sec.  60.5386b(b).
    (3) Use a high-volume sampler according to the method set forth in 
Sec.  60.5386b(c).
    (B) For conducting measurements on manifolded groups of self-
contained wet seal centrifugal compressor seals, you must determine the 
volumetric flow rate from the self-contained wet seal centrifugal 
compressor seal as specified in paragraph (a)(7)(i)(B)(1) or (2) of 
this section.
    (1) Measure at a single point in the manifold downstream of all 
self-contained wet seal centrifugal compressor seal inputs and, if 
practical, prior to comingling with other non-compressor emission 
sources.
    (2) Determine the volumetric flow rate at standard conditions from 
the common stack using one of the methods specified in paragraph 
(a)(7)(i)(A)(1) through (3) of this section.
    (ii) You must determine the volumetric flow rate from your 
centrifugal compressor on the Alaska North Slope equipped with sour 
seal oil separator and capture system as specified in paragraph 
(a)(7)(ii)(A) or (B) of this section. If the volumetric flow rate 
exceeds 9 scfm multiplied by the number of wet seals connected to the 
vent, the wet seals connected to the measured vent must be repaired as 
provided in paragraph (a)(8) of this section.
    (A) For centrifugal compressors in operating-mode or in standby-
pressurized-mode, determine volumetric flow rate at standard conditions 
from each centrifugal compressor on the Alaska North Slope equipped 
with a sour seal oil separator and capture system using one of the 
methods specified in paragraphs (a)(7)(ii)(A)(1) through (3) of this 
section.
    (1) You may choose to use any of the methods set forth in Sec.  
60.5386b(a) to screen for leaks/emissions. For the purposes of this 
paragraph, when using any of the methods in Sec.  60.5386b(a), 
emissions are detected whenever a leak is detected according to the 
method. If emissions are detected using the methods set forth in Sec.  
60.5386b(a), then you must use one of the methods specified in 
paragraph (a)(7)(ii)(A)(2) or (3) of this section to determine the 
volumetric flow rate. If emissions are not detected using the methods 
in Sec.  60.5386b(a), then you may assume that the volumetric emissions 
are zero.
    (2) Use a temporary or permanent flow meter according to methods 
set forth in Sec.  60.5386b(b).
    (3) Use a high-volume sampler according to the method set forth in 
Sec.  60.5386b(c).
    (B) For conducting measurements on manifolded groups of centrifugal 
compressors on the Alaska North Slope equipped with sour seal oil 
separators and capture systems, you must determine the volumetric flow 
rate from the centrifugal compressors equipped with sour seal oil 
separators and capture systems as specified in paragraph 
(a)(7)(ii)(B)(1) or (2) of this section.
    (1) Measure at a single point in the manifold downstream of all 
centrifugal compressors on the Alaska North Slope equipped with sour 
seal oil separator and capture system wet seal inputs and, if 
practical, prior to comingling with other non-compressor emission 
sources.
    (2) Determine the volumetric flow rate at standard conditions from 
the common stack using one of the methods specified in paragraph 
(a)(7)(ii)(A)(1) through (3) of this section.
    (iii) You must determine the volumetric flow rate from your 
centrifugal compressor equipped with dry seals as specified in 
paragraph (a)(7)(iii)(A) or (B) of this section. If the volumetric flow 
rate exceeds 10 scfm multiplied by the number of dry seals connected to 
the vent, the dry seals connected to the measured vent must be repaired 
as provided in paragraph (a)(8) of this section.
    (A) For centrifugal compressors equipped with dry seals in 
operating-mode or in standby-pressurized-mode, determine volumetric 
flow rate at standard conditions from each centrifugal compressor 
equipped with dry seals using one of the methods specified in 
paragraphs (a)(7)(iii)(A)(1) through (3) of this section.
    (1) You may choose to use any of the methods set forth in Sec.  
60.5386b(a) to screen for leaks/emissions. For the purposes of this 
paragraph, when using any of the methods in Sec.  60.5386b(a), 
emissions are detected whenever a leak is detected according to the 
method. If emissions are detected using the methods set forth in Sec.  
60.5386b(a), then you must use one of the methods specified in 
paragraph (a)(7)(iii)(A)(2) or (3) of this section to determine the 
volumetric flow rate. If emissions are not detected using the methods 
in Sec.  60.5386b(a), then you may assume that the volumetric emissions 
are zero.
    (2) Use a temporary or permanent flow meter according to methods 
set forth in Sec.  60.5386b(b).

[[Page 17056]]

    (3) Use a high-volume sampler according to the method set forth in 
Sec.  60.5386b(c).
    (B) For conducting measurements on manifolded groups of centrifugal 
compressors equipped with dry seals, you must determine the volumetric 
flow rate from the dry seal centrifugal compressors as specified in 
paragraph (a)(7)(iii)(B)(1) or (2) of this section.
    (1) Measure at a single point in the manifold downstream of all 
centrifugal compressors equipped with dry seals inputs and, if 
practical, prior to comingling with other non-compressor emission 
sources.
    (2) Determine the volumetric flow rate at standard conditions from 
the common stack using one of the methods specified in paragraph 
(a)(7)(iii)(A)(1) through (3) of this section.
    (8) The seal must be repaired within 90 calendar days after the 
date of the volumetric emissions measurement that exceeds the 
applicable required flow rate per seal. You must conduct follow-up 
volumetric flow rate measurements from seal vents using the methods 
specified in paragraph (a)(7) of this section within 15 days after the 
repair to document that the rate has been reduced to less than the 
applicable required flow rate per seal. If the individual seals are 
manifolded to a single open-ended vent line or vent, the volumetric 
flow rate must be reduced to less than the sum of the individual seals 
multiplied by the applicable required flow rate per seal specified in 
paragraph (a)(4) through (6) of this section, as applicable. Delay of 
repair will be allowed if the conditions in paragraphs (a)(8)(i) or 
(ii) of this section are met.
    (i) If the repair of the wet or dry seal is technically infeasible, 
would require a vent blowdown, a compressor station shutdown, or would 
be unsafe to repair during operation of the unit, the repair must be 
completed during the next scheduled compressor station shutdown for 
maintenance, after a scheduled vent blowdown, or within 2 years of the 
date of the volumetric emissions measurement that exceeds the 
applicable required flow rate per seal, whichever is earliest. A vent 
blowdown is the opening of one or more blowdown valves to depressurize 
major production and processing equipment, other than a storage vessel.
    (ii) If the repair requires replacement of the compressor seal or a 
part thereof, but the replacement cannot be acquired and installed 
within the repair timelines specified under this section due to the 
condition specified in paragraph (a)(8)(ii)(A) of this section, the 
repair must be completed in accordance with paragraph (a)(8)(ii)(B) of 
this section and documented in accordance with Sec.  
60.5420b(c)(4)(iii)(F) through (H).
    (A) Seal or part thereof supplies had been sufficiently stocked but 
are depleted at the time of the required repair.
    (B) The required replacement must be ordered no later than 10 
calendar days after the centrifugal compressor seal is added to the 
delay of repair list due to parts unavailability. The repair must be 
completed as soon as practicable, but no later than 30 calendar days 
after receipt of the replacement seal or part, unless the repair 
requires a compressor station shutdown. If the repair requires a 
compressor station shutdown, the repair must be completed in accordance 
with the timeframe specified in paragraph (a)(8)(i) of this section.
    (9) As an alternative to meeting the requirements for centrifugal 
compressors with dry seals specified in paragraphs (a)(6) through (8) 
of this section, owners or operators are allowed to comply with the 
standard by meeting the requirements specified in paragraphs (a)(9)(i) 
and (ii), or (a)(9)(iii) of this section.
    (i) You must reduce methane and VOC emissions from each centrifugal 
compressor dry seal system by 95.0 percent.
    (ii) If you use a control device to reduce emissions, you must 
equip the dry seal system with a cover that meets the requirements of 
Sec.  60.5411b(b). The cover must be connected through a closed vent 
system that meets the requirements of Sec.  60.5411b(a) and (c) and the 
closed vent system must be routed to a control device that meets the 
conditions specified in Sec.  60.5412b.
    (iii) As an alternative to routing the closed vent system to a 
control device, you may route the closed vent system to a process. If 
you route the emissions to a process, you must equip the dry seal 
system with a cover that meets the requirements of Sec.  60.5411b(b). 
The cover must be connected through a closed vent system that meets the 
requirements of Sec.  60.5411b(a) and (c).
    (b) You must demonstrate initial compliance with the standards that 
apply to centrifugal compressor affected facilities as required by 
Sec.  60.5410b(d).
    (c) You must demonstrate continuous compliance with the standards 
that apply to centrifugal compressor affected facilities as required by 
Sec.  60.5415b(d).
    (d) You must perform the reporting as required by Sec.  
60.5420b(b)(1) and (5), and (b)(11) through (13), as applicable; and 
the recordkeeping as required by Sec.  60.5420b(c)(4), and (8) through 
(13), as applicable.


Sec.  60.5385b   What GHG and VOC standards apply to reciprocating 
compressor affected facilities?

    Each reciprocating compressor affected facility must comply with 
the GHG and VOC standards, using volumetric flow rate as a surrogate, 
in paragraphs (a) through (c) of this section, or the GHG and VOC 
standards in paragraph (d) of this section. You must also comply with 
the requirements in paragraphs (e) through (g) of this section.
    (a) The volumetric flow rate of each cylinder, measured in 
accordance with paragraph (b) or (c) of this section, must not exceed 2 
scfm per individual cylinder. If the individual cylinders are 
manifolded to a single open-ended vent line, the volumetric flow rate 
must not exceed the sum of the individual cylinders multiplied by 2 
scfm. You must conduct measurements of the volumetric flow rate in 
accordance with the schedule specified in paragraphs (a)(1) and (2) of 
this section and determine the volumetric flow rate per cylinder in 
accordance with paragraph (b) or (c) of this section. If the volumetric 
flow rate, measured in accordance with paragraph (b) or (c) of this 
section, for a cylinder exceeds 2 scfm per cylinder (or a combined 
volumetric flow rate greater than the number of compression cylinders 
multiplied by 2 scfm), the rod packing or packings must be repaired or 
replaced as provided in paragraph (a)(3) of this section.
    (1) You must conduct your first volumetric flow rate measurements 
from your reciprocating compressor rod packing vent on or before 8,760 
hours of operation after May 7, 2024, or on or before 8,760 hours of 
operation after last rod packing replacement, or on or before 8,760 
hours of operation after startup, whichever date is later.
    (2) You must conduct subsequent volumetric flow rate measurements 
from your reciprocating compressor rod packing vent on or before 8,760 
hours of operation after the previous measurement which demonstrates 
compliance with the applicable volumetric flow rate of 2 scfm per 
cylinder (or a combined volumetric flow rate greater than the number of 
compression cylinders multiplied by 2 scfm), or on or before 8,760 
hours of operation after last rod packing replacement, whichever date 
is later.
    (3) The rod packing must be repaired or replaced within 90 calendar 
days after the date of the volumetric emissions measurement that 
exceeded 2 scfm per cylinder. You must conduct follow-up volumetric 
flow rate measurements from compressor vents

[[Page 17057]]

using the methods specified in paragraph (b) of this section within 15 
days after the repair (or rod packing replacement) to document that the 
rate has been reduced to less than 2 scfm per cylinder. Delay of repair 
will be allowed if the conditions in paragraphs (a)(3)(i) or (ii) of 
this section are met.
    (i) If the repair (or rod packing replacement) is technically 
infeasible, would require a vent blowdown, a compressor station 
shutdown, or would be unsafe to repair during operation of the unit, 
the repair (or rod packing replacement) must be completed during the 
next scheduled compressor station shutdown for maintenance, after a 
scheduled vent blowdown, or within 2 years of the date of the 
volumetric emissions measurement that exceeds the applicable required 
flow rate per cylinder, whichever is earliest. A vent blowdown is the 
opening of one or more blowdown valves to depressurize major production 
and processing equipment, other than a storage vessel.
    (ii) If the repair requires replacement of the rod packing or a 
part, but the replacement cannot be acquired and installed within the 
repair timelines specified under this section due to the condition 
specified in paragraph (a)(3)(ii)(A) of this section, the repair must 
be completed in accordance with paragraph (a)(3)(ii)(B) of this section 
and documented in accordance with Sec.  60.5420b(c)(5)(viii) through 
(x).
    (A) Rod packing or part supplies had been sufficiently stocked but 
are depleted at the time of the required repair.
    (B) The required rod packing or part replacement must be ordered no 
later than 10 calendar days after the reciprocating compressor is added 
to the delay of repair list due to parts unavailability. The repair 
must be completed as soon as practicable, but no later than 30 calendar 
days after receipt of the replacement rod packing or part, unless the 
repair requires a compressor station shutdown. If the repair requires a 
compressor station shutdown, the repair must be completed in accordance 
with the timeframe specified in paragraph (a)(3)(i) of this section.
    (b) You must determine the volumetric flow rate per cylinder from 
your reciprocating compressor as specified in paragraph (b)(1) or (2) 
of this section.
    (1) For reciprocating compressor rod packing equipped with an open-
ended vent line on compressors in operating or standby pressurized 
mode, determine the volumetric flow rate of the rod packing using one 
of the methods specified in paragraphs (b)(1)(i) through (iii) of this 
section.
    (i) Determine the volumetric flow rate at standard conditions from 
the open-ended vent line using a high-volume sampler according to 
methods set forth in Sec.  60.5386b(c).
    (ii) Determine the volumetric flow rate at standard conditions from 
the open-ended vent line using a temporary or permanent meter, 
according to methods set forth in Sec.  60.5386b(b).
    (iii) Any of the methods set forth in Sec.  60.5386b(a) to screen 
for leaks and emissions. For the purposes of this paragraph, emissions 
are detected whenever a leak is detected according to any of the 
methods in Sec.  60.5386b(a). If emissions are detected using the 
methods set forth in Sec.  60.5386b(a), then you must use one of the 
methods specified in paragraph (b)(1)(i) and (ii) of this section to 
determine the volumetric flow rate per cylinder. If emissions are not 
detected using the methods in Sec.  60.5386b(a), then you may assume 
that the volumetric flow rate is zero.
    (2) For reciprocating compressor rod packing not equipped with an 
open-ended vent line on compressors in operating or standby pressurized 
mode, you must determine the volumetric flow rate of the rod packing 
using the methods specified in paragraphs (b)(2)(i) and (ii) of this 
section.
    (i) You must use the methods described in Sec.  60.5386b(a) to 
conduct leak detection of emissions from the rod packing case into an 
open distance piece, or, for compressors with a closed distance piece, 
you must conduct annual leak detection of emissions from the rod 
packing vent, distance piece vent, compressor crank case breather cap, 
or other vent emitting gas from the rod packing.
    (ii) You must measure emissions found in paragraph (b)(2)(i) of 
this section using a meter or high-volume sampler according to methods 
set forth in Sec.  60.5386b(b) or (c).
    (c) For conducting measurements on manifolded groups of 
reciprocating compressor affected facilities, you must determine the 
volumetric flow rate from reciprocating compressor rod packing vent as 
specified in paragraph (c)(1) and (2) of this section.
    (1) Measure at a single point in the manifold downstream of all 
compressor vent inputs and, if practical, prior to comingling with 
other non-compressor emission sources.
    (2) Determine the volumetric flow rate per cylinder at standard 
conditions from the common stack using one of the methods specified in 
paragraph (c)(2)(i) through (iv) of this section.
    (i) A temporary or permanent flow meter according to the methods 
set forth in Sec.  60.5386b(b).
    (ii) A high-volume sampler according to methods set forth Sec.  
60.5386b(c).
    (iii) An alternative method, as set forth in Sec.  60.5386b(d).
    (iv) Any of the methods set forth in Sec.  60.5386b(a) to screen 
for emissions. For the purposes of this paragraph, emissions are 
detected whenever a leak is detected when using any of the methods in 
Sec.  60.5386b(a). If emissions are detected using the methods set 
forth in Sec.  60.5386b(a), then you must use one of the methods 
specified in paragraph (c)(2)(i) through (iii) of this section to 
determine the volumetric flow rate per cylinder. If emissions are not 
detected using the methods in Sec.  60.5386b(a), then you may assume 
that the volumetric flow rate is zero.
    (d) As an alternative to complying with the GHG and VOC standards 
in paragraphs (a) through (c) of this section, owners or operators can 
meet the requirements specified in paragraph (d)(1), (2), or (3) of 
this section.
    (1) Collect the methane and VOC emissions from your reciprocating 
compressor rod packing using a rod packing emissions collection system 
that is operated to route the rod packing emissions to a process. In 
order to comply with this option, you must equip the reciprocating 
compressor with a cover that meets the requirements of Sec.  
60.5411b(b). The cover must be connected through a closed vent system 
that meets the requirements of Sec.  60.5411b(a) and (c).
    (2) Reduce methane and VOC emissions from each rod packing 
emissions collection system by using a control device that reduces 
methane and VOC emissions by 95.0 percent. In order to comply with this 
option, you must equip the reciprocating compressor with a cover that 
meets the requirements of Sec.  60.5411b(b). The cover must be 
connected through a closed vent system that meets the requirements of 
Sec.  60.5411b(a) and (c) and the closed vent system must be routed to 
a control device that meets the conditions specified in Sec.  60.5412b.
    (3) As an alternative to conducting the required volumetric flow 
rate measurements under paragraph (a) of this section, an owner or 
operator can choose to comply by replacing the rod packing on or before 
8,760 hours of operation after initial startup, on or before 8,760 
hours of operation after May 7, 2024, on or before 8,760 hours of 
operation after the previous flow rate measurement, or on or before 
8,760 hours of operation after the date of the

[[Page 17058]]

most recent compressor rod packing replacement, whichever date is 
later.
    (e) You must demonstrate initial compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5410b(e).
    (f) You must demonstrate continuous compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5415b(g).
    (g) You must perform the reporting requirements as specified in 
Sec.  60.5420b(b)(1), (6), (11), and (12), as applicable; and the 
recordkeeping requirements as specified in Sec.  60.5420b(c)(5) and (8) 
through (13), as applicable.


Sec.  60.5386b   What test methods and procedures must I use for my 
centrifugal compressor and reciprocating compressor affected 
facilities?

    (a) You must use one of the methods described in paragraph (a)(1) 
and (2) of this section to screen for emissions or leaks from the 
reciprocating compressor rod packing when complying with Sec.  
60.5385b(b)(1)(iii) and from applicable wet seal centrifugal compressor 
and dry seal centrifugal compressor vents when complying with Sec.  
60.5380b(a)(3) through (6).
    (1) OGI instrument. Use an OGI instrument for equipment leak 
detection as specified in either paragraph (a)(1)(i) or (ii) of this 
section. For the purposes of paragraphs (a)(1)(i) and (ii) of this 
section, any visible emissions observed by the OGI instrument from 
reciprocating rod packing or compressor dry seal vent is a leak.
    (i) OGI instrument as specified in appendix K of this part. For 
reciprocating compressor, applicable wet seal centrifugal compressor, 
and dry seal centrifugal compressor affected facilities located at 
onshore natural gas processing plants, use an OGI instrument to screen 
for emissions from reciprocating rod packing or centrifugal compressor 
dry seal vent in accordance with the protocol specified in appendix K 
of this part.
    (ii) OGI instrument as specified in Sec.  60.5397b of this subpart. 
For reciprocating compressor, applicable wet seal centrifugal 
compressor, and dry seal centrifugal compressor affected facilities 
located at centralized production facilities, compressor stations, or 
other location that is not an onshore natural gas processing plant, use 
an OGI instrument to screen for emissions from reciprocating rod 
packing or compressor dry seals in accordance with the elements of 
Sec.  60.5397b(c)(7).
    (2) Method 21. Use Method 21 in appendix A-7 to this part according 
to Sec.  60.5403b(b)(1) and (2). For the purposes of this section, an 
instrument reading of 500 parts per million by volume (ppmv) above 
background or greater is a leak.
    (b) You must determine natural gas volumetric flow rate using a 
rate meter which meets the requirement in Method 2D in appendix A-1 of 
this part. Rate meters must be calibrated on an annual basis according 
to the requirements in Method 2D.
    (c) You must use a high-volume sampler to measure emissions of the 
reciprocating compressor rod packing. applicable centrifugal compressor 
wet seal vent, or centrifugal compressor dry seal vent in accordance 
with paragraphs (c)(1) through (7) of this section.
    (1) You must use a high-volume sampler designed to capture the 
entirety of the emissions from the applicable vent and measure the 
entire range of methane concentrations being emitted as well as the 
total volumetric flow at standard conditions. You must develop a 
standard operating procedure for this device and document these 
procedures in the appropriate monitoring plan. In order to get reliable 
results, persons using this device should be knowledgeable in its 
operation and the requirements in this section.
    (2) This procedure may involve hazardous materials, operations, and 
equipment. This procedure may not address all of the safety problems 
associated with its use. It is the responsibility of the user of this 
procedure to establish appropriate safety and health practices and 
determine the applicability of regulatory limitations prior to 
performing this procedure.
    (3) The high-volume sampler must include a methane gas sensor(s) 
which meets the requirements in paragraphs (c)(3)(i) through (iii) of 
this section.
    (i) The methane sensor(s) must be selective to methane with minimal 
interference, less than 2.5 percent for the sum of responses to other 
compounds in the gas matrix. You must document the minimal interference 
though empirical testing or through data provided by the manufacturer 
of the sensor.
    (ii) The methane sensor(s) must have a measurement range over the 
entire expected range of concentrations.
    (iii) The methane sensor(s) must be capable of taking a measurement 
once every second, and the data system must be capable of recording 
these results for each sensor at all times during operation of the 
sampler.
    (4) The high-volume sampler must be designed such that it is 
capable of sampling sufficient volume in order to capture all emissions 
from the applicable vent. Your high-volume sampler must include a flow 
measurement sensor(s) which meets the requirements of paragraphs 
(c)(4)(i) and (ii) of this section.
    (i) The flow measurement sensor must have a measurement range over 
the entire expected range of flow rates sampled. If needed multiple 
sensors may be used to capture the entire range of expected flow rates.
    (ii) The flow measurement sensor(s) must be capable of taking a 
measurement once every second, and the data system must be capable of 
recording these results for each sensor at all times during operation 
of the sampler.
    (5) You must calibrate your methane sensor(s) according to the 
procedures in paragraphs (c)(5)(i)(A) and (B) of this section, and flow 
measurement sensors must be calibrated according to the procedures in 
paragraph (c)(5)(ii) of this section.
    (i) For Methane Sensor Calibration:
    (A) Initially and on a semi-annual basis, determine the linearity 
at four points through the measurement range for each methane sensor 
using methane gaseous calibration cylinder standards. At each point, 
the difference between the cylinder value and the sensor reading must 
be less than 5 percent of the respective calibration gas value. If the 
sensor does not meet this requirement, perform corrective action on the 
sensor, and do not use the sampler until these criteria can be met.
    (B) Prior to and at the end of each testing day, challenge each 
sensor at two points, a low point, and a mid-point, using methane 
gaseous calibration cylinder standards. At each point, the difference 
between the cylinder value and the sensor reading must be less than 5 
percent of the respective calibration gas value. If the sensor does not 
meet this requirement, perform corrective action on the sensor and do 
not use the sampler again until these criteria can be met. If the post-
test calibration check fails at either point, invalidate the data from 
all tests performed subsequent to the last passing calibration check.
    (ii) Flow measurement sensors must meet the requirements in Method 
2D in appendix A-1 of this part. Rate meters must be calibrated on an 
annual basis according to the requirements in Method 2D. If your flow 
sensor relies on ancillary temperature and pressure measurements to 
correct the flow rate to standard conditions, the temperature and 
pressure sensors must also be calibrated on an annual basis. Standard 
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92 
in. Hg).

[[Page 17059]]

    (6) You must conduct sampling of the reciprocating compressor rod 
packing, applicable wet seal centrifugal compressor, or dry seal 
centrifugal compressor vent in accordance with the procedures in 
paragraphs (c)(6)(i) through (v) of this section.
    (i) The instrument must be operated consistent with manufacturer 
recommendations; users are encouraged to develop a standard operating 
procedure to document the exact procedures used for sampling.
    (ii) Identify the rod packing, applicable wet seal centrifugal 
compressor, or dry seal centrifugal compressor vent to be measured and 
record the signal to noise ratio (S/N) of the engine. Collect a 
background methane sample in ppmv for a minimum of one minute and 
record the result along with the date and time.
    (iii) Approach the vent with the sample hose and adjust the sampler 
so that you are measuring at the full flow rate. Then, adjust the flow 
rate to ensure the measured methane concentration is within the 
calibrated range of the methane sensor and minimum methane 
concentration is at least 2 ppmv higher than the background 
concentration. Sample for a period of at least one minute and record 
the average flow rate in standard cubic feet per minute and the methane 
sample concentration in ppmv, along with the date and time. Standard 
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92 
in. Hg).
    (iv) Calculate the leak rate according to the following equation:
    [GRAPHIC] [TIFF OMITTED] TR08MR24.000
    
Where:

CH4<INF>B</INF> = background methane concentration, ppmv
CH4<INF>S</INF> = methane sample concentration, ppmv
    V = Average flow rate of the sampler, scfm
    Q = Methane emission rate, scfm

    (v) You must collect at least three separate one-minute 
measurements and determine the average leak rate. The relative percent 
difference of these three separate samples should be less than 10 
percent.
    (7) If the measured natural gas flow determined as specified in 
paragraph (c)(6) of this section exceeds 70.0 percent of the 
manufacturer's reported maximum sampling flow rate you must either use 
a temporary or permanent flow meter according to paragraph (b) of this 
section or use another method meeting the requirements in paragraph (d) 
of this section to determine the leak or flow rate.
    (d) As an alternative to a high-volume sampler, you may use any 
other method that has been validated in accordance with the procedures 
specified in Method 301 in appendix A in 40 CFR part 63, subject to 
Administrator approval, as specified in Sec.  60.8(b).


Sec.  60.5390b   What GHG and VOC standards apply to process controller 
affected facilities?

    Each process controller affected facility must comply with the GHG 
and VOC standards in this section.
    (a) You must design and operate each process controller affected 
facility with zero methane and VOC emissions to the atmosphere, except 
as provided in paragraph (b) of this section.
    (1) If you comply by routing the emissions to a process, emissions 
must be routed to a process through a closed vent system.
    (2) If you comply by using a self-contained natural gas-driven 
process controller, you must design and operate each self-contained 
natural gas-driven process controller with no identifiable emissions, 
as demonstrated by Sec.  60.5416b(b).
    (b) For each process controller affected facility located at a site 
in Alaska that does not have access to electrical power, you may comply 
with either paragraphs (b)(1) and (2) of this section or with paragraph 
(b)(3) of this section, instead of complying with paragraph (a) of this 
section.
    (1) With the exception of natural gas-driven continuous bleed 
controllers that meet the condition in paragraph (b)(1)(i) of this 
section and that comply with paragraph (b)(1)(ii) of this section, each 
natural gas-driven continuous bleed process controller in the process 
controller affected facility must have a bleed rate less than or equal 
to 6 standard cubic feet per hour (scfh).
    (i) A natural gas-driven continuous bleed process controller with a 
bleed rate higher than 6 scfh may be used if the requirements of 
paragraph (b)(1)(ii) of this section are met.
    (ii) You demonstrate that a natural gas-driven continuous bleed 
controller with a bleed rate higher than 6 scfh is required. The 
demonstration must be based on the specific functional need, including 
but not limited to response time, safety, or positive actuation.
    (2) Each natural gas-driven intermittent vent process controller in 
the process controller affected facility must comply with the 
requirements in paragraphs (b)(2)(i) and (ii) of this section.
    (i) Each natural gas-driven intermittent vent process controller 
must not emit to the atmosphere during idle periods.
    (ii) You must monitor each natural gas-driven intermittent vent 
process controller to ensure that it is not emitting to the atmosphere 
during idle periods, as specified in paragraphs (b)(2)(ii)(A) through 
(C) of this section.
    (A) Monitoring must be conducted at the same frequency as specified 
for fugitive emissions components affected facilities located at the 
same type of site, as specified in Sec.  60.5397b(g).
    (B) You must include the monitoring of each natural gas-driven 
intermittent vent process controller in the monitoring plan required in 
Sec.  60.5397b(b).
    (C) When monitoring identifies emissions to the atmosphere from a 
natural gas-driven intermittent vent controller during idle periods, 
you must take corrective action by repairing or replacing the natural 
gas-driven intermittent vent process controller within 5 calendar days 
of the date the emissions to the atmosphere were detected. After the 
repair or replacement of a natural gas-driven intermittent vent process 
controller, you must re-survey the natural gas-driven intermittent vent 
process controller within five days to verify that it is not venting 
emissions during idle periods.
    (3) You must reduce methane and VOC emissions from all controllers 
in the process controller affected facility by 95.0 percent. You must 
route emissions through a closed vent system to a control device that 
meets the conditions specified in Sec.  60.5412b.
    (c) If you route process controller emissions to a process or a 
control device, you must route the process controller affected facility 
emissions through a closed vent system that meets

[[Page 17060]]

the requirements of Sec.  60.5411b(a) and (c).
    (d) You must demonstrate initial compliance with standards that 
apply to process controller affected facilities as required by Sec.  
60.5410b(f).
    (e) You must demonstrate continuous compliance with standards that 
apply to process controller affected facilities as required by Sec.  
60.5415b(h).
    (f) You must perform the reporting as required by Sec.  
60.5420b(b)(1), (7), and (11) through (13), as applicable, and the 
recordkeeping as required by Sec.  60.5420b(c)(6), (8), and (10) 
through (13), as applicable.


Sec.  60.5393b   What GHG and VOC standards apply to pump affected 
facilities?

    Each pump affected facility must comply with the GHG and VOC 
standards in this section.
    (a) For each pump affected facility meeting the criteria specified 
in paragraphs (a)(1) or (2) of this section, you must design and 
operate the pump affected facility with zero methane and VOC emissions 
to the atmosphere. If you comply by routing the pump affected facility 
emissions to a process, the emissions must be routed to the process 
through a closed vent system.
    (1) The pump affected facility is located at a site that has access 
to electrical power.
    (2) The pump affected facility is located at a site that does not 
have access to electrical power and has three or more natural gas-
driven diaphragm pumps.
    (b)(1) For each pump affected facility located at a site that does 
not have access to electrical power and that also has fewer than three 
natural gas-driven diaphragm pumps, you must comply with paragraph 
(b)(2) or (3) of this section, except as provided in paragraphs (b)(4) 
through (8) of this section.
    (2) Emissions from the pump affected facility must be routed 
through a closed vent system to a process if a vapor recovery unit is 
onsite.
    (3) If a vapor recovery unit is not onsite, you must reduce methane 
and VOC emissions from the pump affected facility by 95.0 percent. You 
must route affected pump facility emissions through a closed vent 
system to a control device meeting the conditions specified in Sec.  
60.5412b.
    (4) You are not required to install an emissions control device or 
a vapor recovery unit, if such a unit is necessary to enable emissions 
to be routed to a process, solely for the purpose of complying with the 
requirements of paragraph (b)(2) or (3) of this section. If no control 
device capable of achieving a 95.0 percent emissions reduction and no 
vapor recovery unit is present on site, you must comply with paragraph 
(b)(5) or (6) of this section, as applicable. For the purposes of this 
section, boilers and process heaters are not considered to be control 
devices.
    (5) If an emissions control device is on site but is unable to 
achieve a 95.0 percent emissions reduction, you must route the pump 
affected facility emissions through a closed vent system to that 
control device. You must certify that there is no vapor recovery unit 
on site and that there is no control device capable of achieving a 95.0 
percent emissions reduction on site.
    (6) If there is no vapor recovery unit on site and no emission 
control device is on site, you must certify that there is no vapor 
recovery unit or emissions control device on site. If you subsequently 
install a control device or vapor recovery unit, you must meet the 
requirements of paragraphs (b)(6)(i) and (ii) of this section.
    (i) You must be in compliance with the requirements of paragraphs 
(b)(1) through (3) of this section, as applicable, within 30 days of 
startup of the control device or vapor recovery unit.
    (ii) You must maintain the records in Sec.  60.5420b(c)(15)(ii) and 
(v), as applicable. You are no longer required to maintain the records 
in Sec.  60.5420b(c)(15)(vi).
    (7) If an owner or operator complying with paragraph (b)(1) of this 
section determines, through an engineering assessment, that routing the 
pump affected facility emissions to a control device or to a process is 
technically infeasible, the requirements specified in paragraphs 
(b)(7)(i) through (iii) of this section must be met.
    (i) The owner or operator must conduct the assessment of technical 
infeasibility in accordance with the criteria in paragraph (b)(7)(ii) 
of this section and have it certified by either a qualified 
professional engineer or an in-house engineer with expertise on the 
design and operation of the pump affected facility and the control 
device or processes at the site in accordance with paragraph 
(b)(7)(iii) of this section.
    (ii) The assessment of technical infeasibility to route emissions 
from the pump affected facility to an existing control device or 
process must include, but is not limited to, safety considerations, 
distance from the control device or process, pressure losses and 
differentials in the closed vent system, and the ability of the control 
device or process to handle the pump affected facility emissions which 
are routed to them. The assessment of technical infeasibility must be 
prepared under the direction or supervision of the qualified 
professional engineer or in-house engineer who signs the certification 
in accordance with paragraph (b)(7)(iii) of this section.
    (iii) The following certification, signed and dated by the 
qualified professional engineer or in-house engineer, must state: ``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 Sec.  60.5393b(b)(5)(ii). Based on my professional 
knowledge and experience, and inquiry of personnel involved in the 
assessment, the certification submitted herein is true, accurate, and 
complete.''
    (8) If the pump affected facility emissions are routed to a control 
device or process and the control device or process is subsequently 
removed from the location or is no longer available, such that there is 
no option to route to a control device or process, you are no longer 
required to be in compliance with the requirements of paragraphs (b)(2) 
or (3) of this section, and instead must comply with paragraph (b)(6) 
of this section.
    (c) If you use a control device or route to a process to reduce 
emissions, you must route the pump affected facility emissions through 
a closed vent system that meets the requirements of Sec.  60.5411b(a) 
and (c).
    (d) You must demonstrate initial compliance with standards that 
apply to pump affected facilities as required by Sec.  60.5410b(g).
    (e) You must demonstrate continuous compliance with the standards 
that apply to pump affected facilities as required by Sec.  
60.5415b(e).
    (f) You must perform the reporting as required by Sec.  
60.5420b(b)(1), (10), and (11) through (13), as applicable; and the 
recordkeeping as required by Sec.  60.5420b(c)(8), (10) through (13), 
and (15), as applicable.


Sec.  60.5395b   What GHG and VOC standards apply to storage vessel 
affected facilities?

    Each storage vessel affected facility must comply with the GHG and 
VOC standards in this section, except as provided in paragraph (e) of 
this section.
    (a) General requirements. You must comply with the requirements of 
paragraphs (a)(1) and (2) of this section. After 12 consecutive months 
of compliance with paragraph (a)(2) of this section, you may continue 
to comply with paragraph (a)(2) of this section, or you may comply with 
paragraph (a)(3) of this section, if applicable. If you

[[Page 17061]]

choose to meet the requirements of paragraph (a)(3) of this section, 
you are not required to comply with the requirements of paragraph 
(a)(2) of this section except as provided in paragraphs (a)(3)(i) and 
(ii) of this section.
    (1) Determine the potential for methane and VOC emissions in 
accordance with Sec.  60.5365b(e)(2).
    (2) Reduce methane and VOC emissions by 95.0 percent.
    (3) Maintain the uncontrolled actual VOC emissions at less than 4 
tpy and the actual methane emissions at less than 14 tpy from the 
storage vessel affected facility without considering control. Prior to 
using the uncontrolled actual VOC and methane emission rates for 
compliance purposes, you must demonstrate that the uncontrolled actual 
VOC emissions have remained less than 4 tpy and the uncontrolled actual 
methane emissions have remained less than 14 tpy as determined monthly 
for 12 consecutive months. After such demonstration, you must determine 
the uncontrolled actual rolling 12-month determination VOC and methane 
emissions rates each month. The uncontrolled actual VOC and methane 
emissions must be calculated using a generally accepted model or 
calculation methodology which account for flashing, working and 
breathing losses, and the calculations must be based on the actual 
average throughput, temperature, and separator pressure for the month. 
You may no longer comply with this paragraph and must instead comply 
with paragraph (a)(2) of this section if your storage vessel affected 
facility meets the conditions specified in paragraphs (a)(3)(i) or (ii) 
of this section.
    (i) If a well feeding the storage vessel affected facility 
undergoes fracturing or refracturing, you must comply with paragraph 
(a)(2) of this section as soon as liquids from the well following 
fracturing or refracturing are routed to the storage vessel affected 
facility.
    (ii) If the rolling 12-month emissions determination required in 
this section indicates that VOC emissions increase to 4 tpy or greater 
or the methane emissions increase to 14 tpy or greater from your 
storage vessel affected facility and the increase is not associated 
with fracturing or refracturing of a well feeding the storage vessel 
affected facility, you must comply with paragraph (a)(2) of this 
section within 30 days of the monthly determination.
    (b) Control requirements. (1) Except as required in paragraph 
(b)(2) of this section, if you use a control device to reduce methane 
and VOC emissions from your storage vessel affected facility, you must 
meet all of the design and operational criteria specified in paragraphs 
(b)(1)(i) through (iii) of this section.
    (i) Each storage vessel in the tank battery must be equipped with a 
cover that meets the requirements of Sec.  60.5411b(b);
    (ii) The tank battery must be equipped with one or more closed vent 
system that meets the requirements of Sec.  60.5411b(a) and (c); and
    (iii) The vapors collected in paragraphs (b)(1)(ii) of this section 
must be routed to a control device that meets the conditions specified 
in Sec.  60.5412b. As an alternative to routing the closed vent system 
to a control device, you may route the closed vent system to a process.
    (2) For storage vessel affected facilities that do not have 
flashing emissions and that are not located at well sites or 
centralized production facilities, you may use a floating roof to 
reduce emissions. If you use a floating roof to reduce emissions, you 
must meet the requirements of Sec.  60.112b(a)(1) or (2) and the 
relevant monitoring, inspection, recordkeeping, and reporting 
requirements in subpart Kb of this part. You must submit a statement 
that you are complying with Sec.  60.112b(a)(1) or (2) with the initial 
annual report specified in Sec.  60.5420b(b)(1) and (8).
    (c) Requirements for storage vessel affected facilities that are 
removed from service or returned to service. If you remove a storage 
vessel affected facility from service or remove a portion of a storage 
vessel affected facility from service, you must comply with the 
applicable paragraphs (c)(1) through (4) of this section. A storage 
vessel is not an affected facility under this subpart for the period 
that it is removed from service.
    (1) For a storage vessel affected facility to be removed from 
service, you must comply with the requirements of paragraphs (c)(1)(i) 
and (ii) of this section.
    (i) You must completely empty and degas each storage vessel, such 
that each storage vessel no longer contains crude oil, condensate, 
produced water or intermediate hydrocarbon liquids. A storage vessel 
where liquid is left on walls, as bottom clingage or in pools due to 
floor irregularity is considered to be completely empty.
    (ii) You must submit a notification as required in Sec.  
60.5420b(b)(6)(viii) in your next annual report, identifying each 
storage vessel affected facility removed from service during the 
reporting period and the date of its removal from service.
    (2) For a portion of a storage vessel affected facility to be 
removed from service, you must comply with the requirements of 
paragraphs (c)(2)(i) through (iv) of this section.
    (i) You must completely empty and degas the storage vessel(s), such 
that the storage vessel(s) no longer contains crude oil, condensate, 
produced water or intermediate hydrocarbon liquids. A storage vessel 
where liquid is left on walls, as bottom clingage or in pools due to 
floor irregularity is considered to be completely empty.
    (ii) You must disconnect the storage vessel(s) from the tank 
battery by isolating the storage vessel(s) from the tank battery such 
that the storage vessel(s) is no longer manifolded to the tank battery 
by liquid or vapor transfer.
    (iii) You must submit a notification as required in Sec.  
60.5420b(b)(8)(viii) in your next annual report, identifying each 
storage vessel removed from service during the reporting period, the 
impacted storage vessel affected facility, and the date of its removal 
from service.
    (iv) The remaining storage vessel(s) in the tank battery remain a 
storage vessel affected facility and must continue to comply with the 
applicable requirements of paragraphs (a) and (b) of this section.
    (3) If a storage vessel identified in paragraph (c)(1)(ii) or 
(c)(2)(iii) of this section is returned to service, you must determine 
its affected facility status as provided in Sec.  60.5365b(e)(6).
    (4) For each storage vessel affected facility or portion of a 
storage vessel affected facility returned to service during the 
reporting period, you must submit a notification in your next annual 
report as required in Sec.  60.5420b(b)(8)(ix), identifying each 
storage vessel affected facility or portion of a storage vessel 
affected facility and the date of its return to service.
    (d) Compliance, notification, recordkeeping, and reporting. You 
must comply with paragraphs (d)(1) through (3) of this section.
    (1) You must demonstrate initial compliance with standards as 
required by Sec.  60.5410b(j).
    (2) You must demonstrate continuous compliance with standards as 
required by Sec.  60.5415b(i).
    (3) You must perform the required reporting as required by Sec.  
60.5420b(b)(1) and (8) and (b)(11) through (13), as applicable; and the 
recordkeeping as required by Sec.  60.5420b(c)(7) and (c)(8) through 
(13), as applicable.
    (e) Exemptions. This subpart does not apply to storage vessels 
subject to and controlled in accordance with the requirements for 
storage vessels in subpart Kb of this part, and 40 CFR part 63, 
subparts G, CC, HH, or WW.

[[Page 17062]]

Sec.  60.5397b   What GHG and VOC standards apply to fugitive emissions 
components affected facilities?

    This section applies to fugitive emissions components affected 
facilities. You must comply with the requirements of paragraphs (a) 
through (l) of this section to reduce fugitive emissions of methane and 
VOC. The requirements of this section are independent of the cover and 
closed vent system requirements of Sec.  60.5411b.
    (a) General requirements. You must monitor all fugitive emissions 
components affected facilities in accordance with paragraphs (b) 
through (g) of this section. You must repair all sources of fugitive 
emissions in accordance with paragraph (h) of this section. You must 
demonstrate initial compliance in accordance with paragraph (i) of this 
section. You must keep records in accordance with paragraph (j) of this 
section and report in accordance with paragraph (k) of this section. 
You must meet the requirements for well closures in accordance with 
paragraph (l) of this section.
    (b) Develop fugitive emissions monitoring plan. You must develop a 
fugitive emissions monitoring plan that covers all fugitive emissions 
components affected facilities within each company-defined area in 
accordance with paragraphs (c) and (d) of this section.
    (c) Elements of fugitive emissions monitoring plan. Your fugitive 
emissions monitoring plan must include the elements specified in 
paragraphs (c)(1) through (8) of this section, at a minimum.
    (1) Frequency for conducting surveys. Surveys must be conducted at 
least as frequently as required by paragraphs (f) and (g) of this 
section.
    (2) Technique for determining fugitive emissions (i.e., AVO or 
other detection methods, Method 21 of appendix A-7 to this part, and/or 
OGI and meeting the requirements of paragraphs (c)(7)(i) through (vii) 
of this section).
    (3) Manufacturer and model number of fugitive emissions detection 
equipment to be used, if applicable.
    (4) Procedures and timeframes for identifying and repairing 
fugitive emissions components from which fugitive emissions are 
detected, including timeframes for fugitive emission components that 
are unsafe to repair. Your repair schedule must meet the requirements 
of paragraph (h) of this section at a minimum.
    (5) Procedures and timeframes for verifying fugitive emission 
component repairs.
    (6) Records that will be kept and the length of time records will 
be kept.
    (7) If you are using OGI, your plan must also include the elements 
specified in paragraphs (c)(7)(i) through (vii) of this section.
    (i) Verification that your OGI equipment meets the specifications 
of paragraphs (c)(7)(i)(A) and (B) of this section. This verification 
is an initial verification, and may either be performed by the 
facility, by the manufacturer, or by a third party. For the purposes of 
complying with the fugitive emissions monitoring program with OGI, 
fugitive emissions are defined as any visible emissions observed using 
OGI.
    (A) Your OGI equipment must be capable of imaging gases in the 
spectral range for the compound of highest concentration in the 
potential fugitive emissions.
    (B) Your OGI equipment must be capable of imaging a gas that is 
half methane, half propane at a concentration of 10,000 ppm at a flow 
rate of <=60 g/hr from a quarter inch diameter orifice.
    (ii) Procedure for a daily verification check.
    (iii) Procedure for determining the operator's maximum viewing 
distance from the equipment and how the operator will ensure that this 
distance is maintained.
    (iv) Procedure for determining maximum wind speed during which 
monitoring can be performed and how the operator will ensure monitoring 
occurs only at wind speeds below this threshold.
    (v) Procedures for conducting surveys, including the items 
specified in paragraphs (c)(7)(v)(A) through (C) of this section.
    (A) How the operator will ensure an adequate thermal background is 
present in order to view potential fugitive emissions.
    (B) How the operator will deal with adverse monitoring conditions, 
such as wind.
    (C) How the operator will deal with interferences (e.g., steam).
    (vi) Training and experience needed prior to performing surveys.
    (vii) Procedures for calibration and maintenance. At a minimum, 
procedures must comply with those recommended by the manufacturer.
    (8) If you are using Method 21 of appendix A-7 to this part, your 
plan must also include the elements specified in paragraphs (c)(8)(i) 
through (iv) of this section. For the purposes of complying with the 
fugitive emissions monitoring program using Method 21 of appendix A-7 
to this part a fugitive emission is defined as an instrument reading of 
500 ppmv or greater.
    (i) Verification that your monitoring equipment meets the 
requirements specified in Section 6.0 of Method 21 of appendix A-7 to 
this part. For purposes of instrument capability, the fugitive 
emissions definition shall be 500 ppmv or greater methane using a FID-
based instrument. If you wish to use an analyzer other than an FID-
based instrument, you must develop a site-specific fugitive emission 
definition that would be equivalent to 500 ppmv methane using a FID-
based instrument (e.g., 10.6 eV PID with a specified isobutylene 
concentration as the fugitive emission definition would provide 
equivalent response to your compound of interest).
    (ii) Procedures for conducting surveys. At a minimum, the 
procedures shall ensure that the surveys comply with the relevant 
sections of Method 21 of appendix A-7 to this part, including Section 
8.3.1.
    (iii) Procedures for calibration. The instrument must be calibrated 
before use each day of its use by the procedures specified in Method 21 
of appendix A-7 to this part. At a minimum, you must also conduct 
precision tests at the interval specified in Method 21 of appendix A-7 
to this part, Section 8.1.2, and a calibration drift assessment at the 
end of each monitoring day. The calibration drift assessment must be 
conducted as specified in paragraph (c)(8)(iii)(A) of this section. 
Corrective action for drift assessments is specified in paragraphs 
(c)(8)(iii)(B) and (C) of this section.
    (A) Check the instrument using the same calibration gas that was 
used to calibrate the instrument before use. Follow the procedures 
specified in Method 21 of appendix A-7 to this part, Section 10.1, 
except do not adjust the meter readout to correspond to the calibration 
gas value. If multiple scales are used, record the instrument reading 
for each scale used. Divide the arithmetic difference of the initial 
and post-test calibration response by the corresponding calibration gas 
value for each scale and multiply by 100 to express the calibration 
drift as a percentage.
    (B) If a calibration drift assessment shows a negative drift of 
more than 10 percent, then all equipment with instrument readings 
between the fugitive emission definition multiplied by (100 minus the 
percent of negative drift) divided by 100 and the fugitive emission 
definition that was monitored since the last calibration must be re-
monitored.

[[Page 17063]]

    (C) If any calibration drift assessment shows a positive drift of 
more than 10 percent from the initial calibration value, then, at the 
owner/operator's discretion, all equipment with instrument readings 
above the fugitive emission definition and below the fugitive emission 
definition multiplied by (100 plus the percent of positive drift) 
divided by 100 monitored since the last calibration may be re-
monitored.
    (iv) Procedures for monitoring yard piping (other than buried yard 
piping). At a minimum, place the probe inlet at the surface of the yard 
piping and run the probe down the length of the piping. Connection 
points on the piping must be monitored following the procedures 
specified in Method 21 of appendix A-7 to this part.
    (d) Additional elements of fugitive emissions monitoring plan. Each 
fugitive emissions monitoring plan must include the elements specified 
in paragraphs (d)(1) through (3) of this section, at a minimum, as 
applicable.
    (1) If you are using OGI, your plan must include procedures to 
ensure that all fugitive emissions components, except buried yard 
piping and associated components (e.g., connectors), are monitored 
during each survey. Example procedures include, but are not limited to, 
a sitemap with an observation path, a written narrative of where the 
fugitive emissions components are located and how they will be 
monitored, or an inventory of fugitive emissions components.
    (2) If you are using Method 21 of appendix A-7 to this part, your 
plan must include a list of fugitive emissions components to be 
monitored and method for determining the location of fugitive emissions 
components to be monitored in the field (e.g., tagging, identification 
on a process and instrumentation diagram, etc.). Your fugitive 
emissions monitoring plan must include the written plan developed for 
all of the fugitive emissions components designated as difficult-to-
monitor in accordance with paragraph (g)(2) of this section, and the 
written plan for fugitive emissions components designated as unsafe-to-
monitor in accordance with paragraph (g)(3) of this section.
    (e) Monitoring of fugitive emissions components. Each fugitive 
emissions component, except buried yard piping and associated 
components (e.g., connectors), shall be observed or monitored for 
fugitive emissions during each monitoring survey.
    (f) Initial monitoring survey. You must conduct initial monitoring 
surveys according to the requirements specified in paragraphs (f)(1) 
through (4) of this section.
    (1) At single wellhead only sites and small sites, you must conduct 
an initial monitoring survey using audible, visual, and olfactory 
(AVO), or any other detection methods (e.g., OGI), within 90 days of 
the startup of production, for each fugitive emissions components 
affected facility or by June 6, 2024 whichever date is later.
    (2) For multi-wellhead only well sites, well sites or centralized 
production facilities that contain the major production and processing 
equipment specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of 
this section, and compressor station sites, you must conduct an initial 
monitoring survey using OGI or Method 21 of appendix A-7 to this part 
within 90 days of the startup of production, for each fugitive 
emissions components affected facility or by June 6, 2024 whichever 
date is later.
    (3) For a modified or reconstructed fugitive emissions components 
affected facility, the initial monitoring survey must be conducted 
within 90 days of the startup of production for each fugitive emissions 
components affected facility after the modification or reconstruction 
or by June 6, 2024, whichever date is later.
    (4) Notwithstanding the deadlines specified in paragraphs (f)(1) 
through (3) of this section, for each fugitive emissions components 
affected facility located on the Alaskan North Slope that starts up 
production between September and March, you must conduct an initial 
monitoring survey within 6 months of the startup of production for a 
new well site, within 6 months of the first day of production after a 
modification of the fugitive emissions components affected facility, or 
by the following June 30, whichever date is latest.
    (g) Monitoring frequency. A monitoring survey of each fugitive 
emissions components affected facility must be performed as specified 
in paragraph (g)(1) of this section, with the exceptions noted in 
paragraphs (g)(2) through (4) of this section. Monitoring for fugitive 
emissions components affected facilities located at well sites and 
centralized production facilities that have wells located onsite must 
continue at the specified frequencies in paragraphs (g)(1)(i), (ii), 
(iii), (iv) and (vi) of this section until the well closure 
requirements of paragraph (l) of this section are completed.
    (1) A monitoring survey of the fugitive emissions components 
affected facilities must be conducted using the methods and at the 
frequencies specified in paragraphs (g)(1)(i) through (vi) of this 
section.
    (i) A monitoring survey of the fugitive emissions component 
affected facilities located at single wellhead only well sites must be 
conducted at least quarterly using AVO, or any other detection method, 
after the initial survey except as specified in paragraph (g)(1)(vi) of 
this section. Any indications of fugitive emissions using these methods 
are considered fugitive emissions that must be repaired in accordance 
with paragraph (h) of this section.
    (ii) A monitoring survey of the fugitive emissions component 
affected facilities located at small well sites must be conducted at 
least quarterly using AVO, or any other detection method, after the 
initial survey except as specified in paragraph (g)(1)(vi) of this 
section. Any indications of fugitive emissions using these methods are 
considered fugitive emissions that must be repaired in accordance with 
paragraph (h) of this section. At small well sites with an uncontrolled 
storage vessel, a visual inspection of all thief hatches and other 
openings on the storage vessel that are fugitive emissions components 
must be conducted in conjunction with the monitoring survey to ensure 
that they are kept closed and sealed at all times except during times 
of adding or removing material, inspecting or sampling material, or 
during required maintenance operations. If evidence of a deviation from 
this requirement is found, you must take corrective action. At small 
well sites with a separator, a visual inspection of all separator dump 
valves to ensure the dump valve is free of debris and not stuck in an 
open position must be conducted in conjunction with the monitoring 
survey. Any dump valve not operating as designed must be repaired.
    (iii) A monitoring survey of the fugitive emissions components 
affected facilities located at multi-wellhead only well sites must be 
conducted in accordance with paragraphs (g)(1)(iii)(A) and (B) of this 
section, except as specified in paragraph (g)(1)(vi) of this section.
    (A) A monitoring survey must be conducted at least quarterly using 
AVO, or any other detection method, after the initial survey. Any 
indications of fugitive emissions using these methods are considered 
fugitive emissions that must be repaired in accordance with paragraph 
(h) of this section.
    (B) A monitoring survey must be conducted at least semiannually 
using OGI or Method 21 of appendix A-7 to this part after the initial 
survey. Consecutive semiannual surveys must

[[Page 17064]]

be conducted at least 4 months apart and no more than 7 months apart.
    (iv) A monitoring survey of the fugitive emissions components 
affected facilities located at well sites or centralized production 
facilities that contain the major production and processing equipment 
specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) must be 
conducted at the frequencies in paragraphs (g)(1)(iv)(E) and (F) of 
this section, except as specified in paragraph (g)(1)(vi) of this 
section.
    (A) One or more controlled storage vessels or tank batteries.
    (B) One or more control devices.
    (C) One or more natural gas-driven process controllers or pumps.
    (D) Two or more pieces of major production and processing equipment 
not specified in paragraphs (g)(1)(iv)(A) through (C) of this section.
    (E) A monitoring survey must be conducted at least bimonthly using 
AVO, or any other detection method, after the initial survey. Any 
indications of fugitive emissions using these methods are considered 
fugitive emissions that must be repaired in accordance with paragraph 
(h) of this section. A visual inspection of all thief hatches and other 
openings on storage vessels (or tank batteries) that are fugitive 
emissions components must be conducted in conjunction with the 
monitoring survey to ensure that they are kept closed and sealed at all 
times except during times of adding or removing material, inspecting or 
sampling material, or during required maintenance operations. If 
evidence of a deviation from this requirement is found, you must take 
corrective action. A visual inspection must be conducted of all 
separator dump valves to ensure the dump valve is free of debris and 
not stuck in an open position must be conducted in conjunction with the 
monitoring survey. Any dump valve not operating as designed must be 
repaired.
    (F) A monitoring survey must be conducted at least quarterly using 
OGI or Method 21 of appendix A-7 to this part after the initial survey. 
Consecutive quarterly monitoring surveys must be conducted at least 60 
calendar days apart.
    (v) A monitoring survey of the fugitive emissions components 
affected facility located at a compressor station must be conducted at 
the frequencies in paragraphs (g)(1)(v)(A) and (B) of this section, 
except as specified in paragraph (g)(1)(vi) of this section,
    (A) A monitoring survey must be conducted at least monthly using 
AVO, or any other detection method, after the initial survey. Any 
indications of fugitive emissions using these methods are considered 
fugitive emissions that must be repaired in accordance with paragraph 
(h) of this section.
    (B) A monitoring survey must be conducted at least quarterly using 
OGI or Method 21 of appendix A-7 to this part after the initial survey. 
Consecutive quarterly monitoring surveys must be conducted at least 60 
calendar days apart.
    (vi) A monitoring survey of the fugitive emissions components 
affected facility located on the Alaska North Slope must be conducted 
using OGI of this part or Method 21 of appendix A-7 to this part at 
least annually. Consecutive annual monitoring surveys must be conducted 
at least 9 months apart and no more than 13 months apart.
    (2) If you are using Method 21 of appendix A-7 to this part, 
fugitive emissions components that cannot be monitored without 
elevating the monitoring personnel more than 2 meters above the surface 
may be designated as difficult-to-monitor. Fugitive emissions 
components that are designated difficult-to-monitor must meet the 
specifications of paragraphs (g)(2)(i) through (iv) of this section.
    (i) A written plan must be developed for all the fugitive emissions 
components designated difficult-to-monitor. This written plan must be 
incorporated into the fugitive emissions monitoring plan required by 
paragraphs (b), (c), and (d) of this section.
    (ii) The plan must include the identification and location of each 
fugitive emissions component designated as difficult-to-monitor.
    (iii) The plan must include an explanation of why each fugitive 
emissions component designated as difficult-to-monitor is difficult-to-
monitor.
    (iv) The plan must include a schedule for monitoring the difficult-
to-monitor fugitive emissions components at least once per calendar 
year.
    (3) If you are using Method 21 of appendix A-7 to this part, 
fugitive emissions components that cannot be monitored because 
monitoring personnel would be exposed to immediate danger while 
conducting a monitoring survey may be designated as unsafe-to-monitor. 
Fugitive emissions components that are designated unsafe-to-monitor 
must meet the specifications of paragraphs (g)(3)(i) through (iv) of 
this section.
    (i) A written plan must be developed for all the fugitive emissions 
components designated unsafe-to-monitor. This written plan must be 
incorporated into the fugitive emissions monitoring plan required by 
paragraphs (b), (c), and (d) of this section.
    (ii) The plan must include the identification and location of each 
fugitive emissions component designated as unsafe-to-monitor.
    (iii) The plan must include an explanation of why each fugitive 
emissions component designated as unsafe-to-monitor is unsafe-to-
monitor.
    (iv) The plan must include a schedule for monitoring the fugitive 
emissions components designated as unsafe-to-monitor.
    (4) The requirements of paragraphs (g)(1)(iv)(F) and (g)(1)(v)(B) 
of this section are waived during a quarterly monitoring period for any 
fugitive emissions components affected facility located within an area 
that has an average calendar month temperature below 0 degrees 
Fahrenheit for two of three consecutive calendar months of a quarterly 
monitoring period. The calendar month temperature average for each 
month within the quarterly monitoring period must be determined using 
historical monthly average temperatures over the previous three years 
as reported by a National Oceanic and Atmospheric Administration source 
or other source approved by the Administrator. The requirements of 
paragraph (g)(1)(iv) and (v) of this section shall not be waived for 
two consecutive quarterly monitoring periods.
    (h) Repairs. Each identified source of fugitive emissions shall be 
repaired in accordance with paragraphs (h)(1) and (2) of this section.
    (1) A first attempt at repair shall be made in accordance with 
paragraphs (h)(1)(i) and (ii) of this section.
    (i) A first attempt at repair shall be made no later than 15 
calendar days after detection of fugitive emissions that were 
identified using AVO.
    (ii) If you are complying with paragraph (g)(1)(i) through (vi) of 
this section using OGI or Method 21 of appendix A-7 to this part, a 
first attempt at repair shall be made no later than 30 calendar days 
after detection of the fugitive emissions.
    (2) Repair shall be completed as soon as practicable, but no later 
than 15 calendar days after the first attempt at repair as required in 
paragraph (h)(1)(i) of this section, and 30 calendar days after the 
first attempt at repair as required in paragraph (h)(1)(ii) of this 
section.
    (3) Delay of repair will be allowed if the conditions in paragraphs 
(h)(3)(i) or (ii) of this section are met.
    (i) If the repair is technically infeasible, would require a vent 
blowdown, a compressor station

[[Page 17065]]

shutdown, a well shutdown or well shut-in, or would be unsafe to repair 
during operation of the unit, the repair must be completed during the 
next scheduled compressor station shutdown for maintenance, scheduled 
well shutdown, scheduled well shut-in, after a scheduled vent blowdown, 
or within 2 years of detecting the fugitive emissions, whichever is 
earliest. A vent blowdown is the opening of one or more blowdown valves 
to depressurize major production and processing equipment, other than a 
storage vessel.
    (ii) If the repair requires replacement of a fugitive emissions 
component or a part thereof, but the replacement cannot be acquired and 
installed within the repair timelines specified in paragraphs (h)(1) 
and (2) of this section due to either of the conditions specified in 
paragraph (h)(3)(ii)(A) or (B) of this section, the repair must be 
completed in accordance with paragraph (h)(3)(ii)(C) of this section 
and documented in accordance with Sec.  60.5420b(c)(14)(v)(I).
    (A) Valve assembly supplies had been sufficiently stocked but are 
depleted at the time of the required repair.
    (B) A replacement fugitive emissions component or a part thereof 
requires custom fabrication.
    (C) The required replacement must be ordered no later than 10 
calendar days after the first attempt at repair. The repair must be 
completed as soon as practicable, but no later than 30 calendar days 
after receipt of the replacement component, unless the repair requires 
a compressor station or well shutdown. If the repair requires a 
compressor station or well shutdown, the repair must be completed in 
accordance with the timeframe specified in paragraph (h)(3)(i) of this 
section.
    (4) Each identified source of fugitive emissions must be resurveyed 
to complete repair according to the requirements of paragraphs 
(h)(4)(i) through (v) of this section, to ensure that there are no 
fugitive emissions.
    (i) The operator may resurvey the fugitive emissions components to 
verify repair using either Method 21 of appendix A-7 to this part or 
OGI, except as specified in paragraph (h)(4)(v) of this section.
    (ii) For each repair that cannot be made during the monitoring 
survey when the fugitive emissions are initially found, a digital 
photograph must be taken of that component, or the component must be 
tagged during the monitoring survey when the fugitive emissions were 
initially found for identification purposes and subsequent repair. The 
digital photograph must include the date that the photograph was taken 
and must clearly identify the component by location within the site 
(e.g., the latitude and longitude of the component or by other 
descriptive landmarks visible in the picture).
    (iii) Operators that use Method 21 of appendix A-7 to this part to 
resurvey the repaired fugitive emissions components are subject to the 
resurvey provisions specified in paragraphs (h)(4)(iii)(A) and (B) of 
this section.
    (A) A fugitive emissions component is repaired when the Method 21 
instrument indicates a concentration of less than 500 ppmv above 
background or when no soap bubbles are observed when the alternative 
screening procedures specified in section 8.3.3 of Method 21 of 
appendix A-7 to this part are used.
    (B) Operators must use the Method 21 monitoring requirements 
specified in paragraph (c)(8)(ii) of this section or the alternative 
screening procedures specified in section 8.3.3 of Method 21 of 
appendix A-7 to this part.
    (iv) Operators that use OGI to resurvey the repaired fugitive 
emissions components are subject to the resurvey provisions specified 
in paragraphs (h)(4)(iv)(A) and (B) of this section.
    (A) A fugitive emissions component is repaired when the OGI 
instrument shows no indication of visible emissions.
    (B) Operators must use the OGI monitoring requirements specified in 
paragraph (c)(7) of this section.
    (v) For fugitive emissions identified using AVO detection methods, 
the operator may resurvey using those same methods, Method 21 of 
appendix A-7 to this part, or OGI. For operators that use AVO detection 
methods, a fugitive emissions component is repaired when there are no 
indications of fugitive emissions using these methods.
    (i) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to fugitive emissions components affected 
facilities as required by Sec.  60.5410b(k).
    (j) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to fugitive emissions 
components affected facilities as required by Sec.  60.5415b(l).
    (k) Reporting and recordkeeping. You must comply with the reporting 
requirements as specified in Sec.  60.5420b(b)(1) and (9), and the 
recordkeeping requirements as specified in Sec.  60.5420b(c)(16).
    (l) Well closure requirements. You must complete the requirements 
specified in paragraphs (l)(1) through (4) of this section.
    (1) You must submit a well closure plan to the Administrator within 
30 days of the cessation of production from all wells located at the 
well site as specified in Sec.  60.5420b(a)(4)(i). The well closure 
plan must include, at a minimum, the information specified in 
paragraphs (l)(1)(i) through (iii) of this section.
    (i) Description of the steps necessary to close all wells at the 
well site, including permanent plugging of all wells;
    (ii) Description of the financial requirements and disclosure of 
financial assurance to complete closure; and
    (iii) Description of the schedule for completing all activities in 
the well closure plan.
    (2) You must submit a notification as specified in Sec.  
60.5420b(a)(4)(ii) of intent to close the well site to the 
Administrator 60 days before you begin well closure activities.
    (3) You must conduct a survey of the well site using OGI, including 
each closed well, after completing all well closure activities outlined 
in the well closure plan specified in paragraph (l)(1) of this section. 
If any emissions are imaged by the OGI instrument, then you must take 
steps to eliminate those emissions and you must resurvey the source of 
emissions. You must repeat steps to eliminate emissions and resurvey 
the source of emissions until no emissions are imaged by the OGI 
instrument. You must update the well closure plan specified in 
paragraph (l)(1) of this section to include the video of the OGI survey 
demonstrating closure of all wells at the site.
    (4) You must maintain the records specified in Sec.  
60.5420b(c)(14) and submit the reports specified in Sec.  
60.5420b(b)(9).


Sec.  60.5398b   What alternative GHG and VOC standards apply to 
fugitive emissions components affected facilities and what inspection 
and monitoring requirements apply to covers and closed vent systems 
when using an alternative technology?

    This section provides alternative GHG and VOC standards for 
fugitive emissions components affected facilities in Sec.  60.5397b and 
alternative continuous inspection and monitoring requirements for 
covers and closed vent systems in Sec.  60.5416b(a)(1)(ii) and (iii), 
(2)(ii) through (iv), and (3)(iii) and (iv). If you choose to use an 
alternative standard under this section, you must submit the 
notification under paragraph (a) of this section. If you choose to 
demonstrate compliance with the alternative GHG and VOC standards 
through periodic screening, you are subject to the requirements in 
paragraph (b) of this section. If you choose to demonstrate compliance 
through a continuous monitoring system, you are

[[Page 17066]]

subject to the requirements in paragraph (c) of this section. The 
technology used for periodic screenings under paragraph (b) of this 
section or continuous monitoring under paragraph (c) of this section 
must be approved in accordance with paragraph (d) of this section.
    (a) Notification. If you choose to demonstrate compliance with the 
alternative GHG and VOC standards in either paragraph (b) or (c) of 
this section, you must notify the Administrator of adoption of the 
alternative standards in the first annual report following 
implementation of the alternative standards, as specified in Sec.  
60.5424b(a). Once you have implemented the alternative standards, you 
must continue to comply with the alternative standards.
    (b) Periodic Screening. You may choose to demonstrate compliance 
for your fugitive emissions components affected facility and compliance 
with continuous inspection and monitoring requirements for your covers 
and closed vent systems through periodic screenings using any methane 
measurement technology approved in accordance with paragraph (d) of 
this section. If you choose to demonstrate compliance using periodic 
screenings, you must comply with the requirements in paragraphs (b)(1) 
through (5) of this section and comply with the recordkeeping and 
reporting requirements in Sec.  60.5424b.
    (1) You must use one or more alternative test method(s) approved 
per paragraph (d) of this section to conduct periodic screenings.
    (i) The required frequencies for conducting periodic screenings are 
listed in tables 1 and 2 to this subpart. You must choose the 
appropriate frequency for conducting periodic screenings based on the 
minimum aggregate detection threshold of the method used to conduct the 
periodic screenings. You must also use tables 1 and 2 to this subpart 
to determine whether you must conduct an annual fugitive emissions 
survey using OGI, except as provided in paragraph (b)(1)(ii) of this 
section.
    (ii) For well sites, centralized production facilities, and 
compressor stations subject to quarterly OGI monitoring surveys in 
Sec.  60.5397b(g)(1)(iv) and/or (v), prior to March 9, 2026, if you use 
an alternative test method approved per paragraph (d) of this section 
with a minimum aggregated detection threshold less than or equal to 3 
kg/hr, in lieu of conducting periodic screening events at the frequency 
specified in paragraph (b)(1)(i) of this section, you may conduct 
periodic screening events quarterly. After March 9, 2026, you must 
conduct periodic screening events at the frequency specified in 
paragraph (b)(1)(i) of this section.
    (iii) Use of table 1 or 2 to this subpart is based on the required 
frequency for conducting monitoring surveys in Sec.  60.5397b(g)(1)(i) 
through (v).
    (iv) You may replace one or more individual periodic screening 
events required by table 1 or 2 to this subpart with an OGI survey. The 
OGI survey must be conducted according to the requirements outlined in 
Sec.  60.5397b.
    (v) If you use multiple methods to conduct periodic screenings, you 
must conduct all periodic screenings, regardless of the method used for 
the individual periodic screening event, at the frequency required for 
the alternative test method with the highest aggregate detection 
threshold (e.g., if you use methods with aggregate detection thresholds 
of 15 kg/hr, your periodic screenings must be conducted monthly). You 
must also conduct an annual OGI survey if an annual OGI survey is 
required for the alternative test method with the highest aggregate 
detection threshold.
    (2) You must develop a monitoring plan that covers the collection 
of fugitive emissions components, covers, and closed vent systems at 
each site where you will use periodic screenings to demonstrate 
compliance. You may develop a site-specific monitoring plan, or you may 
include multiple sites that you own or operate in one plan. At a 
minimum, the monitoring plan must contain the information specified in 
paragraphs (b)(2)(i) through (ix) of this section.
    (i) Identification of each site that will be monitored through 
periodic screening, including latitude and longitude coordinates of the 
site in decimal degrees to an accuracy and precision of at least four 
decimals of a degree using the North American Datum of 1983.
    (ii) Identification of the alternative test method(s) approved per 
paragraph (d) of this section that will be used for periodic screenings 
and the spatial resolution (i.e., component-level, area-level, or 
facility-level) of the technology used for each method.
    (iii) Identification of and contact information for the entities 
that will be performing the periodic screenings.
    (iv) Required frequency for conducting periodic screenings, based 
on the criteria outlined in paragraph (b)(1) of this section.
    (v) If you are required to conduct an annual OGI survey by 
paragraph (b)(1)(i) or (iii) of this section or you choose to replace 
any individual screening event with an OGI survey, your monitoring plan 
must also include the information required by Sec.  60.5397b(b).
    (vi) Procedures for conducting monitoring surveys required by 
paragraphs (b)(5)(ii)(A), (b)(5)(iii)(A), and (b)(5)(iv)(A) of this 
section. At a minimum, your monitoring plan must include the 
information required by Sec.  60.5397b(c)(2), (3), (7), and (8), and 
(d), as applicable. The provisions of Sec.  60.5397b(d)(3) do not apply 
for purposes of conducting monitoring surveys required by paragraphs 
(b)(5)(ii) through (iv) of this section.
    (vii) Procedures and timeframes for identifying and repairing 
fugitive emissions components, covers, and closed vent systems from 
which emissions are detected.
    (viii) Procedures and timeframes for verifying repairs for fugitive 
emissions components, covers, and closed vent systems.
    (ix) Records that will be kept and the length of time records will 
be kept.
    (3) You must conduct the initial screening of your site according 
to the timeframes specified in (b)(3)(i) through (v) of this section.
    (i) Within 90 days of the startup of production for each fugitive 
emissions components affected facility and storage vessel affected 
facility located at a new well site or centralized production facility.
    (ii) Within 90 days of the startup of a new compressor station for 
each fugitive emissions components affected facility and storage vessel 
affected facility located at a new compressor station.
    (iii) Within 90 days of the startup of production after 
modification for each modified fugitive emissions components affected 
facility and storage vessel affected facility at a well site or 
centralized production facility.
    (iv) Within 90 days of modification for each modified fugitive 
emissions components affected facility and storage vessel affected 
facility at a compressor station.
    (v) No later than the final date by which the next monitoring 
survey required by Sec.  60.5397b(g)(1)(i) through (v) would have been 
required to be conducted if you were previously complying with the 
requirements in Sec.  60.5397b and Sec.  60.5416b(a)(1)(ii) and (iii), 
(2)(ii) through (iv), and (3)(iii) and (iv).
    (4) If you are required to conduct an annual OGI survey by 
paragraph (b)(1)(i) or (iii) of this section, you must conduct OGI 
surveys according to the schedule in paragraphs (b)(4)(i) through (iv) 
of this section.
    (i) You must conduct the initial OGI survey no later than 12 
calendar months

[[Page 17067]]

after conducting the initial screening event in paragraph (b)(3) of 
this section.
    (ii) Each subsequent OGI survey must be conducted no later than 12 
calendar months after the previous OGI survey was conducted. Each 
identified source of fugitive emissions during the OGI survey shall be 
repaired in accordance with Sec.  60.5397b(h).
    (iii) If you replace a periodic screening event with an OGI survey 
or you are required to conduct a monitoring survey in accordance with 
paragraph (b)(5)(ii)(A) of this section prior to the date that your 
next OGI survey under paragraph (b)(4)(ii) of this section is due, the 
OGI survey conducted in lieu of the periodic screening event or the 
monitoring survey under paragraph (b)(5)(ii)(A) of this section can be 
used to fulfill the requirements of paragraph (b)(4)(ii) of this 
section. The next OGI survey is required to be conducted no later than 
12 calendar months after the date of the survey conducted under 
paragraph (b)(1)(iv) or (b)(5)(ii)(A) of this section.
    (iv) You cannot use a monitoring survey conducted under paragraph 
(b)(5)(iii)(A) or (b)(5)(iv)(A) of this section to fulfill the 
requirements of paragraph (b)(4)(ii) of this section unless the 
monitoring survey included all fugitive emission components at the 
site.
    (5) You must investigate confirmed detections of emissions from 
periodic screening events and repair each identified source of 
emissions in accordance with paragraphs (b)(5)(i) through (vii) of this 
section.
    (i) You must receive the results of the periodic screening no later 
than 5 calendar days after the screening event occurs.
    (ii) If you use an alternative test method with a facility-level 
spatial resolution to conduct a periodic screening event and the 
results of the periodic screening event indicate a confirmed detection 
of emissions from an affected facility, you must take the actions 
listed in paragraphs (b)(5)(ii)(A) through (C) of this section.
    (A) You must conduct a monitoring survey of the entire fugitive 
emissions components affected facility following the procedures in your 
monitoring plan. During the survey, you must observe each fugitive 
emissions component for fugitive emissions.
    (B) You must inspect all covers and closed vent system(s) with OGI 
or Method 21 to appendix A-7 to this part in accordance with the 
requirements in Sec.  60.5416b(b)(1) through (4), as applicable.
    (C) You must conduct a visual inspection of all covers and closed 
vent systems to identify if there are any defects, as defined in Sec.  
60.5416b(a)(1)(ii), (a)(2)(iii), or (a)(3)(i), as applicable.
    (iii) If you use an alternative test method with an area-level 
spatial resolution to conduct a periodic screening event and the 
results of the periodic screening event indicate a confirmed detection 
of emissions from an affected facility, you must take the actions 
listed in paragraphs (b)(5)(iii)(A) and (B) of this section, as 
applicable.
    (A) You must conduct a monitoring survey of all your fugitive 
emissions components located within a 4-meter radius of the location of 
the periodic screening's confirmed detection. You must follow the 
procedures in your monitoring plan when conducting the survey.
    (B) If the confirmed detection occurred in the portion of a site 
that contains a storage vessel or a closed vent system, you must 
inspect all covers and all closed vent systems that are connected to 
all storage vessels and closed vent systems that are within a 2-meter 
radius of the location of the periodic screening's confirmed detection 
(i.e., you must inspect the whole system that is connected to the 
portion of the system in the radius of the detected event, not just the 
portion of the system that falls within the radius of the detected 
event).
    (1) You must inspect the cover(s) and closed vent system(s) with 
OGI or Method 21 to appendix A-7 to this part in accordance with the 
requirements in Sec.  60.5416b(b)(1) through (4), as applicable.
    (2) You must conduct a visual inspection of the closed vent 
system(s) and cover(s) to identify if there are any defects, as defined 
in Sec.  60.5416b(a)(1)(ii), (a)(2)(iii), or (a)(3)(i), as applicable.
    (iv) If you use an alternative test method with a component-level 
spatial resolution to conduct a periodic screening event and the 
results of the periodic screening event indicate a confirmed detection 
of emissions from an affected facility, you must take the actions 
listed in paragraphs (b)(5)(iv)(A) and (B) of this section, as 
applicable.
    (A) You must conduct a monitoring survey of the all the fugitive 
emissions components located within a 1-meter radius of the location of 
the periodic screening's confirmed detection. You must follow the 
procedures in your monitoring plan when conducting the survey.
    (B) If the confirmed detection occurred in the portion of a site 
that contains a storage vessel or a closed vent system, you must 
inspect all covers and all closed vent systems that are connected to 
all storage vessels and closed vent systems that are within a 0.5-meter 
radius of the location of the periodic screening's confirmed detection 
(i.e., you must inspect the whole system that is connected to the 
portion of the system in the radius of the detected event, not just the 
portion of the system that falls within the radius of the detected 
event).
    (1) You must inspect the cover(s) and closed vent system(s) with 
OGI or Method 21 to appendix A-7 to this part in accordance with the 
requirements in Sec.  60.5416b(b)(1) through (4), as applicable.
    (2) You must conduct a visual inspection of the closed vent 
system(s) and cover(s) to identify if there are any defects, as defined 
in Sec.  60.5416b(a)(1)(ii), (a)(2)(iii), or (a)(3)(i), as applicable.
    (v) You must repair all sources of fugitive emissions in accordance 
with Sec.  60.5397b(h) and all emissions or defects of covers and 
closed vent systems in accordance with Sec.  60.5416b(b)(5), except as 
specified in this paragraph (b)(5)(v). Except as allowed by Sec.  
60.5397b(h)(3) and Sec.  60.5416b(b)(6), all repairs must be completed, 
including the resurvey verifying the repair, within 30 days of 
receiving the results of the periodic screening in paragraph (b)(5)(i) 
of this section.
    (vi) If the results of the periodic screening event in paragraph 
(b)(5)(i) of this section indicate a confirmed detection at an affected 
facility, and the ground-based monitoring survey and inspections 
required by paragraphs (b)(5)(ii) through (iv) of this section 
demonstrate the confirmed detection was caused by a failure of a 
control device used to demonstrate continuous compliance under this 
subpart, you must initiate an investigative analysis to determine the 
underlying primary and other contributing cause(s) of such failure 
within 24 hours of receiving the results of the monitoring survey and/
or inspection. As part of the investigation, you must determine if the 
control device is operating in compliance with the applicable 
requirements of Sec.  60.5415b and Sec.  60.5417b, and if not, what 
actions are necessary to bring the control device into compliance with 
those requirements as soon as possible and prevent future failures of 
the control device from the same underlying cause(s).
    (vii) If the results of the inspections required in paragraphs 
(b)(5)(ii) through (iv) of this section indicate that there is an 
emission or defect in your cover or closed vent system, you must 
perform

[[Page 17068]]

an investigative analysis to determine the underlying primary and other 
contributing cause(s) of emissions from your cover or closed vent 
system within 5 days of completing the inspection required by 
paragraphs (b)(5)(ii) through (iv) of this section. The investigative 
analysis must include a determination as to whether the system was 
operated outside of the engineering design analysis and whether updates 
are necessary for the cover or closed vent system to prevent future 
emissions from the cover and closed vent system.
    (6) You must maintain records as specified in Sec.  60.5420b(c)(4) 
through (7), (14), and (15), and Sec.  60.5424b(c).
    (7) You must submit reports as specified in Sec.  60.5424b.
    (c) Continuous monitoring. You may choose to demonstrate compliance 
for your fugitive emissions components affected facility and compliance 
with continuous inspection and monitoring requirements for your covers 
and closed vent systems through continuous monitoring using a 
technology approved in accordance with paragraph (d) of this section. 
If you choose to demonstrate compliance using continuous monitoring, 
you must comply and develop a monitoring plan consistent with the 
requirements in paragraphs (c)(1) through (9) of this section and 
comply with the recordkeeping and reporting requirements in Sec.  
60.5424b.
    (1) For the purpose of this section, continuous monitoring means 
the ability of a methane monitoring system to determine and record a 
valid methane mass emissions rate or equivalent of affected facilities 
at least once for every 12-hour block.
    (i) The detection threshold of the system must be such that it can 
detect at least 0.40 kg/hr (0.88 lb/hr) of methane.
    (ii) The health of the devices used within the continuous 
monitoring system must be confirmed for power and function at least 
twice every six-hour block.
    (iii) The continuous monitoring system must transmit all applicable 
valid data at least once every 24-hours. The continuous monitoring 
system must transmit all valid data collected, including health checks 
required in paragraph (c)(1)(ii) of this section.
    (iv) The continuous monitoring system must continuously collect 
data as specified in paragraph (c)(1) of this section, except as 
specified in paragraphs (c)(1)(iv)(A) through (D) of this section:
    (A) The rolling 12-month average operational downtime of the 
continuous monitoring system must be less than or equal to 10 percent.
    (B) Operational downtime of the continuous monitoring system is 
defined as a period of time for which any monitor fails to collect or 
transmit data as specified in paragraph (c)(1) of this section or any 
monitor is out-of-control as specified in paragraph (c)(1)(iv)(C) of 
this section.
    (C) A monitor is out-of-control if it fails ongoing quality 
assurance checks, as specified in the alternative test method approved 
under paragraph (d) of this section, or if the monitor output is 
outside of range. The beginning of the out-of-control period is defined 
as the time of the failure of the quality assurance check. The end of 
the out-of-control period is defined as the time when either the 
monitor passes a subsequent quality assurance check, or a new monitor 
is installed. The out-of-control period for a monitor outside of range 
starts at the time when the monitor first reads outside of range and 
ends when the monitor reads within range again.
    (D) The downtime for the continuous monitoring system must be 
calculated each calendar month. Once 12 months of data are available, 
at the end of each calendar month, you must calculate the 12-month 
average by averaging that month with the previous 11 calendar months. 
You must determine the rolling 12-month average by recalculating the 
12-month average at the end of each month.
    (2) You must develop a monitoring plan that covers the collection 
of fugitive emissions components, covers, and closed vent systems for 
each site where continuous monitoring will be used to demonstrate 
compliance. At a minimum, the monitoring plan must contain the 
information specified in paragraphs (c)(2)(i) through (xii) of this 
section.
    (i) Identification of each site to be monitored through continuous 
monitoring, including latitude and longitude coordinates of the site in 
decimal degrees to an accuracy and precision of at least four decimals 
of a degree using the North American Datum of 1983.
    (ii) Identification of the alternative test method(s) approved 
under paragraph (d) of this section used for the continuous monitoring, 
including the detection principle; the manufacturer, make, and model; 
instrument manual, if applicable; and the manufacturer's recommended 
maintenance schedule.
    (iii) If the continuous monitoring system is administered through a 
third-party provider, contact information where the provider can be 
reached 24 hours a day.
    (iv) Number and location of monitors. If the continuous monitoring 
system uses open path technology, you must identify the location of any 
reflectors used. These locations should be identified by latitude and 
longitude coordinates in decimal degrees to an accuracy and precision 
of at least five decimals of a degree using the North American Datum of 
1983.
    (v) Discussion of system calibration requirements, including but 
not limited to, the calibration procedures and calibration schedule for 
the detection systems and meteorology systems.
    (vi) Identification of critical components and infrastructure 
(e.g., power, data systems) and procedures for their repairs.
    (vii) Procedures for out-of-control periods.
    (viii) Procedures for establishing baseline emissions, including 
the identification of any sources with methane emissions not subject to 
this subpart. The procedures for establishing the baseline emissions 
must account for variability in the operation of the site. Operation of 
the site during the development of the baseline emissions must 
represent the site's expected annual production or throughput.
    (ix) Procedures for determining when a fugitive emissions event is 
detected by the continuous monitoring technology.
    (x) Procedures and timeframes for identifying and repairing 
fugitive emissions components, covers, and closed vent systems from 
which emissions are detected.
    (xi) Procedures and timeframes for verifying repairs for fugitive 
emissions components, covers, and closed vent systems.
    (xii) Records that will be kept and the length of time records will 
be kept.
    (3) You must install and begin conducting monitoring with your 
continuous monitoring system according to the timeframes specified in 
paragraphs (c)(3)(i) through (v) of this section.
    (i) Within 120 days of the startup of production for each fugitive 
emissions components affected facility and storage vessel affected 
facility located at a new well site or centralized production facility.
    (ii) Within 120 days of the startup of a new compressor station for 
each fugitive emissions components affected facility and storage vessel 
affected facility located at a new compressor station.
    (iii) Within 120 days of the startup of production after 
modification for each modified fugitive emissions components affected 
facility and storage vessel

[[Page 17069]]

affected facility at a well site or centralized production facility.
    (iv) Within 120 days of modification for each modified fugitive 
emissions components affected facility and storage vessel affected 
facility at a compressor station.
    (v) No later than the final date by which the next monitoring 
survey required by Sec.  60.5397b(g)(1)(i) through (v) would have been 
required to be conducted if you were previously complying with the 
requirements in Sec.  60.5397b and Sec.  60.5416b(a)(1)(ii) and (iii), 
(2)(ii) through (iv), and (3)(iii) and (iv).
    (4) You are subject to the following action-levels as specified in 
paragraphs (c)(4)(i) and (ii) of this section for any affected 
facilities located at a well site, centralized production facility, or 
compressor station.
    (i) For affected facilities located at a wellhead only well site, 
the action levels are as follows:
    (A) The 90-day rolling average action-level is 1.2 kg/hr (2.6 lb/
hr) of methane over the site-specific baseline emissions.
    (B) The 7-day rolling average action level is 15 kg/hr (34 lb/hr) 
of methane over site-specific baseline emissions.
    (ii) For affected facilities located at well sites with major 
production and processing equipment (including small well sites), 
centralized production facilities, and compressor stations, the action 
levels are as follows:
    (A) The 90-day rolling average action-level is 1.6 kg/hr (3.6 lb/
hr) of methane over the site-specific baseline emissions.
    (B) The 7-day rolling average action level is 21 kg/hr (46 lb/hr) 
of methane over the site-specific baseline emissions.
    (5) You must establish site-specific baseline emissions upon 
initial installation and activation of a continuous monitoring system. 
You must establish the baseline emissions under the conditions outlined 
in paragraphs (c)(5)(i) through (iii) of this section. You must 
determine the baseline emission rates according to paragraphs 
(c)(5)(iv) and (v) of this section. The baseline must be established 
initially and any time there is a major change to the processing 
equipment at a well site (including small well sites), centralized 
production facility, or compressor station.
    (i) Inspect all fugitive emissions components according to the 
requirements in Sec.  60.5397b and covers and closed vent systems 
according to the requirements in Sec.  60.5416b. This includes all 
fugitive emissions components, covers, and closed vent systems, 
regardless of whether they are regulated by this subpart. Repairs of 
any fugitive emissions, leaks, or defects found during the inspection 
must be completed prior to beginning the period in paragraph 
(c)(5)(iii) of this section.
    (ii) Verify control devices (e.g., flares) on all affected sources 
are operating in compliance with the applicable requirements of Sec.  
60.5415b and Sec.  60.5417b. You must ensure that all control devices 
are operating in compliance with the applicable regulations prior to 
beginning the period in paragraph (b)(5)(iii) of this section. Verify 
that all other methane emission sources (e.g., reciprocating engines) 
located at the site are operating consistent with any applicable 
regulations. You must ensure that these sources are operating in 
compliance with the applicable regulations prior to beginning the 
period in paragraph (b)(5)(iii) of this section.
    (iii) Using the alternative test method approved under paragraph 
(d) of this section, record the site-level emission rate from your 
continuous monitoring system for 30 operating days. You must minimize 
any activities that are not normal, day-to-day activities during this 
30 operating day period. Document any maintenance activities and the 
period (including the start date and time and end date and time) such 
activities occurred during the 30 operating day period.
    (iv) Determine the site-specific baseline by calculating the mean 
emission rate (kg/hr of methane) for the 30 operating day period, less 
any time periods when maintenance activities were conducted.
    (v) The site-specific baseline emission rate must be no more than 
10 times the applicable 90-day action-level defined in paragraphs 
(c)(4)(i) and (ii) of this section.
    (6) Calculate the emission rate from your site according to 
paragraphs (c)(6)(i) through (iii) of this section. Compare the 
emission rate calculated in this paragraph (c)(6) to the appropriate 
action levels in paragraph (c)(4) of this section to determine whether 
you have exceeded an action level.
    (i) Each calendar day, calculate the daily average mass emission 
rate in kg/hr of methane from your continuous monitoring system.
    (ii) Once the system has been operating for 7 calendar days, at the 
end of each calendar day calculate the 7-day average mass emission rate 
by averaging the mass emission rate from that day with the mass 
emission rate from the previous 6 calendar days. Subtract the site-
specific baseline mass emission rate from the 7-day average mass 
emission rate when comparing the mass emission rate to the applicable 
action level. Determine the 7-day rolling average by recalculating the 
7-day average each calendar day, less the site-specific baseline.
    (iii) Once the system has been operating for 90 calendar days, at 
the end of each calendar day calculate the 90-day average mass emission 
rate by averaging the mass emission rate from that day with the mass 
emission rate from the previous 89 calendar days. Subtract the site-
specific baseline emission rate from the 90-day average mass emission 
rate when comparing the mass emission rate to the applicable action 
level. Determine the 90-day rolling average by recalculating the 90-day 
average each calendar day, less the site-specific baseline.
    (7) Within 5 days of determining that either of your action levels 
in paragraph (c)(4) of this section has been exceeded, you must 
initiate an investigative analysis to determine the underlying primary 
and contributing cause(s) of such exceedance and actions to be taken to 
reduce the mass emission rate below the applicable action level.
    (i) You must complete the investigative analysis and take initial 
steps to bring the mass emission rate below the action level no later 
than 5 days after determining there is an exceedance of the action 
level in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section.
    (ii) You must complete the investigative analysis and take initial 
steps to bring the mass emission rate below the action level no later 
than 30 days after determining there is an exceedance of the action 
level in paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section.
    (8) You must develop a mass emission rate reduction plan if you 
meet any of the criteria in paragraphs (c)(8)(i) through (iii) of this 
section. The plan must describe the action(s) completed to date to 
reduce the mass emission rate below the action level, additional 
measures that you propose to employ to reduce methane emissions below 
the action level, and a schedule for completion of these measures. You 
must submit the plan to the Administrator within 60 days of initially 
determining there is an exceedance of an action level in paragraph 
(c)(4) of this section.
    (i) If, upon completion of the initial actions required under 
paragraph (c)(7) of this section, the average mass emission rate for 
the following 30-day period is not below the applicable action level in 
paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section. The beginning 
of the 30-day period starts on the calendar day following completion of 
the initial actions in paragraph (c)(7) of this section.

[[Page 17070]]

    (ii) If, upon completion of the initial actions required under 
paragraph (c)(6) of this section, the average mass emission rate for 
the following 24-hour period is not below the applicable action level 
in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section. The average 
mass emission rate will be the mass emission rate calculated according 
to paragraph (c)(6)(i) of this section for the calendar day following 
completion of the initial corrective actions in paragraph (c)(7) of 
this section.
    (iii) All actions needed to reduce the average mass emission rate 
below the action level require more than 30 days to implement.
    (9) You must maintain the records as specified in Sec.  
60.5420b(c)(4) through (c)(7), (c)(14) and (c)(15), and Sec.  
60.5424b(e). You must submit the reports as specified in Sec.  
60.5420b(b)(1), and (b)(4) through (10) and Sec.  60.5424b.
    (d) Alternative Test Method for Methane Detection Technology. Any 
alternative test method for methane detection technology used to meet 
the requirements specified in paragraphs (b) or (c) of this section or 
Sec.  60.5371b must be approved by the Administrator as specified in 
this paragraph (d). Approval of an alternative test method for methane 
detection technology will include consideration of the combination of 
the measurement technology and the standard protocol for its operation. 
Any entity meeting the requirements in paragraph (d)(2) of this section 
may submit a request for an alternative test method for methane 
detection technology. At a minimum, the request must follow the 
requirements outlined in paragraph (d)(3) of this section. Approved 
alternative test methods for methane detection technology that are 
broadly applicable will be posted on the EPA's Emission Measurement 
Center web page (https://www.epa.gov/emc/oil-and-gas-alternative-test-methods). Any owner or operator that meets the specific applicability 
for the alternative test method, as outlined in the alternative test 
method for methane detection technology, may use the alternative test 
method to comply with the requirements of paragraph (b) or (c) of this 
section, as applicable, in lieu of the requirements for fugitive 
emissions components affected facilities in Sec.  60.5397b and covers 
and closed vent systems in Sec.  60.5416b(a)(1)(ii) and (iii), 
(a)(2)(ii) through (iv), and (a)(3)(iii) and (iv). Certified third-
party notifiers may use the alternative test method to identify super-
emitter events in Sec.  60.5371b(b)(1)(ii).
    (1) A request for an alternative test method for methane detection 
technology, along with the required supporting information, must be 
submitted to the EPA through the alternative methane detection 
technology portal at https://www.epa.gov/emc/oil-and-gas-alternative-test-methods. The EPA may make all the information submitted through 
the portal available to the public without further notice to you. Do 
not use the portal to submit information you claim as confidential 
business information (CBI). If you wish to assert a CBI claim for some 
of the information in your submittal, submit the portion of the 
information claimed as CBI to the OAQPS CBI office. Clearly mark the 
information that you claim to be CBI. Information not marked as CBI may 
be authorized for public release without prior notice. Information 
marked as CBI will not be disclosed except in accordance with 
procedures set forth in 40 CFR part 2. All CBI claims must be asserted 
at the time of submission. Anything submitted using the portal cannot 
later be claimed CBI. The preferred method to receive CBI is for it to 
be transmitted electronically using email attachments, File Transfer 
Protocol, or other online file sharing services. Electronic submissions 
must be transmitted directly to the OAQPS CBI Office at the email 
address <a href="/cdn-cgi/l/email-protection#ef808e9e9f9c8c8d86af8a9f8ec1888099"><span class="__cf_email__" data-cfemail="deb1bfafaeadbdbcb79ebbaebff0b9b1a8">[email protected]</span></a> and should include clear CBI markings and be 
flagged to the attention of the Leader, Measurement Technology Group. 
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 <a href="/cdn-cgi/l/email-protection#57383626272434353e1732273679303821"><span class="__cf_email__" data-cfemail="fc939d8d8c8f9f9e95bc998c9dd29b938a">[email protected]</span></a> to 
request a file transfer link. If you cannot transmit the file 
electronically, you may send CBI information through the postal service 
to the following address: U.S. EPA, Attn: OAQPS Document Control 
Officer and Measurement Technology Group Leader, Mail Drop: C404-02, 
109 T.W. Alexander Drive, P.O. Box 12055, RTP, North Carolina 27711. 
The mailed CBI material should be double wrapped and clearly marked. 
Any CBI markings should not show through the outer envelope.
    (i) The Administrator will complete an initial review for 
completeness within 90 days of receipt and notify the submitter of the 
results of the review.
    (ii) If the entity submitting the request does not meet the 
requirements in paragraph (d)(2) of this section or the request does 
not contain the information in paragraph (d)(3) of this section, the 
submitter will be notified. The submitter may choose to revise the 
information and submit a new request for an alternative test method.
    (iii) Within 270 days of receipt of an alternative test method 
request that was determined to be complete, the Administrator will 
determine whether the requested alternative test method is adequate for 
indicating compliance with the requirements for monitoring fugitive 
emissions components affected facilities in Sec.  60.5397b and 
continuous inspection and monitoring of covers and closed vent systems 
in Sec.  60.5416b and/or for identifying super-emitter events in Sec.  
60.5371b. The Administrator will issue either an approval or 
disapproval in writing to the submitter. Approvals may be considered 
site-specific or more broadly applicable. Broadly applicable 
alternative test methods and approval letters will be posted at https://www.epa.gov/emc/oil-and-gas-approved-alternative-test-methods-approvals. If the Administrator fails to provide the submitter a 
decision on approval or disapproval within 270 days, the alternative 
test method will be given conditional approval status and posted on 
this same web page. If the Administrator finds any deficiencies in the 
request and disapproves the request in writing, the owner or operator 
may choose to revise the information and submit a new request for an 
alternative test method.
    (iv) If the Administrator finds reasonable grounds to dispute the 
results obtained by any alternative test method for the purposes of 
demonstrating compliance with a relevant standard, the Administrator 
may require you to demonstrate compliance according to Sec.  60.5397b 
for fugitive emissions components affected facilities and Sec.  
60.5416b for covers and closed vent systems.
    (2) Any entity may submit an alternative test method for 
consideration, so long as you meet the requirements in paragraphs 
(d)(2)(i) through (iv) of this section.
    (i) An entity is limited to any individual or organization located 
in or that has representation in the United States.
    (ii) If an entity is not considered an owner or operator of an 
affected facility regulated under this subpart or subpart OOOOa of this 
part or is not the owner or operator of a designated facility regulated 
under subpart OOOOc of this part, the provisions of paragraphs 
(d)(2)(ii)(A) and (B) of this section apply.
    (A) The entity must directly represent the provider of the 
measurement system using advanced methane detection technology.
    (B) The measurement system must have been applied to methane 
measurements or monitoring in the oil

[[Page 17071]]

and gas sector either domestically or internationally.
    (iii) The underlying technology or technologies must be readily 
available for use, meaning that the measurement system using these 
technologies has either been:
    (A) Sold, leased, or licensed, or offered for sale, lease, or 
license to the general public or;
    (B) Developed by an owner or operator for internal use and/or use 
by external partners.
    (iv) The entity must be able to provide and submit to the 
Administrator the information required in paragraph (d)(3) of this 
section.
    (3) The request must contain the information specified in 
paragraphs (d)(3)(i) through (vii) of this section.
    (i) The submitter's name, mailing address, phone number and email 
address.
    (ii) The desired applicability of the technology (i.e., site-
specific, basin-specific, or broadly applicable across the sector, 
super-emitter detection).
    (iii) Description of the measurement technology, including the 
physical components, the scientific theory, and the known limitations. 
At a minimum, this description must contain the information in 
paragraphs (d)(3)(iii)(A) through (D) of this section.
    (A) Description of scientific theory and appropriate references 
outlining the underlying g technology (e.g., reference material, 
literature review).
    (B) Description of the physical instrumentation.
    (C) Type of measurement and application (e.g., remote or in-situ 
measurements, mobile, airborne).
    (D) Known limitation of the technology, including application 
limitations and weather limitations.
    (iv) Description of how the measurement technology is converted to 
a methane mass emission rate (i.e., kg/hr of methane) or equivalent. At 
a minimum this description must contain the information in paragraphs 
(d)(3)(iv)(A) through (F) of this section.
    (A) Detailed workflow and description covering all steps and 
processes from measurement technology signal output to final, validated 
mass emission rate or equivalent. These workflows must cover the 
material in paragraph (d)(3)(v) of this section and put all technical 
components into context. The workflow must also cover the technology 
from data collection to generation of the final product and identify 
any raw data processing procedures; identification of whether 
processing steps are manual or automated, and when and what quality 
assurance checks are made to the data, including raw data, processed 
data, and output data.
    (B) Description of how any meteorological data used are collected 
or sourced, including a description how the data are used.
    (C) Description of any model(s) (e.g., AERMOD) used, including how 
inputs are determined or derived.
    (D) All calculations used, including the defined variables for any 
of these calculations and a description of their purposes.
    (E) Descriptions of a-priori methods and datasets used, including 
source and version numbers when applicable.
    (F) Description of algorithms/machine learning procedures used in 
the data processing, if applicable.
    (v) Description of how all data collected and generated by the 
measurement system are handled and stored. At a minimum this 
description must contain the information in paragraphs (d)(3)(v)(A) 
through (C) of this section.
    (A) How the data, including metadata, are collected, maintained, 
and stored.
    (B) A description of how raw data streams are processed and 
manipulated, including how the resultant data processing is documented 
and how version controlled is maintained.
    (C) A description of what data streams are provided to the end-user 
of the data and how the data are delivered to the end-user.
    (vi) Supporting information verifying that the technology meets the 
aggregate detection threshold(s) defined in paragraphs (b) and/or (c) 
of this section or in Sec.  60.5371b, including supporting data to 
demonstrate the aggregate detection threshold of the measurement 
technology as applied in the field and if applicable, how probability 
of detection is determined. For the purpose of this subpart the average 
aggregate detection threshold is the average of all site-level 
detection thresholds from a single deployment (e.g., a singular flight 
that surveys multiple well sites, centralized production facility, and/
or compressor stations) of a technology, unless this technology is to 
be applied to Sec.  60.5371b. When the technology is applied to Sec.  
60.5371b, then the aggregate detection threshold is the average of all 
site-level detection thresholds from a single deployment in the same 
basin and field. At a minimum, you provide the information identified 
in paragraphs (d)(3)(vi)(A) through (D) of this section.
    (A) Published reports (e.g., scientific papers) produced by either 
the submitting entity or an outside entity evaluating the submitted 
measurement technology that has been independently evaluated. The 
published reports must identify either a site-level or aggregate 
detection threshold and be accompanied with sufficient supporting data 
to evaluate whether the performance metrics of the alternative testing 
procedures in paragraph (d)(3)(vi)(C) of this section are adequate and 
the data was collected consistent with those alternative testing 
procedures. The supporting data may be included in the published report 
or may be submitted separately.
    (B) Standard operating procedures including safety considerations, 
measurement limitations, personnel qualification/responsibilities, 
equipment and supplies, data and record management, and quality 
assurance/quality control (i.e., initial and ongoing calibration 
procedures, data quality indicators, and data quality objectives).
    (C) Detailed description of the alternative testing procedure(s), 
preferably in the format described in Guideline Document 45 on the 
Emission Measurement Center's website (available at https://www.epa.gov/sites/default/files/2020-08/documents/gd-045.pdf). The 
detailed description must address all key elements of the requested 
method(s) and must include objectives to ensure the detection 
threshold(s) required in paragraph (d)(3)(vi) of this section are 
maintained, including procedures for verifying the detection threshold 
and/or or probability of detection is maintained under field 
conditions.
    (D) Any documents provided to end-users of the data generated by 
the measurement system, including but not limited to client products, 
manuals, and frequently asked questions documents.
    (vii) If the technology will be used to monitor the collection of 
fugitive emissions components, covers, and closed vent systems at a 
well site, centralized production facility, or compressor station, you 
must submit supporting information verifying the spatial resolution of 
technology, as defined in paragraphs (d)(3)(vii)(A) through (C) of this 
section. This supporting information must be in the form of a published 
reports (e.g., scientific papers) produced by either the submitting 
entity or an outside entity evaluating the submitted measurement 
technology that has been independently evaluated. The report must 
include sufficient supporting data to evaluate whether the performance 
metrics of the alternative testing procedures in paragraph 
(d)(3)(vi)(C) of this section are adequate and the data was collected 
consistent with those alternative testing procedures.

[[Page 17072]]

    (A) Facility-level spatial resolution means a technology with the 
ability to identify emissions within the boundary of a well site, 
centralized production facility, or compressor station.
    (B) Area-level spatial resolution means a technology with the 
ability to identify emissions within a radius of 2 meters of the 
emission source.
    (C) Component-level spatial resolution means a technology with the 
ability to identify emissions within a radius of 0.5 meter of the 
emission source.


Sec.  60.5399b   What are the alternative means of emission limitations 
for GHG and VOC emissions from well completions, liquids unloading 
operations, centrifugal compressors, reciprocating compressors, 
fugitive emissions components, and process unit equipment affected 
facilities; and what are the alternative fugitive emissions standards 
based on State, local, and Tribal programs?

    This section provides procedures for the submittal and approval of 
alternative means of emission limitation for GHG and VOC based on work 
practices for well completions, liquids unloading operations, 
centrifugal compressors, reciprocating compressors, fugitive emissions 
components and process unit equipment affected facilities. This section 
also provides procedures for the submittal and approval of alternative 
fugitive emissions standards based on programs under state, local, or 
Tribal authorities for the fugitive emissions components affected 
facility. Paragraphs (a) through (d) of this section outline the 
procedure for submittal and approval of alternative means of emission 
limitation for methane and VOC. Paragraphs (e) through (i) of this 
section outline the procedure for submittal and approval of alternative 
fugitive emissions standards. The requirements for a monitoring plan 
specified in Sec.  60.5397b(c) and (d) apply to the alternative 
fugitive emissions standards in this section.
    (a) Alternative means of emission limitation. If, in the 
Administrator's judgment, an alternative means of emission limitation 
will achieve a reduction in methane and VOC emissions at least 
equivalent to the reduction in methane and VOC emissions achieved under 
Sec.  60.5375b, Sec.  60.5376b, Sec.  60.5380b, Sec.  60.5385b, Sec.  
60.5397b, Sec.  60.5400b, or Sec.  60.5401b, the Administrator will 
publish, in the Federal Register, a notice permitting the use of that 
alternative means for the purpose of compliance with Sec.  60.5375b, 
Sec.  60.5376b, Sec.  60.5380b, Sec.  60.5385b, Sec.  60.5397b, Sec.  
60.5400b, or Sec.  60.5401b. The authority to approve an alternative 
means of emission limitation is retained by the Administrator and shall 
not be delegated to States under section 111(c) of the CAA.
    (b) Notice. Any notice under paragraph (a) of this section must be 
published only after notice and an opportunity for a public hearing.
    (c) Evaluation guidelines. Determination of equivalence to the 
design, equipment, work practice, or operational requirements of this 
section will be evaluated by the following guidelines:
    (1) The applicant must provide information that is sufficient for 
demonstrating the alternative means of emission limitation achieves 
emission reductions that are at least equivalent to the emission 
reductions that would be achieved by complying with the relevant 
standards. At a minimum, the application must include the following 
information:
    (i) Details of the specific equipment or components that would be 
included in the alternative.
    (ii) A description of the alternative work practice, including, as 
appropriate, the monitoring method, monitoring instrument or 
measurement technology, and the data quality indicators for precision 
and bias.
    (iii) The method detection limit of the technology, technique, or 
process and a description of the procedures used to determine the 
method detection limit. At a minimum, the applicant must collect, 
verify, and submit field data encompassing seasonal variations to 
support the determination of the method detection limit. The field data 
may be supplemented with modeling analyses, controlled test site data, 
or other documentation.
    (iv) Any initial and ongoing quality assurance/quality control 
measures necessary for maintaining the technology, technique, or 
process, and the timeframes for conducting such measures.
    (v) Frequency of measurements. For continuous monitoring 
techniques, the minimum data availability.
    (vi) Any restrictions for using the technology, technique, or 
process.
    (vii) Initial and continuous compliance procedures, including 
recordkeeping and reporting, if the compliance procedures are different 
than those specified in this subpart.
    (2) For each technology, technique, or process for which a 
determination of equivalency is requested, the application must provide 
a demonstration that the emission reduction achieved by the alternative 
means of emission limitation is at least equivalent to the emission 
reduction that would be achieved by complying with the relevant 
standards in this subpart.
    (d) Approval of alternative means of emission limitation. Any 
alternative means of emission limitations approved under this section 
shall constitute a required work practice, equipment, design, or 
operational standard within the meaning of section 111(h)(1) of the 
CAA.
    (e) Alternative fugitive emissions standards. If, in the 
Administrator's judgment, an alternative fugitive emissions standard 
will achieve a reduction in methane and VOC emissions at least 
equivalent to the reductions achieved under Sec.  60.5397b, the 
Administrator will publish, in the Federal Register, a notice 
permitting use of the alternative fugitive emissions standard for the 
purpose of compliance with Sec.  60.5397b. The authority to approve 
alternative fugitive emissions standards is retained by the 
Administrator and shall not be delegated to States under section 111(c) 
of the CAA.
    (f) Notice. Any notice under paragraph (e) of this section will be 
published only after notice and an opportunity for public hearing.
    (g) Evaluation guidelines. Determination of alternative fugitive 
emissions standards to the design, equipment, work practice, or 
operational requirements of Sec.  60.5397b will be evaluated by the 
following guidelines:
    (1) The monitoring instrument, including the monitoring procedure;
    (2) The monitoring frequency;
    (3) The fugitive emissions definition;
    (4) The repair requirements; and
    (5) The recordkeeping and reporting requirements.
    (h) Approval of alternative fugitive emissions standard. Any 
alternative fugitive emissions standard approved under this section 
shall:
    (1) Constitute a required design, equipment, work practice, or 
operational standard within the meaning of section 111(h)(1) of the 
CAA; and
    (2) Be made available for use by any owner or operator in meeting 
the relevant standards and requirements established for affected 
facilities under Sec.  60.5397b.
    (i) Notification. (1) An owner or operator must notify the 
Administrator of adoption of the alternative fugitive emissions 
standards within the first annual report following implementation of 
the alternative fugitive emissions standard, as specified in Sec.  
60.5420b(a)(3).
    (2) An owner or operator implementing one of the alternative

[[Page 17073]]

fugitive emissions standards must submit the reports specified in Sec.  
60.5420b(b)(9)(iii). An owner or operator must also maintain the 
records specified by the specific alternative fugitive emissions 
standard for a period of at least 5 years.


Sec.  60.5400b   What GHG and VOC standards apply to process unit 
equipment affected facilities?

    This section applies to process unit equipment affected facilities 
located at an onshore natural gas processing plant. You must comply 
with the requirements of paragraphs (a) through (l) of this section to 
reduce methane and VOC emissions from equipment leaks, except as 
provided in Sec.  60.5402b. As an alternative to the standards in this 
section, you may comply with the requirements in Sec.  60.5401b.
    (a) General standards. You must comply with the requirements in 
paragraphs (b) through (d) of this section for each pump in light 
liquid service, pressure relief device in gas/vapor service, valve in 
gas/vapor or light liquid service, and connector in gas/vapor or light 
liquid service, as applicable. You must comply with the requirements in 
paragraph (e) of this section for each open-ended valve or line. You 
must comply with the requirements in paragraph (f) of this section for 
each closed vent system and control device used to comply with 
equipment leak provisions in this section. You must comply with 
paragraph (g) of this section for each pump, valve, and connector in 
heavy liquid service and pressure relief device in light liquid or 
heavy liquid service. You must make repairs as specified in paragraph 
(h) of this section. You must demonstrate initial compliance with the 
standards as specified in paragraph (i) of this section. You must 
demonstrate continuous compliance with the standards as specified in 
paragraph (j) of this section. You must perform the reporting as 
specified in paragraph (k) of this section. You must perform the 
recordkeeping as required in paragraph (l) of this section.
    (1) You may apply to the Administrator for permission to use an 
alternative means of emission limitation that achieves a reduction in 
emissions of methane and VOC at least equivalent to that achieved by 
the controls required in this subpart according to the requirements of 
Sec.  60.5399b.
    (2) 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 methane and VOC content of a gaseous stream 
must be below detection limits using Method 18 of appendix A-6 to this 
part. Alternatively, if the piece of equipment is in wet gas service, 
you may choose to determine the methane and VOC content of the stream 
is below the detection limit of the methods described in ASTM E168-
16(R2023), E169-16(R2022), or E260-96 (all incorporated by reference, 
see Sec.  60.17).
    (b) Monitoring surveys. You must monitor for leaks using OGI in 
accordance with appendix K of this part, unless otherwise specified in 
paragraphs (c) or (d) of this section.
    (1) Monitoring surveys must be conducted bimonthly.
    (2) Any emissions observed using OGI are defined as a leak.
    (c) Additional requirements for pumps in light liquid service. In 
addition to the requirements in paragraph (b), you must conduct weekly 
visual inspections of all pumps in light liquid service for indications 
of liquids dripping from the pump seal, except as specified in 
paragraphs (c)(3) and (4) of this section. If there are indications of 
liquids dripping from the pump seal, you must follow the procedure 
specified in either paragraph (c)(1) or (2) of this section.
    (1) Monitor the pump within 5 calendar days using the methods 
specified in Sec.  60.5403b. A leak is detected if any emissions are 
observed using OGI or if an instrument reading of 2,000 ppmv or greater 
is provided using Method 21 of appendix A-7 to this part.
    (2) Designate the visual indications of liquids dripping as a leak 
and repair the leak as specified in paragraph (h) of this section.
    (3) If any pump is equipped with a closed vent system capable of 
capturing and transporting any leakage from the seal or seals to a 
process, fuel gas system, or a control device that complies with the 
requirements of paragraph (f) of this section, it is exempt from the 
weekly inspection requirements in paragraph (c) of this section.
    (4) Any pump that is located within the boundary of an unmanned 
plant site is exempt from the weekly visual inspection requirements in 
paragraph (c) of this section, provided that each pump is visually 
inspected as often as practicable and at least bimonthly.
    (d) Additional requirements for pressure relief devices in gas/
vapor service. In addition to the requirements in paragraph (b) of this 
section, you must monitor each pressure relief device as specified in 
paragraph (d)(1) of this section, except as specified in paragraphs 
(d)(2) and (3) of this section.
    (1) You must monitor each pressure relief device within 5 calendar 
days after each pressure release to detect leaks using the methods 
specified in Sec.  60.5403b. A leak is detected if any emissions are 
observed using OGI or if an instrument reading of 500 ppmv or greater 
is provided using Method 21 of appendix A-7 to this part.
    (2) Any pressure relief device that is located in a 
nonfractionating plant that is monitored only by non-plant personnel 
may be monitored after a pressure release the next time the monitoring 
personnel are onsite or within 30 calendar days after a pressure 
release, whichever is sooner, instead of within 5 calendar days as 
specified in paragraph (d)(1) of this section. No pressure relief 
device described in this paragraph may be allowed to operate for more 
than 30 calendar days after a pressure release without monitoring.
    (3) Any pressure relief device that is routed to a process or fuel 
gas system or equipped with a closed vent system capable of capturing 
and transporting leakage through the pressure relief device to a 
control device as described in paragraph (f) of this section is exempt 
from the requirements of paragraph (d)(1) of this section.
    (e) Open-ended valves or lines. Each open-ended valve or line must 
be equipped with a cap, blind flange, plug, or a second valve, except 
as provided in paragraphs (e)(4) and (5) of this section. The cap, 
blind flange, plug, or second valve must seal the open end of the valve 
or line at all times except during operations requiring process fluid 
flow through the open-ended valve or line.
    (1) If evidence of a leak is found at any time by AVO, or any other 
detection method, a leak is detected.
    (2) Each open-ended valve or line equipped with a second valve must 
be operated in a manner such that the valve on the process fluid end is 
closed before the second valve is closed.
    (3) When a double block-and-bleed system is being used, the bleed 
valve or line may remain open during operations that require venting 
the line between the block valves but shall remain closed at all other 
times.
    (4) Open-ended valves or lines in an emergency shutdown system 
which are designed to open automatically in the event of a process 
upset are exempt from the requirements of this section.
    (5) Open-ended valves or lines containing materials which would 
autocatalytically polymerize or would present an explosion, serious 
overpressure, or other safety hazard if capped or equipped with a 
double

[[Page 17074]]

block-and-bleed system as specified in paragraphs (e) introductory 
text, (e)(2), and (3) of this section are exempt from the requirements 
of this section.
    (f) Closed vent systems and control devices. Closed vent systems 
used to comply with the equipment leak provisions of this section must 
comply with the requirements in Sec. Sec.  60.5411b and 60.5416b. 
Control devices used to comply with the equipment leak provisions of 
this section must comply with the requirements in Sec. Sec.  60.5412b, 
60.5415b(f), and 60.5417b.
    (g) Pumps, valves, and connectors in heavy liquid service and 
pressure relief devices in light liquid or heavy liquid service. If 
evidence of a potential leak is found at any time by AVO, or any other 
detection method, a leak is detected and must be repaired in accordance 
with paragraph (h) of this section.
    (h) Repair requirements. When a leak is detected, you must comply 
with the requirements of paragraphs (h)(1) through (5) of this section, 
except as provided in paragraph (h)(6) of this section.
    (1) A weatherproof and readily visible identification tag, marked 
with the equipment identification number, must be attached to the 
leaking equipment. The identification tag on equipment may be removed 
after it has been repaired.
    (2) A first attempt at repair must be made as soon as practicable, 
but no later than 5 calendar days after the leak is detected. A first 
attempt at repair is not required if the leak is detected using OGI and 
the equipment identified as leaking would require elevating the repair 
personnel more than 2 meters above a support surface.
    (i) First attempts at repair for pumps in light liquid or heavy 
liquid service include, but are not limited to, the practices described 
in paragraphs (h)(2)(i)(A) and (B) of this section, where practicable.
    (A) Tightening the packing gland nuts.
    (B) Ensuring that the seal flush is operating at design pressure 
and temperature.
    (ii) For each valve where a leak is detected, you must comply with 
(h)(2)(ii)(A), (B) or (C), and (D) of this section.
    (A) Repack the existing valve with a low-e packing.
    (B) Replace the existing valve with a low-e valve; or
    (C) Perform a drill and tap repair with a low-e injectable packing.
    (D) An owner or operator is not required to utilize a low-e valve 
or low-e packing to replace or repack a valve if the owner or operator 
demonstrates that a low-e valve or low-e packing is not technically 
feasible. Low-e valve or low-e packing that is not suitable for its 
intended use is considered to be technically infeasible. Factors that 
may be considered in determining technical infeasibility include: 
retrofit requirements for installation (e.g., re-piping or space 
limitation), commercial unavailability for valve type, or certain 
instrumentation assemblies.
    (3) Repair of leaking equipment must be completed within 15 
calendar days after detection of each leak, except as provided in 
paragraphs (h)(4), (5) and (6) of this section.
    (4) If the repair for visual indications of liquids dripping for 
pumps in light liquid service can be made by eliminating visual 
indications of liquids dripping, you must make the repair within 5 
calendar days of detection.
    (5) If the repair for AVO or other indication of a leak for open-
ended valves or lines; pumps, valves, or connectors in heavy liquid 
service; or pressure relief devices in light liquid or heavy liquid 
service can be made by eliminating the AVO, or other indication of a 
potential leak, you must make the repair within 5 calendar days of 
detection.
    (6) Delay of repair of equipment for which leaks have been detected 
is allowed if repair within 15 days is technically infeasible without a 
process unit shutdown or as specified in paragraphs (h)(6)(i) through 
(v) of this section. Repair of this equipment shall occur before the 
end of the next process unit shutdown. Monitoring to verify repair must 
occur within 15 days after startup of the process unit.
    (i) Delay of repair of equipment is allowed for equipment which is 
isolated from the process, and which does not have the potential to 
emit methane or VOC.
    (ii) Delay of repair for valves and connectors is allowed if the 
conditions in paragraphs (h)(6)(ii)(A) and (B) of this section are met.
    (A) You must demonstrate that emissions of purged material 
resulting from immediate repair are greater than the fugitive emissions 
likely to result from delay of repair, and
    (B) When repair procedures are conducted, the purged material is 
collected and destroyed or recovered in a control device complying with 
paragraph (f) of this section.
    (iii) Delay of repair for pumps is allowed if the conditions in 
paragraphs (h)(6)(iii)(A) and (B) of this section are met.
    (A) Repair requires the use of a dual mechanical seal system that 
includes a barrier fluid system, and
    (B) Repair is completed as soon as practicable, but not later than 
6 months after the leak was detected.
    (iv) If delay of repair is required to repack or replace the valve, 
you may use delay of repair. Delay of repair beyond a process unit 
shutdown is allowed for a valve, if valve assembly replacement is 
necessary during the process unit shutdown, valve assembly supplies 
have been depleted, and valve assembly supplies had been sufficiently 
stocked before the supplies were depleted. Delay of repair beyond the 
next process unit shutdown will not be allowed unless the next process 
unit shutdown occurs sooner than 6 months after the first process unit 
shutdown.
    (v) When delay of repair is allowed for a leaking pump, valve, or 
connector that remains in service, the pump, valve, or connector may be 
considered to be repaired and no longer subject to delay of repair 
requirements if two consecutive bimonthly monitoring results show no 
leak remains.
    (i) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to equipment leaks at onshore natural gas 
processing plants as required by Sec.  60.5410b(h).
    (j) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to equipment leaks at onshore 
natural gas processing plants as required by Sec.  60.5415b(j).
    (k) Reporting. You must perform the reporting requirements as 
specified in Sec.  60.5420b(b)(1) and (11) and Sec.  60.5422b.
    (l) Recordkeeping. You must perform the recordkeeping requirements 
as specified in Sec.  60.5420b(c)(8), (10), and (12) and Sec.  
60.5421b.


Sec.  60.5401b   What are the alternative GHG and VOC standards for 
process unit equipment affected facilities?

    This section provides alternative standards for process unit 
equipment affected facilities located at an onshore natural gas 
processing plant. You may choose to comply with the standards in this 
section instead of the requirements in Sec.  60.5400b. For purposes of 
the alternative standards provided in this section, you must comply 
with the requirements of paragraphs (a) through (m) of this section to 
reduce methane and VOC emissions from equipment leaks, except as 
provided in Sec.  60.5402b.
    (a) General standards. You must comply with the requirements in 
paragraphs (b) of this section for each pump in light liquid service. 
You must comply with the requirements of paragraph (c) of this section 
for each pressure relief device in gas/vapor

[[Page 17075]]

service. You must comply with the requirements in paragraph (d) of this 
section for each open-ended valve or line. You must comply with the 
requirements in paragraph (e) of this section for each closed vent 
system and control device used to comply with equipment leak provisions 
in this section. You must comply with paragraph (f) of this section for 
each valve in gas/vapor or light liquid service. You must comply with 
paragraph (g) of this section for each pump, valve, and connector in 
heavy liquid service and pressure relief device in light liquid or 
heavy liquid service. You must comply with paragraph (h) of this 
section for each connector in gas/vapor and light liquid service. You 
must make repairs as specified in paragraph (i) of this section. You 
must demonstrate initial compliance with the standards as specified in 
paragraph (j) of this section. You must demonstrate continuous 
compliance with the standards as specified in paragraph (k) of this 
section. You must perform the reporting requirements as specified in 
paragraph (l) of this section. You must perform the recordkeeping 
requirements as required in paragraph (m) of this section.
    (1) You may apply to the Administrator for permission to use an 
alternative means of emission limitation that achieves a reduction in 
emissions of methane and VOC at least equivalent to that achieved by 
the controls required in this subpart according to the requirements of 
Sec.  60.5399b.
    (2) 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 methane and VOC content of a gaseous stream 
must be below detection limits using Method 18 of appendix A-6 to this 
part. Alternatively, if the piece of equipment is in wet gas service, 
you may choose to determine the methane and VOC content of the stream 
is below the detection limit of the methods described in ASTM E168-
16(R2023), E169-16(R2022), or E260-96 (all incorporated by reference, 
see Sec.  60.17).
    (b) Pumps in light liquid service. You must monitor each pump in 
light liquid service monthly to detect leaks by the methods specified 
in Sec.  60.5403b, except as provided in paragraphs (b)(2) through (4) 
of this section. A leak is defined as an instrument reading of 2,000 
ppmv or greater. A pump that begins operation in light liquid service 
after the initial startup date for the process unit must be monitored 
for the first time within 30 days after the end of its startup period, 
except for a pump that replaces a leaking pump and except as provided 
in paragraphs (b)(2) through (4) of this section.
    (1) In addition to the requirements in paragraph (b) of this 
section, you must conduct weekly visual inspections of all pumps in 
light liquid service for indications of liquids dripping from the pump 
seal. If there are indications of liquids dripping from the pump seal, 
you must follow the procedure specified in either paragraph (b)(1)(i) 
or (ii) of this section.
    (i) Monitor the pump within 5 days using the methods specified in 
Sec.  60.5403b. A leak is defined as an instrument reading of 2,000 
ppmv or greater.
    (ii) Designate the visual indications of liquids dripping as a 
leak, and repair the leak as specified in paragraph (i) of this 
section.
    (2) Each pump equipped with a dual mechanical seal system that 
includes a barrier fluid system is exempt from the requirements in 
paragraph (b) of this section, provided the requirements specified in 
paragraphs (b)(2)(i) through (vi) of this section are met.
    (i) Each dual mechanical seal system meets the requirements of 
paragraphs (b)(2)(i)(A), (B), or (C) of this section.
    (A) Operated with the barrier fluid at a pressure that is at all 
times greater than the pump stuffing box pressure; or
    (B) Equipped with a barrier fluid degassing reservoir that is 
routed to a process or fuel gas system or connected by a closed vent 
system to a control device that complies with the requirements of 
paragraph (e) of this section; or
    (C) Equipped with a system that purges the barrier fluid into a 
process stream with zero VOC emissions to the atmosphere.
    (ii) The barrier fluid system is in heavy liquid service or does 
not have the potential to emit methane or VOC.
    (iii) Each barrier fluid system is equipped with a sensor that will 
detect failure of the seal system, the barrier fluid system, or both.
    (iv) Each pump is checked according to the requirements in 
paragraph (b)(1) of this section.
    (v) Each sensor meets the requirements in paragraphs (b)(2)(v)(A) 
through (C) of this section.
    (A) Each sensor as described in paragraph (b)(2)(iii) of this 
section is checked daily or is equipped with an audible alarm.
    (B) You determine, based on design considerations and operating 
experience, a criterion that indicates failure of the seal system, the 
barrier fluid system, or both.
    (C) If the sensor indicates failure of the seal system, the barrier 
fluid system, or both, based on the criterion established in paragraph 
(b)(2)(v)(B) of this section, a leak is detected.
    (3) Any pump that is designated, as described in Sec.  
60.5421b(b)(12), for no detectable emissions, as indicated by an 
instrument reading of less than 500 ppmv above background, is exempt 
from the requirements of paragraphs (b) introductory text, (b)(1), and 
(2) of this section if the pump:
    (i) Has no externally actuated shaft penetrating the pump housing;
    (ii) Is demonstrated to be operating with no detectable emissions 
as indicated by an instrument reading of less than 500 ppmv above 
background as measured by the methods specified in Sec.  60.5403b; and
    (iii) Is tested for compliance with paragraph (b)(3)(ii) of this 
section initially upon designation, annually, and at other times 
requested by the Administrator.
    (4) If any pump is equipped with a closed vent system capable of 
capturing and transporting any leakage from the seal or seals to a 
process, fuel gas system, or a control device that complies with the 
requirements of paragraph (e) of this section, it is exempt from 
paragraphs (b), (b)(1) through (3) of this section, and the repair 
requirements of paragraph (i) of this section.
    (5) Any pump that is designated, as described in Sec.  
60.5421b(b)(13), as an unsafe-to-monitor pump is exempt from the 
inspection and monitoring requirements of paragraphs (b), (b)(1) and 
(b)(2)(iv) through (vi) of this section if the conditions in paragraph 
(b)(5)(i) and (ii) of this section are met.
    (i) You demonstrate that the pump is unsafe-to-monitor because 
monitoring personnel would be exposed to an immediate danger as a 
consequence of complying with paragraph (b) of this section; and
    (ii) You have a written plan that requires monitoring of the pump 
as frequently as practicable during safe-to-monitor times, but not more 
frequently than the periodic monitoring schedule otherwise applicable, 
and you repair the equipment according to the procedures in paragraph 
(i) of this section if a leak is detected.
    (6) Any pump that is located within the boundary of an unmanned 
plant site is exempt from the weekly visual inspection requirements in 
paragraph (b)(1) and (b)(2)(iv) of this section, and the daily 
requirements of paragraph (b)(2)(v) of this section, provided that

[[Page 17076]]

each pump is visually inspected as often as practicable and at least 
monthly.
    (c) Pressure relief devices in gas/vapor service. You must monitor 
each pressure relief device quarterly using the methods specified in 
Sec.  60.5403b. A leak is defined as an instrument reading of 500 ppmv 
or greater above background.
    (1) In addition to the requirements in paragraph (c) introductory 
text of this section, after each pressure release, you must monitor 
each pressure relief device within 5 calendar days after each pressure 
release to detect leaks. A leak is detected if an instrument reading of 
500 ppmv or greater is provided using the methods specified in Sec.  
60.5403b(b).
    (2) Any pressure relief device that is located in a 
nonfractionating plant that is monitored only by non-plant personnel 
may be monitored after a pressure release the next time the monitoring 
personnel are onsite or within 30 calendar days after a pressure 
release, whichever is sooner, instead of within 5 calendar days as 
specified in paragraph (c)(1) of this section.
    (3) No pressure relief device described in paragraph (c)(2) of this 
section may be allowed to operate for more than 30 calendar days after 
a pressure release without monitoring.
    (4) Any pressure relief device that is routed to a process or fuel 
gas system or equipped with a closed vent system capable of capturing 
and transporting leakage through the pressure relief device to a 
control device as described in paragraph (e) of this section is exempt 
from the requirements of paragraph (c) introductory text and (c)(1) of 
this section.
    (5) Pressure relief devices equipped with a rupture disk are exempt 
from the requirements of paragraphs (c)(1) and (2) of this section 
provided you install a new rupture disk upstream of the pressure relief 
device as soon as practicable, but no later than 5 calendar days after 
each pressure release, except as provided in paragraph (i)(4) of this 
section.
    (d) Open-ended valves or lines. Each open-ended valve or line must 
be equipped with a cap, blind flange, plug, or a second valve, except 
as provided in paragraphs (d)(4) and (5) of this section. The cap, 
blind flange, plug, or second valve must seal the open end of the valve 
or line at all times except during operations requiring process fluid 
flow through the open-ended valve or line.
    (1) If evidence of a leak is found at any time by AVO, or any other 
detection method, a leak is detected and must be repaired in accordance 
with paragraph (i) of this section. A leak is defined as an instrument 
reading of 500 ppmv or greater if Method 21 of appendix A-7 to this 
part is used.
    (2) Each open-ended valve or line equipped with a second valve must 
be operated in a manner such that the valve on the process fluid end is 
closed before the second valve is closed.
    (3) When a double block-and-bleed system is being used, the bleed 
valve or line may remain open during operations that require venting 
the line between the block valves but shall remain closed at all other 
times.
    (4) Open-ended valves or lines in an emergency shutdown system 
which are designed to open automatically in the event of a process 
upset are exempt from the requirements of paragraphs (d) introductory 
text, and (d)(1) through (3) of this section.
    (5) Open-ended valves or lines containing materials which would 
autocatalytically polymerize or would present an explosion, serious 
overpressure, or other safety hazard if capped or equipped with a 
double block-and-bleed system as specified in paragraphs (d) 
introductory text, (d)(2), and (3) of this section are exempt from the 
requirements of this section.
    (e) Closed vent systems and control devices. Closed vent systems 
used to comply with the equipment leak provisions of this section must 
comply with the requirements in Sec. Sec.  60.5411b and 60.5416b. 
Control devices used to comply with the equipment leak provisions of 
this section must comply with the requirements in Sec. Sec.  60.5412b, 
60.5415b(f), and 60.5417b.
    (f) Valves in gas/vapor and light liquid service. You must monitor 
each valve in gas/vapor and in light liquid service quarterly to detect 
leaks by the methods specified in Sec.  60.5403b, except as provided in 
paragraphs (h)(3) through (5) of this section.
    (1) A valve that begins operation in gas/vapor service or in light 
liquid service after the initial startup date for the process unit must 
be monitored for the first time within 90 days after the end of its 
startup period to ensure proper installation, except for a valve that 
replaces a leaking valve and except as provided in paragraphs (h)(3) 
through (5) of this section.
    (2) An instrument reading of 500 ppmv or greater is a leak. You 
must repair each leaking valve according to the requirements in 
paragraph (i) of this section.
    (3) Any valve that is designated, as described in Sec.  
60.5421b(b)(12), for no detectable emissions, as indicated by an 
instrument reading of less than 500 ppmv above background, is exempt 
from the requirements of paragraphs (f) of this section if the valve:
    (i) Has no externally actuating mechanism in contact with the 
process fluid;
    (ii) Is operated with emissions less than 500 ppmv above background 
as determined by the methods specified in Sec.  60.5403b; and
    (iii) Is tested for compliance with paragraph (f)(3)(ii) of this 
section initially upon designation, annually, and at other times 
requested by the Administrator.
    (4) Any valve that is designated, as described in Sec.  
60.5421b(b)(13), as an unsafe-to-monitor pump is exempt from the 
monitoring requirements of paragraph (f) introductory text of this 
section if the requirements in paragraphs (f)(4)(i) and (ii) of this 
section are met.
    (i) You demonstrate that the valve is unsafe-to-monitor because 
monitoring personnel would be exposed to an immediate danger as a 
consequence of complying with paragraph (f) of this section; and
    (ii) You have a written plan that requires monitoring of the valve 
as frequently as practicable during safe-to-monitor times, but not more 
frequently than the periodic monitoring schedule otherwise applicable, 
and you repair the equipment according to the procedures in paragraph 
(i) of this section if a leak is detected.
    (5) Any valve that is designated, as described in Sec.  
60.5421b(b)(14), as a difficult-to-monitor valve is exempt from the 
monitoring requirements of paragraph (h) of this section if the 
requirements in paragraph (f)(5)(i) through (iii) of this section are 
met.
    (i) You demonstrate that the valve cannot be monitored without 
elevating the monitoring personnel more than 2 meters above a support 
surface.
    (ii) The process unit within which the valve is located has less 
than 3.0 percent of its total number of valves designated as difficult-
to-monitor.
    (iii) You have a written plan that requires monitoring of the at 
least once per calendar year.
    (g) Pumps, valves, and connectors in heavy liquid service and 
pressure relief devices in light liquid or heavy liquid service. If 
evidence of a potential leak is found at any time by AVO, or any other 
detection method, you must comply with either paragraph (g)(1) or (2) 
of this section.
    (1) You must monitor the equipment within 5 calendar days by the 
method specified in Sec.  60.5403b and repair any leaks detected 
according to paragraph (i) of this section. An instrument reading of 
10,000 ppmv or greater is defined as a leak.

[[Page 17077]]

    (2) You must designate the AVO, or other indication of a leak as a 
leak and repair the leak according to paragraph (i) of this section.
    (h) Connectors in gas/vapor service and in light liquid service. 
You must initially monitor all connectors in the process unit for leaks 
by the later of either 12 months after the compliance date or 12 months 
after initial startup. If all connectors in the process unit have been 
monitored for leaks prior to the compliance date, no initial monitoring 
is required provided either no process changes have been made since the 
monitoring or the owner or operator can determine that the results of 
the monitoring, with or without adjustments, reliably demonstrate 
compliance despite process changes. If required to monitor because of a 
process change, you are required to monitor only those connectors 
involved in the process change.
    (1) You must monitor all connectors in gas/vapor service and in 
light liquid service annually, except as provided in Sec.  60.5399b, 
paragraph (e) of this section or paragraph (h)(2) of this section.
    (2) Any connector that is designated, as described in Sec.  
60.5421b(b)(13), as an unsafe-to-monitor connector is exempt from the 
requirements of paragraphs (h) introductory text and (h)(1) of this 
section if the requirements of paragraphs (h)(2)(i) and (ii) of this 
section are met.
    (i) You demonstrate the connector is unsafe-to-monitor because 
monitoring personnel would be exposed to an immediate danger as a 
consequence of complying with paragraphs (h) introductory text and 
(h)(1) of this section; and
    (ii) You have a written plan that requires monitoring of the 
connector as frequently as practicable during safe-to-monitor times, 
but not more frequently than the periodic monitoring schedule otherwise 
applicable, and you repair the equipment according to the procedures in 
paragraph (i) of this section if a leak is detected.
    (3) Inaccessible, ceramic, or ceramic-line connectors.
    (i) Any connector that is inaccessible or that is ceramic or 
ceramic-lined (e.g., porcelain, glass, or glass-lined), is exempt from 
the monitoring requirements of paragraphs (h) and (h)(1) of this 
section, from the leak repair requirements of paragraph (i) of this 
section, and from the recordkeeping and reporting requirements of 
Sec. Sec.  60.5421b and 60.5422b. An inaccessible connector is one that 
meets any of the specifications in paragraphs (h)(3)(i)(A) through (F) 
of this section, as applicable.
    (A) Buried.
    (B) Insulated in a manner that prevents access to the connector by 
a monitor probe.
    (C) Obstructed by equipment or piping that prevents access to the 
connector by a monitor probe.
    (D) Unable to be reached from a wheeled scissor-lift or hydraulic-
type scaffold that would allow access to connectors up to 7.6 meters 
(25 feet) above the ground.
    (E) Inaccessible because it would require elevating monitoring 
personnel more than 2 meters (7 feet) above a permanent support surface 
or would require the erection of scaffold.
    (F) Not able to be accessed at any time in a safe manner to perform 
monitoring. Unsafe access includes, but is not limited to, the use of a 
wheeled scissor-lift on unstable or uneven terrain, the use of a 
motorized man-lift basket in areas where an ignition potential exists, 
or access would require near proximity to hazards such as electrical 
lines or would risk damage to equipment.
    (ii) If any inaccessible, ceramic, or ceramic-lined connector is 
observed by AVO or other means to be leaking, the indications of a leak 
to the atmosphere by AVO or other means must be eliminated as soon as 
practicable.
    (4) Connectors which are part of an instrumentation systems and 
inaccessible, ceramic, or ceramic-lined connectors meeting the 
provisions of paragraph (h)(3) of this section, are not subject to the 
recordkeeping requirements of Sec.  60.5421b(b)(1).
    (i) Repair requirements. When a leak is detected, comply with the 
requirements of paragraphs (i)(1) through (5) of this section, except 
as provided in paragraph (i)(6) of this section.
    (1) A weatherproof and readily visible identification tag, marked 
with the equipment identification number, must be attached to the 
leaking equipment. The identification tag on the equipment may be 
removed after it has been repaired.
    (2) A first attempt at repair must be made as soon as practicable, 
but no later than 5 calendar days after the leak is detected.
    (i) First attempts at repair for pumps in light liquid or heavy 
liquid service include, but are not limited to, the practices described 
in paragraphs (i)(2)(i)(A) and (B) of this section, where practicable.
    (A) Tightening the packing gland nuts.
    (B) Ensuring that the seal flush is operating at design pressure 
and temperature.
    (ii) For each valve where a leak is detected, you must comply with 
(h)(2)(ii)(A), (B) or (C), and (D) of this section.
    (A) Repack the existing valve with a low-e packing.
    (B) Replace the existing valve with a low-e valve; or
    (C) Perform a drill and tap repair with a low-e injectable packing.
    (D) An owner or operator is not required to utilize a low-e valve 
or low-e packing to replace or repack a valve if the owner or operator 
demonstrates that a low-e valve or low-e packing is not technically 
feasible. Low-e valve or low-e packing that is not suitable for its 
intended use is considered to be technically infeasible. Factors that 
may be considered in determining technical infeasibility include: 
retrofit requirements for installation (e.g., re-piping or space 
limitation), commercial unavailability for valve type, or certain 
instrumentation assemblies.
    (3) Repair of leaking equipment must be completed within 15 
calendar days after detection of each leak, except as provided in 
paragraph (i)(4), (5), or (6) of this section.
    (4) If the repair for visual indications of liquids dripping for 
pumps in light liquid service can be made by eliminating visual 
indications of liquids dripping, you must make the repair within 5 
calendar days of detection.
    (5) If the repair for AVO or other indication of a leak for open-
ended lines or valves; pumps, valves, or connectors in heavy liquid 
service; or pressure relief devices in light liquid or heavy liquid 
service can be made by eliminating the AVO, or other indication of a 
potential leak, you must make the repair within 5 calendar days of 
detection.
    (6) Delay of repair of equipment for which leaks have been detected 
will be allowed if repair within 15 calendar days is technically 
infeasible without a process unit shutdown or as specified in 
paragraphs (i)(6)(i) through (v) of this section. Repair of this 
equipment shall occur before the end of the next process unit shutdown. 
Monitoring to verify repair must occur within 15 calendar days after 
startup of the process unit.
    (i) Delay of repair of equipment will be allowed for equipment 
which is isolated from the process, and which does not have the 
potential to emit methane or VOC.
    (ii) Delay of repair for valves and connectors will be allowed if 
the conditions in paragraphs (i)(6)(ii)(A) and (B) are met.
    (A) You demonstrate that emissions of purged material resulting 
from immediate repair are greater than the

[[Page 17078]]

fugitive emissions likely to result from delay of repair, and
    (B) When repair procedures are conducted, the purged material is 
collected and destroyed or recovered in a control device complying with 
paragraph (e) of this section.
    (iii) Delay of repair for pumps will be allowed if the conditions 
in paragraphs (i)(6)(iii)(A) and (B) are met.
    (A) Repair requires the use of a dual mechanical seal system that 
includes a barrier fluid system, and
    (B) Repair is completed as soon as practicable, but not later than 
6 months after the leak was detected.
    (iv) If delay of repair is required to repack or replace the valve, 
you may use delay of repair. Delay of repair beyond a process unit 
shutdown will be allowed for a valve, if valve assembly replacement is 
necessary during the process unit shutdown, valve assembly supplies 
have been depleted, and valve assembly supplies had been sufficiently 
stocked before the supplies were depleted. Delay of repair beyond the 
next process unit shutdown will not be allowed unless the next process 
unit shutdown occurs sooner than 6 months after the first process unit 
shutdown.
    (v) When delay of repair is allowed for a leaking pump, valve, or 
connector that remains in service, the pump, valve, or connector may be 
considered to be repaired and no longer subject to delay of repair 
requirements if two consecutive monthly monitoring results show no leak 
remains.
    (j) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to equipment leaks at onshore natural gas 
processing plants as required by Sec.  60.5410b(h).
    (k) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to equipment leaks at onshore 
natural gas processing plants as required by Sec.  60.5415b(j).
    (l) Reporting. You must perform the reporting requirements as 
specified in Sec. Sec.  60.5420b(b)(1), (b)(11), and 60.5422b.
    (m) Recordkeeping. You must perform the recordkeeping requirements 
as specified in Sec.  60.5420b(c)(8), (10), (12), and Sec.  60.5421b.


Sec.  60.5402b   What are the exceptions to the GHG and VOC standards 
for process unit equipment affected facilities?

    (a) You may comply with the following exceptions to the provisions 
of Sec. Sec.  60.5400b(a) and 60.5401b(a), as applicable.
    (b) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and 
connectors in gas/vapor service and in light liquid service that are 
located at a nonfractionating plant that does not have the design 
capacity to process 283,200 standard cubic meters per day (scmd) (10 
million standard cubic feet per day) or more of field gas may comply 
with the exceptions specified in paragraphs (b)(1) or (2) of this 
section.
    (1) You are exempt from the bimonthly OGI monitoring as required 
under Sec.  60.5400b(b).
    (2) You are exempt from the routine Method 21 of appendix A-7 
monitoring requirements of Sec.  60.5401b(b), (c), (f), and (h), if 
complying with the alternative standards of Sec.  60.5401b.
    (c) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and 
connectors in gas/vapor service and in light liquid service within a 
process unit that is located in the Alaskan North Slope are exempt from 
the monitoring requirements Sec.  60.5400b(b) and (c) and Sec.  
60.5401b(b), (c), (f) and (h).
    (d) You may use the following provisions instead of Sec.  
60.5403b(e):
    (1) Equipment is in heavy liquid service if the weight percent 
evaporated is 10 percent or less at 150 degrees Celsius (302 degrees 
Fahrenheit) as determined by ASTM D86-96 (incorporated by reference, 
see Sec.  60.17).
    (2) Equipment is in light liquid service if the weight percent 
evaporated is greater than 10 percent at 150 degrees Celsius (302 
degrees Fahrenheit) as determined by ASTM D86-96 (incorporated by 
reference, see Sec.  60.17).
    (e) Equipment that is in vacuum service, except connectors in gas/
vapor and light liquid service, is excluded from the requirements of 
Sec.  60.5400b(b) through (g), if it is identified as required in Sec.  
60.5421b(b)(15). Equipment that is in vacuum service is excluded from 
the requirements of Sec.  60.5401b(b) through (g) if it is identified 
as required in Sec.  60.5421b(b)(15).
    (f) Equipment that you designate as having the potential to emit 
methane or VOC less than 300 hr/yr is excluded from the requirements of 
Sec.  60.5400b(b) through (g) and Sec.  60.5401b(b) through (h), if it 
is identified as required in Sec.  60.5421b(b)(16) and it meets any of 
the conditions specified in paragraphs (f)(1) through (3) of this 
section.
    (1) The equipment has the potential to emit methane or VOC only 
during startup and shutdown.
    (2) The equipment has the potential to emit methane or VOC only 
during process malfunctions or other emergencies.
    (3) The equipment is backup equipment that has the potential to 
emit methane or VOC only when the primary equipment is out of service.


Sec.  60.5403b   What test methods and procedures must I use for my 
process unit equipment affected facilities?

    (a) In conducting the performance tests required in Sec.  60.8, you 
must use as reference methods and procedures the test methods in 
appendix A to this part or other methods and procedures as specified in 
this section, except as provided in Sec.  60.8(b).
    (b) You must determine compliance with the standards in Sec.  
60.5401b as follows:
    (1) Method 21 of appendix A-7 to this part shall be used to 
determine the presence of leaking sources. The instrument shall be 
calibrated before use each day of its use by the procedures specified 
in Method 21 of appendix A-7 to this part. The following calibration 
gases shall be used:
    (i) Zero air (less than 10 ppmv of hydrocarbon in air); and
    (ii) A mixture of methane or n-hexane and air at a concentration no 
more than 2,000 ppmv greater than the leak definition concentration of 
the equipment monitored. If the monitoring instrument's design allows 
for multiple calibration scales, then the lower scale shall be 
calibrated with a calibration gas that is no higher than 2,000 ppmv 
above the concentration specified as a leak, and the highest scale 
shall be calibrated with a calibration gas that is approximately or 
equal to 10,000 ppmv. If only one scale on an instrument will be used 
during monitoring, you need not calibrate the scales that will not be 
used during that day's monitoring.
    (iii) Verification that your monitoring equipment meets the 
requirements specified in Section 6.0 of Method 21 of appendix A-7 to 
this part. For purposes of instrument capability, the leak definition 
shall be 500 ppmv or greater methane using a FID-based instrument for 
valves and connectors and 2,000 ppmv methane or greater for pumps. If 
you wish to use an analyzer other than a FID-based instrument, you must 
develop a site-specific leak definition that would be equivalent to 500 
ppmv methane using a FID-based instrument (e.g., 10.6 eV PID with a 
specified isobutylene concentration as the leak definition would 
provide equivalent response to your compound of interest).
    (2) The instrument must be calibrated before use each day of its 
use by the procedures specified in Method 21 of appendix A-7 to this 
part. At minimum, you must also conduct precision tests at the interval 
specified in Method 21 of appendix A-7 to this part, Section 8.1.2, and 
a calibration drift assessment at the

[[Page 17079]]

end of each monitoring day. The calibration drift assessment must be 
conducted as specified in paragraph (b)(2)(i) of this section. 
Corrective action for drift assessments is specified in paragraphs 
(b)(2)(ii) and (iii) of this section.
    (i) Check the instrument using the same calibration gas that was 
used to calibrate the instrument before use. Follow the procedures 
specified in Method 21 of appendix A-7 to this part, Section 10.1, 
except do not adjust the meter readout to correspond to the calibration 
gas value. If multiple scales are used, record the instrument reading 
for each scale used. Divide the arithmetic difference of the initial 
and post-test calibration response by the corresponding calibration gas 
value for each scale and multiply by 100 to express the calibration 
drift as a percentage.
    (ii) If a calibration drift assessment shows a negative drift of 
more than 10 percent, then all equipment with instrument readings 
between the fugitive emission definition multiplied by (100 minus the 
percent of negative drift) divided by 100 and the fugitive emission 
definition that was monitored since the last calibration must be re-
monitored.
    (iii) If any calibration drift assessment shows a positive drift of 
more than 10 percent from the initial calibration value, then, at the 
owner/operator's discretion, all equipment with instrument readings 
above the fugitive emission definition and below the fugitive emission 
definition multiplied by (100 plus the percent of positive drift) 
divided by 100 monitored since the last calibration may be re-
monitored.
    (c) You shall determine compliance with the no detectable emission 
standards in Sec.  60.5401b(b), (c), and (f) as specified in paragraphs 
(c)(1) and (2) of this section.
    (1) The requirements of paragraph (b) of this section shall apply.
    (2) Method 21 of appendix A-7 to this part shall be used to 
determine the background level. All potential leak interfaces shall be 
traversed as close to the interface as possible. The arithmetic 
difference between the maximum concentration indicated by the 
instrument and the background level is compared with 500 ppmv for 
determining compliance.
    (d) You shall demonstrate that a piece of equipment is in light 
liquid service by showing that all of the following conditions apply:
    (1) The vapor pressure of one or more of the organic components is 
greater than 0.3 kPa at 20 [deg]C (1.2 in H<INF>2</INF>O at 68 [deg]F). 
Standard reference texts or ASTM D2879-83, -96, or -97 (all 
incorporated by reference, see Sec.  60.17) shall be used to determine 
the vapor pressures.
    (2) The total concentration of the pure organic components having a 
vapor pressure greater than 0.3 kPa at 20 [deg]C (1.2 in H<INF>2</INF>O 
at 68 [deg]F) is equal to or greater than 20 percent by weight.
    (3) The fluid is a liquid at operating conditions.
    (e) Samples used in conjunction with paragraphs (d) and (e) of this 
section shall be representative of the process fluid that is contained 
in or contacts the equipment, or the gas being combusted in the flare.


Sec.  60.5405b   What standards apply to sweetening unit affected 
facilities?

    (a) During the initial performance test required by Sec.  60.8(b), 
you must achieve at a minimum, an SO<INF>2</INF> emission reduction 
efficiency (Z<INF>i</INF>) to be determined from table 3 to this 
subpart based on the sulfur feed rate (X) and the sulfur content of the 
acid gas (Y) of the affected facility.
    (b) After demonstrating compliance with the provisions of paragraph 
(a) of this section, you must achieve at a minimum, an SO<INF>2</INF> 
emission reduction efficiency (Z<INF>c</INF>) to be determined from 
table 4 to this subpart based on the sulfur feed rate (X) and the 
sulfur content of the acid gas (Y) of the affected facility.
    (c) You must demonstrate initial compliance with the standards that 
apply to sweetening unit affected facilities as required by Sec.  
60.5410b(i).
    (d) You must demonstrate continuous compliance with the standards 
that apply to sweetening unit affected facilities as required by Sec.  
60.5415b(k).
    (e) You must perform the reporting as required by Sec.  
60.5420b(a)(1), (b)(1), and Sec.  60.5423b and the recordkeeping as 
required by Sec.  60.5423b.


Sec.  60.5406b   What test methods and procedures must I use for my 
sweetening unit affected facilities?

    (a) In conducting the performance tests required in Sec.  60.8, you 
must use the test methods in appendix A to this part or other methods 
and procedures as specified in this section, except as provided in 
Sec.  60.8(b).
    (b) During a performance test required by Sec.  60.8, you must 
determine the minimum required reduction efficiencies (Z) of 
SO<INF>2</INF> emissions as required in Sec.  60.5405b(a) and (b) as 
follows:
    (1) The average sulfur feed rate (X) must be computed as follows:
    [GRAPHIC] [TIFF OMITTED] TR08MR24.001
    
Where:

X = average sulfur feed rate, Mg/D (LT/D).
Q<INF>a</INF> = average volumetric flow rate of acid gas from 
sweetening unit, dscm/day (dscf/day).
Y = average H<INF>2</INF>S concentration in acid gas feed from 
sweetening unit, percent by volume, expressed as a decimal.
K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/Mg)).
= 1.331 x 10<SUP>-3</SUP>Mg/dscm, for metric units.
= (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long ton)).
= 3.707 x 10<SUP>-5</SUP> long ton/dscf, for English units.

    (2) You must use the continuous readings from the process flowmeter 
to determine the average volumetric flow rate (Q<INF>a</INF>) in dscm/
day (dscf/day) of the acid gas from the sweetening unit for each run.
    (3) You must use the Tutwiler procedure in Sec.  60.5408b or a 
chromatographic procedure following ASTM E260-96 (incorporated by 
reference, see Sec.  60.17) to determine the H<INF>2</INF>S 
concentration in the acid gas feed from the sweetening unit (Y). At 
least one sample per hour (at equally spaced intervals) must be taken 
during each 4-hour run. The arithmetic mean of all samples must be the 
average H<INF>2</INF>S concentration (Y) on a dry basis for the run. By 
multiplying the result from the Tutwiler procedure by 1.62 x 10\-3\, 
the units gr/100 scf are converted to volume percent.
    (4) Using the information from paragraphs (b)(1) and (3) of this 
section, tables 3 and 4 to this subpart must be used to determine the 
required initial (Z<INF>i</INF>) and continuous (Z<INF>c</INF>) 
reduction efficiencies of SO<INF>2</INF> emissions.

[[Page 17080]]

    (c) You must determine the emission reduction efficiency (R) 
achieved by the sulfur recovery technology as follows:
    (1) You must compute the emission reduction efficiency (R) achieved 
by the sulfur recovery technology for each run using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.002

    (2) You must use the level indicators or manual soundings to 
measure the liquid sulfur accumulation rate in the product storage 
vessels. You must use readings taken at the beginning and end of each 
run, the tank geometry, sulfur density at the storage temperature, and 
sample duration to determine the sulfur production rate (S) in kg/hr 
(lb/hr) for each run.
    (3) You must compute the emission rate of sulfur for each run as 
follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.003

Where:

E = emission rate of sulfur per run, kg/hr.
C<INF>e</INF> = concentration of sulfur equivalent (SO<SUP>2+</SUP> 
reduced sulfur), g/dscm (lb/dscf).
Q<INF>sd</INF> = volumetric flow rate of effluent gas, dscm/hr 
(dscf/hr).
K<INF>1</INF> = conversion factor, 1000 g/kg (7000 gr/lb).

    (4) The concentration (C<INF>e</INF>) of sulfur equivalent must be 
the sum of the SO<INF>2</INF> and TRS concentrations, after being 
converted to sulfur equivalents. For each run and each of the test 
methods specified in this paragraph (c) of this section, you must use a 
sampling time of at least 4 hours. You must use Method 1 of appendix A-
1 to this part to select the sampling site. The sampling point in the 
duct must be at the centroid of the cross-section if the area is less 
than 5 m\2\ (54 ft\2\) or at a point no closer to the walls than 1 m 
(39 in) if the cross-sectional area is 5 m\2\ or more, and the centroid 
is more than 1 m (39 in) from the wall.
    (i) You must use Method 6 or 6C of appendix A-4 to this part to 
determine the SO<INF>2</INF> concentration. You must take eight samples 
of 20 minutes each at 30-minute intervals. The arithmetic average must 
be the concentration for the run. The concentration must be multiplied 
by 0.5 x 10<SUP>-3</SUP> to convert the results to sulfur equivalent. 
In place of Method 6 of appendix A to this part, you may use ANSI/ASME 
PTC 19.10-1981, Part 10 (manual portion only) (incorporated by 
reference, see Sec.  60.17).
    (ii) You must use Method 2 of appendix A-1 to this part to 
determine the volumetric flow rate of the effluent gas. A velocity 
traverse must be conducted at the beginning and end of each run. The 
arithmetic average of the two measurements must be used to calculate 
the volumetric flow rate (Q<INF>sd</INF>) for the run. For the 
determination of the effluent gas molecular weight, a single integrated 
sample over the 4-hour period may be taken and analyzed or grab samples 
at 1-hour intervals may be taken, analyzed, and averaged.
    (iii) You must use Method 4 of appendix A-2 to this part for 
moisture content. Alternatively, you must take two samples of at least 
0.10 dscm (3.5 dscf) and 10 minutes at the beginning of the 4-hour run 
and near the end of the time period. The arithmetic average of the two 
runs must be the moisture content for the run.
    (iv) You must use Method 15 of appendix A-5 to this part to 
determine the TRS concentration from reduction-type devices or where 
the oxygen content of the effluent gas is less than 1.0 percent by 
volume. The sampling rate must be at least 3 liters/min (0.1 ft\3\/min) 
to insure minimum residence time in the sample line. You must take 
sixteen samples at 15-minute intervals. The arithmetic average of all 
the samples must be the concentration for the run. The concentration in 
ppmv reduced sulfur as sulfur must be multiplied by 1.333 x 
10<SUP>-3</SUP> to convert the results to sulfur equivalent.
    (v) You must use Method 16A of appendix A-6 to this part or ANSI/
ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by 
reference, see Sec.  60.17) to determine the reduced sulfur 
concentration from oxidation-type devices or where the oxygen content 
of the effluent gas is greater than 1.0 percent by volume. You must 
take eight samples of 20 minutes each at 30-minute intervals. The 
arithmetic average must be the concentration for the run. The 
concentration in ppm reduced sulfur as sulfur must be multiplied by 
1.333 x 10<SUP>-3</SUP> to convert the results to sulfur equivalent.
    (iv) You must use EPA Method 2 of appendix A-1 to this part to 
determine the volumetric flow rate of the effluent gas. A velocity 
traverse must be conducted at the beginning and end of each run. The 
arithmetic average of the two measurements must be used to calculate 
the volumetric flow rate (Q<INF>sd</INF>) for the run. For the 
determination of the effluent gas molecular weight, a single integrated 
sample over the 4-hour period may be taken and analyzed or grab samples 
at 1-hour intervals may be taken, analyzed, and averaged. For the 
moisture content, you must take two samples of at least 0.10 dscm (3.5 
dscf) and 10 minutes at the beginning of the 4-hour run and near the 
end of the time period. The arithmetic average of the two runs must be 
the moisture content for the run.


Sec.  60.5407b   What are the requirements for monitoring of emissions 
and operations from my sweetening unit affected facilities?

    (a) If your sweetening unit affected facility is subject to the 
provisions of Sec.  60.5405b(a) or (b) you must install, calibrate, 
maintain, and operate monitoring devices or perform measurements to 
determine the following operations information on a daily basis:
    (1) The accumulation of sulfur product over each 24-hour period. 
The monitoring method may incorporate the use of an instrument to 
measure and record the liquid sulfur production rate or may be a 
procedure for measuring and recording the sulfur liquid levels in the 
storage vessels with a level indicator or by manual soundings, with 
subsequent calculation of the sulfur production rate based on the tank 
geometry, stored sulfur density, and elapsed time between readings. The 
method must be designed to be accurate

[[Page 17081]]

within <plus-minus>2 percent of the 24-hour sulfur accumulation.
    (2) The H<INF>2</INF>S concentration in the acid gas from the 
sweetening unit for each 24-hour period. At least one sample per 24-
hour period must be collected and analyzed using the equation specified 
in Sec.  60.5406b(b)(1). The Administrator may require you to 
demonstrate that the H<INF>2</INF>S concentration obtained from one or 
more samples over a 24-hour period is within <plus-minus>20 percent of 
the average of 12 samples collected at equally spaced intervals during 
the 24-hour period. In instances where the H<INF>2</INF>S concentration 
of a single sample is not within <plus-minus>20 percent of the average 
of the 12 equally spaced samples, the Administrator may require a more 
frequent sampling schedule.
    (3) The average acid gas flow rate from the sweetening unit. You 
must install and operate a monitoring device to continuously measure 
the flow rate of acid gas. The monitoring device reading must be 
recorded at least once per hour during each 24-hour period. The average 
acid gas flow rate must be computed from the individual readings.
    (4) The sulfur feed rate (X). For each 24-hour period, you must 
compute X using the equation specified in Sec.  60.5406b(b)(1).
    (5) The required sulfur dioxide emission reduction efficiency for 
the 24-hour period. You must use the sulfur feed rate and the 
H<INF>2</INF>S concentration in the acid gas for the 24-hour period, as 
applicable, to determine the required reduction efficiency in 
accordance with the provisions of Sec.  60.5405b(b).
    (b) Where compliance is achieved through the use of an oxidation 
control system or a reduction control system followed by a continually 
operated incineration device, you must install, calibrate, maintain, 
and operate monitoring devices and continuous emission monitors as 
follows:
    (1) A continuous monitoring system to measure the total sulfur 
emission rate (E) of SO<INF>2</INF> in the gases discharged to the 
atmosphere. The SO<INF>2</INF> emission rate must be expressed in terms 
of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this 
monitoring system must be set so that the equivalent emission limit of 
Sec.  60.5405b(b) will be between 30 percent and 70 percent of the 
measurement range of the instrument system.
    (2) Except as provided in paragraph (b)(3) of this section: A 
monitoring device to measure the temperature of the gas leaving the 
combustion zone of the incinerator, if compliance with Sec.  
60.5405b(a) is achieved through the use of an oxidation control system 
or a reduction control system followed by a continually operated 
incineration device. The monitoring device must be certified by the 
manufacturer to be accurate to within <plus-minus>1 percent of the 
temperature being measured.
    (3) When performance tests are conducted under the provision of 
Sec.  60.8 to demonstrate compliance with the standards under Sec.  
60.5405b, the temperature of the gas leaving the incinerator combustion 
zone must be determined using the monitoring device. If the volumetric 
ratio of sulfur dioxide to sulfur dioxide plus total reduced sulfur 
(expressed as SO<INF>2</INF>) in the gas leaving the incinerator is 
equal to or less than 0.98, then temperature monitoring may be used to 
demonstrate that sulfur dioxide emission monitoring is sufficient to 
determine total sulfur emissions. At all times during the operation of 
the facility, you must maintain the average temperature of the gas 
leaving the combustion zone of the incinerator at or above the 
appropriate level determined during the most recent performance test to 
ensure the sulfur compound oxidation criteria are met. Operation at 
lower average temperatures may be considered by the Administrator to be 
unacceptable operation and maintenance of the affected facility. You 
may request that the minimum incinerator temperature be reestablished 
by conducting new performance tests under Sec.  60.8.
    (4) Upon promulgation of a performance specification of continuous 
monitoring systems for total reduced sulfur compounds at sulfur 
recovery plants, you may, as an alternative to paragraph (b)(2) of this 
section, install, calibrate, maintain, and operate a continuous 
emission monitoring system for total reduced sulfur compounds as 
required in paragraph (d) of this section in addition to a sulfur 
dioxide emission monitoring system. The sum of the equivalent sulfur 
mass emission rates from the two monitoring systems must be used to 
compute the total sulfur emission rate (E).
    (c) Where compliance is achieved using a reduction control system 
not followed by a continually operated incineration device, you must 
install, calibrate, maintain, and operate a continuous monitoring 
system to measure the emission rate of reduced sulfur compounds as 
SO<INF>2</INF> equivalent in the gases discharged to the atmosphere. 
The SO<INF>2</INF> equivalent compound emission rate must be expressed 
in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span 
of this monitoring system must be set so that the equivalent emission 
limit of Sec.  60.5405b(b) will be between 30 and 70 percent of the 
measurement range of the system. This requirement becomes effective 
upon promulgation of a performance specification for continuous 
monitoring systems for total reduced sulfur compounds at sulfur 
recovery plants.
    (d) For those sources required to comply with paragraph (b) or (c) 
of this section, you must calculate the average sulfur emission 
reduction efficiency achieved (R) for each 24-hour clock interval. The 
24-hour interval may begin and end at any selected clock time but must 
be consistent. You must compute the 24-hour average reduction 
efficiency (R) based on the 24-hour average sulfur production rate (S) 
and sulfur emission rate (E), using the equation in Sec.  
60.5406b(c)(1).
    (1) You must use data obtained from the sulfur production rate 
monitoring device specified in paragraph (a) of this section to 
determine S.
    (2) You must use data obtained from the sulfur emission rate 
monitoring systems specified in paragraphs (b) or (c) of this section 
to calculate a 24-hour average for the sulfur emission rate (E). The 
monitoring system must provide at least one data point in each 
successive 15-minute interval. You must use at least two data points to 
calculate each 1-hour average. You must use a minimum of 18 1-hour 
averages to compute each 24-hour average.
    (e) In lieu of complying with paragraphs (b) or (c) of this 
section, those sources with a design capacity of less than 152 Mg/D 
(150 LT/D) of H<INF>2</INF>S expressed as sulfur may calculate the 
sulfur emission reduction efficiency achieved for each 24-hour period 
by:
[GRAPHIC] [TIFF OMITTED] TR08MR24.004


[[Page 17082]]


Where:

R = The sulfur dioxide removal efficiency achieved during the 24-
hour period, percent.
K<INF>2</INF> = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071 
LT/D per lb/hr).
S = The sulfur production rate during the 24-hour period, kg/hr (lb/
hr).
X = The sulfur feed rate in the acid gas, Mg/D (LT/D).

    (f) The monitoring devices required in paragraphs (b)(1) and (3) 
and (c) of this section must be calibrated at least annually according 
to the manufacturer's specifications, as required by Sec.  60.13(b).
    (g) The continuous emission monitoring systems required in 
paragraphs (b)(1) and (3), and (c) of this section must be subject to 
the emission monitoring requirements of Sec.  60.13. For conducting the 
continuous emission monitoring system performance evaluation required 
by Sec.  60.13(c), Performance Specification 2 of appendix B to this 
part must apply, and Method 6 of appendix A-4 to this part must be used 
for systems required by paragraph (b) of this section. In place of 
Method 6 of appendix A-4 to this part, ASME PTC 19.10-1981 
(incorporated by reference, see Sec.  60.17) may be used.


Sec.  60.5408b   What is an optional procedure for measuring hydrogen 
sulfide in acid gas--Tutwiler Procedure?

    The Tutwiler procedure may be found in the Gas Engineers Handbook, 
Fuel Gas Engineering practices, The Industrial Press, 93 Worth Street, 
New York, NY, 1966, First Edition, Second Printing, page 6/25 (Docket 
A-80-20-A, Entry II-I-67).
    (a) Sampling. When an instantaneous sample is desired and 
H<INF>2</INF>S concentration is 10 grains per 1000 cubic foot or more, 
a 100 ml Tutwiler burette is used. For concentrations less than 10 
grains, a 500 ml Tutwiler burette and more dilute solutions are used. 
In principle, this method consists of titrating hydrogen sulfide in a 
gas sample directly with a standard solution of iodine.
    (b) Apparatus. (See figure 1 to this section.) A 100- or 500-ml 
capacity Tutwiler burette, with two-way glass stopcock at bottom and 
three-way stopcock at top that connect either with inlet tubulature or 
glass-stoppered cylinder, 10 ml capacity, graduated in 0.1 ml 
subdivision; rubber tubing connecting burette with leveling bottle.
    (c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 g 
iodine, and 20 to 25 g cp potassium iodide (KI) for each liter of 
solution. Dissolve KI in as little water as necessary; dissolve iodine 
in concentrated KI solution, make up to proper volume, and store in 
glass-stoppered brown glass bottle.
    (2) Standard iodine solution, 1 ml = 0.001771 g I. Transfer 33.7 ml 
of above 0.1N stock solution into a 250 ml volumetric flask; add water 
to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard 
iodine solution is equivalent to 100 grains H<INF>2</INF>S per cubic 
feet of gas.
    (3) Rub into a thin paste about one teaspoonful of wheat starch 
with a little water; pour into about a pint of boiling water; stir; let 
cool and decant off clear solution. Make fresh solution every few days.
    (d) Procedure. (Refer to figure 1 to this section.) Fill leveling 
bulb with starch solution. Raise (L), open cock (G), open (F) to (A), 
and close (F) when solutions start to run out of gas inlet. Close (G). 
Purge gas sampling line and connect with (A). Lower (L) and open (F) 
and (G). When liquid level is several ml past the 100 ml mark, close 
(G) and (F), and disconnect sampling tube. Open (G) and bring starch 
solution to 100 ml mark by raising (L); then close (G). Open (F) 
momentarily, to bring gas in burette to atmospheric pressure, and close 
(F). Open (G), bring liquid level down to 10 ml mark by lowering (L). 
Close (G), clamp rubber tubing near (E) and disconnect it from burette. 
Rinse graduated cylinder with a standard iodine solution (0.00171 g I 
per ml); fill cylinder and record reading. Introduce successive small 
amounts of iodine through (F); shake well after each addition; continue 
until a faint permanent blue color is obtained. Record reading; 
subtract from previous reading, and call difference D.
    (e) Blank testing. (Refer to figure 1 to this section.) With every 
fresh stock of starch solution perform a blank test as follows: 
Introduce fresh starch solution into burette up to 100 ml mark. Close 
(F) and (G). Lower (L) and open (G). When liquid level reaches the 10 
ml mark, close (G). With air in burette, titrate as during a test and 
up to same end point. Call ml of iodine used C. Then,
[GRAPHIC] [TIFF OMITTED] TR08MR24.044

    (f) Test sensitivity. Greater sensitivity can be attained if a 500 
ml capacity Tutwiler burette is used with a more dilute (0.001N) iodine 
solution. Concentrations less than 1.0 grains per 100 cubic foot can be 
determined in this way. Usually, the starch-iodine end point is much 
less distinct, and a blank determination of end point, with 
H<INF>2</INF>S-free gas or air, is required.
BILLING CODE 6560-50-P

[[Page 17083]]

[GRAPHIC] [TIFF OMITTED] TR08MR24.005

Figure 1 to Sec.  60.5408b. Tutwiler burette (lettered items mentioned 
in text).

BILLING CODE 6560-50-C


Sec.  60.5410b   How do I demonstrate initial compliance with the 
standards for each of my affected facilities?

    You must determine initial compliance with the standards for each 
affected facility using the requirements of paragraphs (a) through (k) 
of this section. Except as otherwise provided in this section, the 
initial compliance period begins on the date specified in Sec.  
60.5370b and ends no later than 1 year after that date. The initial 
compliance period may be less than 1 full year.
    (a) Well completion standards for well affected facilities. To 
achieve initial compliance with the GHG and VOC standards for each well 
completion operation conducted at your well affected facility as 
required by Sec.  60.5375b, you must comply with paragraphs (a)(1) 
through (4) of this section.
    (1) You must submit the notification required in Sec.  
60.5420b(a)(2).
    (2) You must submit the initial annual report for your well 
affected facility as required in Sec.  60.5420b(b)(1) and (2).
    (3) You must maintain a log of records as specified in Sec.  
60.5420b(c)(1)(i) through (iv) and (vii), as applicable, for each well 
completion operation conducted. If you meet the exemption at Sec.  
60.5375b(g) for wells with a GOR less than 300 scf per stock barrel of 
oil produced, you do not have to maintain the records in Sec.  
60.5420b(c)(1)(i) through (iv) and must maintain the record in Sec.  
60.5420b(c)(1)(vi). If you meet the exemption at Sec.  60.5375b(h) for 
a well modified in accordance with Sec.  60.5365b(a)(1)(ii) (i.e., an 
existing well is hydraulically refractured), you do not need to 
maintain the records in Sec.  60.5420b(c)(1)(i) through (iv) and must 
maintain the record in Sec.  60.5420b(c)(1)(viii).
    (4) For each well completion affected facility subject to both 
Sec.  60.5375b(a)(1) and (2), as an alternative to retaining the 
records specified in Sec.  60.5420b(c)(1)(i) through (iv), you may 
maintain records in accordance with Sec.  60.5420b(c)(1)(v).
    (b) Gas well liquids unloading standards for well affected 
facility. To demonstrate initial compliance with the GHG and VOC 
standards for each gas well liquids unloading operation conducted at 
your gas well affected facility as required by Sec.  60.5376b, you must 
comply with paragraphs (b)(1) through (4) of this section, as 
applicable.
    (1) You must submit the initial annual report for your well 
affected facility as required in Sec.  60.5420b(b)(1) and (3).

[[Page 17084]]

    (2) If you comply by using a liquids unloading technology or 
technique that does not vent to the atmosphere according to Sec.  
60.5376b(a)(1), you must maintain the records specified in Sec.  
60.5420b(c)(2)(i).
    (3) If you comply by using a liquids unloading technology or 
technique that vents to the atmosphere according to Sec.  
60.5376b(a)(2), (b) and (c), you must comply with paragraphs (b)(3)(i) 
and (ii) of this section.
    (i) Employ best management practices to minimize venting of methane 
and VOC emissions as specified in Sec.  60.5376b(c) for each gas well 
liquids unloading operation.
    (ii) Maintain the records specified in Sec.  60.5420b(c)(2)(ii).
    (4) If you comply by using Sec.  60.5376b(g), you must comply with 
paragraphs (b)(4)(i) through (vii) of this section.
    (i) Reduce methane and VOC emissions by 95.0 percent or greater and 
as demonstrated by the requirements of Sec.  60.5413b.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411b(a) and (c) to capture all emissions and route all 
emissions to a control device that meets the conditions specified in 
Sec.  60.5412b.
    (iii) Conduct an initial performance test as required in Sec.  
60.5413b within 180 days after the initial gas well liquids unloading 
operation, or install a control device tested under Sec.  60.5413b(d) 
which meets the criteria in Sec.  60.5413b(d)(11) and (e), and comply 
with the continuous compliance requirements of Sec.  60.5415b(f).
    (iv) You must conduct the initial inspections required in Sec.  
60.5416b(a) and (b).
    (v) You must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417b(a) through (i), as 
applicable.
    (vi) You must maintain the records specified in Sec.  
60.5420b(c)(2)(iii),(c)(8) and (c)(10) through (13), as applicable and 
submit the reports as required by Sec.  60.5420b(b)(11) through (13), 
as applicable.
    (c) Associated gas well standards for well affected facility. To 
demonstrate initial compliance with the GHG and VOC standards for each 
associated gas well as required by Sec.  60.5377b, you must comply with 
paragraphs (c)(1) through (3) of this section.
    (1) If you comply with the requirements of Sec.  60.5377b(a), you 
must maintain the records specified in Sec.  60.5420b(c)(3)(i), (ii), 
and (iv).
    (2) For associated gas wells that comply with Sec.  60.5377b(f) 
based on a demonstration and certification that it is not feasible to 
comply with paragraph (a)(1), (2), (3), and (4) of this section due to 
technical reasons in accordance with paragraph Sec.  60.5377b(g), you 
must comply with paragraphs (c)(2)(i) and (ii) of this section.
    (i) Document the technical reasons why it is infeasible to route 
recovered associated gas into a gas gathering flow line or collection 
system to a sales line, use it as an onsite fuel source, use it for 
another useful purpose that a purchased fuel or raw material would 
serve, or re-inject it into the well or inject it into another well, 
and submit this documentation in the initial annual report.
    (ii) Submit the certification as required by Sec.  60.5377b(g).
    (3) If you comply with Sec.  60.5377b(d) or (f), you must comply 
with paragraphs (c)(3)(i) through (vi) of this section.
    (i) Reduce methane and VOC emissions by 95.0 percent or greater and 
as demonstrated by the requirements of Sec.  60.5413b.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411b(a) and (c) to capture the associated gas and route the 
captured associated gas to a control device that meets the conditions 
specified in Sec.  60.5412b.
    (iii) Conduct an initial performance test as required in Sec.  
60.5413b within 180 days after initial startup or by May 7, 2024, 
whichever date is later, or install a control device tested under Sec.  
60.5413b(d) which meets the criteria in Sec.  60.5413b(d)(11) and (e) 
and you must comply with the continuous compliance requirements of 
Sec.  60.5415b(f).
    (iv) Conduct the initial inspections required in Sec.  60.5416b(a) 
and (b).
    (v) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417b(a) through (i), as applicable.
    (vi) Maintain the records specified in Sec.  60.5420b(c)(3)(iv) and 
(c)(8) and (c)(10) through (13), as applicable.
    (4) You must submit the initial annual report for your associated 
gas well as required in Sec.  60.5420b(b)(1) and (4) and (b)(11) 
through (13), as applicable.
    (d) Centrifugal compressor affected facility. To demonstrate 
initial compliance with the GHG and VOC standards for your centrifugal 
compressor affected facility that uses a wet seal as required by Sec.  
60.5380b, you must comply with paragraphs (d)(1) through (5) and 
paragraphs (d)(7) and (8) of this section. To demonstrate initial 
compliance with the GHG and VOC alternative standards for your 
centrifugal compressor affected facility that is a self-contained wet 
seal centrifugal compressor or a centrifugal compressor at the Alaska 
North Slope equipped with sour seal oil separator and capture system as 
allowed by Sec.  60.5380b, you must comply with paragraphs (d)(6) 
through (8) of this section. To demonstrate initial compliance with the 
GHG and VOC alternative standards for your dry seal centrifugal 
compressor as required by Sec.  60.5380b, you must comply with 
paragraphs (d)(6) through (8) of this section.
    (1) You must reduce methane and VOC emissions by 95.0 percent or 
greater according to Sec.  60.5380b(a)(1) and (2) and as demonstrated 
by the requirements of Sec.  60.5413b, or you must route emissions to a 
process according to Sec.  60.5380b(a)(3).
    (2) If you use a control device to reduce emissions to comply with 
Sec.  60.5380b(a)(1) and (2), you must equip the wet seal fluid 
degassing system with a cover that meets the requirements of Sec.  
60.5411b(b) that is connected through a closed vent system that meets 
the requirements of Sec.  60.5411b(a) and (c) and is routed to a 
control device that meets the conditions specified in Sec.  60.5412b. 
If you comply with Sec.  60.5380b(a)(3) by routing the closed vent 
system to a process as an alternative to routing the closed vent system 
to a control device, you must equip the wet seal fluid degassing system 
with a cover that meets the requirements of Sec.  60.5411b(b), and 
route captured vapors through a closed vent system that meets the 
requirements of Sec.  60.5411b(a) and (c).
    (3) If you use a control device to comply with Sec.  60.5380b(a)(1) 
and (2), you must conduct an initial performance test as required in 
Sec.  60.5413b within 180 days after initial startup or by May 7, 2024, 
whichever date is later, or install a control device tested under Sec.  
60.5413b(d) which meets the criteria in Sec.  60.5413b(d)(11) and (e) 
and you must comply with the continuous compliance requirements of 
Sec.  60.5415b(f).
    (4) If you use a control device to comply with Sec.  60.5380b(a)(1) 
and (2) or comply with Sec.  60.5380b(a)(3) by routing to a process, 
you must conduct the initial inspections required in Sec.  60.5416b(a) 
and (b).
    (5) If you use a control device to comply with Sec.  60.5380b(a)(1) 
and (2), you must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417b(a) through (i), as 
applicable.
    (6) You must maintain the volumetric flow rates for your 
centrifugal compressors as specified in paragraphs (d)(6)(i) through 
(iii) of this section, as applicable. You must conduct your

[[Page 17085]]

initial annual volumetric measurement as required by Sec.  
60.5380b(a)(5).
    (i) For your self-contained wet seal centrifugal compressors, you 
must maintain the volumetric flow rate at or below 3 scfm per seal.
    (ii) For your centrifugal compressor on the Alaska North Slope 
equipped with sour seal oil separator and capture system, you must 
maintain the volumetric flow rate at or below 9 scfm per seal.
    (iii) For your dry seal compressor, you must maintain the 
volumetric flow rate at or below 10 scfm per seal.
    (7) You must submit the initial annual report for your centrifugal 
compressor affected facility as required in Sec.  60.5420b(b)(1) and 
(5) and (b)(11) through (13), as applicable.
    (8) You must maintain the records as specified in Sec.  
60.5420b(c)(4) and (c)(8) through (13), as applicable.
    (e) Reciprocating compressor affected facility. To demonstrate 
initial compliance with the GHG and VOC standards for each 
reciprocating compressor affected facility as required by Sec.  
60.5385b, you must comply with paragraphs (e)(1) through (7) of this 
section.
    (1) If you comply with Sec.  60.5385b by maintaining volumetric 
flow rate at or below 2 scfm per cylinder (or a combined cylinder 
volumetric flow rate greater than the number of compression cylinders 
multiplied by 2 scfm) as required by Sec.  60.5385b(a), you must 
maintain volumetric flow rate at or below 2 scfm and you must conduct 
your initial annual volumetric flow rate measurement as required by 
Sec.  60.5385b(a)(1).
    (2) If you comply with Sec.  60.5385bby collecting the methane and 
VOC emissions from your reciprocating compressor rod packing using a 
rod packing emissions collection system as required by Sec.  
60.5385b(d)(1), you must equip the reciprocating compressor with a 
cover that meets the requirements of Sec.  60.5411b(b), route emissions 
to a process through a closed vent system that meets the requirements 
of Sec.  60.5411b(a) and (c), and you must conduct the initial 
inspections required in Sec.  60.5416b(a) and (b).
    (3) If you comply with Sec.  60.5385b(d) by collecting the 
emissions from your rod packing emissions collection system by using a 
control device to reduce VOC and methane emissions by 95.0 percent as 
required by Sec.  60.5385b(d)(2), you must equipe the reciprocating 
compressor with a cover that meets the requirements of Sec.  
60.5411b(b), route emissions to a control device that meets the 
conditions specified in Sec.  60.5412b through a closed vent system 
that meets the requirements of Sec.  60.5411b(a) and (c) and you must 
conduct the initial inspections required in Sec.  60.5416b(a) and (b).
    (4) If you comply with Sec.  60.5385b(d)(2), you must conduct an 
initial performance test as required in Sec.  60.5413b within 180 days 
after initial startup or by May 7, 2024, whichever date is later, or 
install a control device tested under Sec.  60.5413b(d) which meets the 
criteria in Sec.  60.5413b(d)(11) and (e) and you must comply with the 
continuous compliance requirements of Sec.  60.5415b(f).
    (5) If you comply with Sec.  60.5385b(d)(2), you must install and 
operate the continuous parameter monitoring systems in accordance with 
Sec.  60.5417b(a) through (i), as applicable.
    (6) You must submit the initial annual report for your 
reciprocating compressor as required in Sec.  60.5420b(b)(1), (6), and 
(11) through (13), as applicable.
    (7) You must maintain the records as specified in Sec.  
60.5420b(c)(5) and (8) through (13) as applicable.
    (f) Process controller affected facility. To demonstrate initial 
compliance with GHG and VOC emission standards for your process 
controller affected facility as required by Sec.  60.5390b, you must 
comply with paragraphs (f)(1) through (5) of this section, as 
applicable. If you change compliance methods, you must perform the 
applicable compliance demonstrations of paragraphs (f)(1) through (3) 
of this section again for the new compliance method, note the change in 
compliance method in the annual report required by Sec.  
60.5420b(b)(7)(iv), and maintain the records required by paragraph 
(f)(5) of this section for the new compliance method.
    (1) For process controller affected facilities complying with the 
requirements of Sec.  60.5390b(a), you must demonstrate that your 
process controller affected facility does not emit any VOC or methane 
to the atmosphere by meeting the requirements of paragraphs (f)(1)(i) 
or (ii) of this section.
    (i) If you comply by routing the emissions to a process, you must 
meet the requirements for closed vent systems specified in paragraph 
(f)(3) of this section.
    (ii) If you comply by using a self-contained natural gas-driven 
process controller, you must conduct an initial no identifiable 
emissions inspection as required by Sec.  60.5416b(b).
    (2) For each process controller affected facility located at a site 
in Alaska that does not have access to electrical power, you must 
demonstrate initial compliance with Sec.  60.5390b(b)(1) and (2) or 
with Sec.  60.5390b(b)(3), instead of complying with paragraph Sec.  
60.5390b(a), by meeting the requirements specified in (f)(2)(i) through 
(v) of this section for each process controller, as applicable.
    (i) For each process controller in the process controller affected 
facility operating with a bleed rate of less than or equal to 6 scfh, 
you must maintain records in accordance with Sec.  
60.5420b(c)(6)(iii)(A) that demonstrate the process controller is 
designed and operated to achieve a bleed rate less than or equal to 6 
scfh.
    (ii) For each process controller in the process controller affected 
facility operating with a bleed rate greater than 6 scfh, you must 
maintain records that demonstrate that a controller with a higher bleed 
rate than 6 scfh is required based on a specific functional need for 
that controller as specified in Sec.  60.5420b(c)(6)(iii)(B).
    (iii) For each intermittent vent process controller in the process 
controller affected facility you must demonstrate that each 
intermittent vent controller does not emit to the atmosphere during 
idle periods by conducting initial monitoring in accordance with Sec.  
60.5390b(b)(2)(ii).
    (iv) For each process controller affected facility that complies by 
reducing methane and VOC emissions from all controllers in the process 
controller affected facility by 95.0 percent in accordance with Sec.  
60.5390b(b)(3), you must comply with paragraphs (b)(2)(iv)(A) through 
(D) of this section.
    (A) Reduce methane and VOC emissions by 95.0 percent or greater and 
as demonstrated by the requirements of Sec.  60.5413b.
    (B) Route all process controller affected facility emissions to a 
control device that meets the conditions specified in Sec.  60.5412b 
through a closed vent system that meets the requirements specified in 
paragraph (f)(3) of this section.
    (C) Conduct an initial performance test as required in Sec.  
60.5413b within 180 days after initial startup or by May 7, 2024, 
whichever date is later, or install a control device tested under Sec.  
60.5413b(d) which meets the criteria in Sec.  60.5413b(d)(11) and (e) 
and you must comply with the continuous compliance requirements of 
Sec.  60.5415b(f).
    (D) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417b(a) through (i), as applicable.
    (3) For each closed vent system used to comply with Sec.  60.5390b, 
you must meet the requirements specified in

[[Page 17086]]

paragraphs (f)(3)(i) and (ii) of this section.
    (i) Install a closed vent system that meets the requirements of 
Sec.  60.5411b(a) and (c).
    (ii) Conduct the initial inspections of the closed vent system and 
bypasses, if applicable, as required in Sec.  60.5416b(a) and (b).
    (4) You must submit the initial annual report for your process 
controller affected facility as required in Sec.  60.5420b(b)(1) and 
(7).
    (5) You must maintain the records as specified in Sec.  
60.5420b(c)(6).
    (g) Pump affected facility. To demonstrate initial compliance with 
the GHG and VOC standards for your pump affected facility as required 
by Sec.  60.5393b, you must comply with paragraphs (g)(1) through (4) 
of this section, as applicable. If you change compliance methods, you 
must perform the applicable compliance demonstrations of paragraphs 
(g)(1) and (2) of this section again for the new compliance method, 
note the change in compliance method in the annual report required by 
Sec.  60.5420b(b)(10)(v)(C), and maintain the records required by 
paragraph (g)(4) of this section for the new compliance method.
    (1) For pump affected facilities complying with the requirements of 
Sec.  60.5393b(a) or (b)(2) by routing emissions to a process, you must 
meet the requirements specified in paragraphs (g)(ii) and (iv) of this 
section. For pump affected facilities complying with the requirements 
of Sec.  60.5393b(b)(3), you must meet the requirements specified in 
paragraphs (g)(1)(i) through (v) of this section.
    (i) Reduce methane and VOC emissions by 95.0 percent or greater and 
as demonstrated by the requirements of Sec.  60.5413b.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411b(a) and (c) to capture all emissions from all pumps in 
the pump affected facility and route all emissions to a process or 
control device that meets the conditions specified in Sec.  60.5412b.
    (iii) Conduct an initial performance test as required in Sec.  
60.5413b within 180 days after initial startup or by May 7, 2024, 
whichever date is later, or install a control device tested under Sec.  
60.5413b(d) which meets the criteria in Sec.  60.5413b(d)(11) and (e) 
and you must comply with the continuous compliance requirements of 
Sec.  60.5415b(f).
    (iv) Conduct the initial inspections of the closed vent system and 
bypasses, if applicable, as required in Sec.  60.5416b(a) and (b).
    (v) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417b(a) through (i), as applicable.
    (2) Submit the certifications specified in paragraphs (g)(2)(i) 
through (iii) of this section, as applicable.
    (i) The certification required by Sec.  60.5393b(b)(3) that there 
is no vapor recovery unit on site and that there is a control device on 
site, but it does not achieve a 95.0 percent emissions reduction.
    (ii) The certification required by Sec.  60.5393b(b)(4) that there 
is no control device or process available on site.
    (iii) The certification required by Sec.  60.5393b(b)(5)(i) that it 
is technically infeasible to capture and route the pump affected 
facility emissions to a process or an existing control device.
    (3) You must submit the initial annual report for your pump 
affected facility as specified in Sec.  60.5420b(b)(1), (10), and 
(b)(11) through (13), as applicable.
    (4) You must maintain the records for your pump affected facility 
as specified in Sec.  60.5420b(c)(8) and (c)(10) through (13), as 
applicable, and (c)(15).
    (h) Process unit equipment affected facility. To achieve initial 
compliance with the GHG and VOC standards for process unit equipment 
affected facilities as required by Sec.  60.5400b, you must comply with 
paragraphs (h)(1) through (4) and (h)(11) through (15) of this section, 
unless you meet and comply with the exception in Sec.  60.5402b(b), 
(e), or (f) or meet the exemption in Sec.  60.5402b(c). If you comply 
with the GHG and VOC standards for process unit equipment affected 
facilities using the alternative standards in Sec.  60.5401b, you must 
comply with paragraphs (h)(5) through (15) of this section, unless you 
meet the exemption in Sec.  60.5402b(b) or (c) or the exception in 
Sec.  60.5402b(e) or (f).
    (1) You must conduct monitoring for each pump in light liquid 
service, pressure relief device in gas/vapor service, valve in gas/
vapor or light liquid service and connector in gas/vapor or light 
liquid service as required by Sec.  60.5400b(b).
    (2) You must conduct monitoring as required by Sec.  60.5400b(c) 
for each pump in light liquid service.
    (3) You must conduct monitoring as required by Sec.  60.5400b(d) 
for each pressure relief device in gas/vapor service.
    (4) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec.  60.5400b(e).
    (5) You must conduct monitoring for each pump in light liquid 
service as required by Sec.  60.5401b(b).
    (6) You must conduct monitoring for each pressure relief device in 
gas/vapor service as required by Sec.  60.5401b(c).
    (7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec.  60.5401b(d).
    (8) You must conduct monitoring for each valve in gas/vapor or 
light liquid service as required by Sec.  60.5401b(f).
    (9) You must conduct monitoring for each pump, valve, and connector 
in heavy liquid service and each pressure relief device in light liquid 
or heavy liquid service as required by Sec.  60.5401b(g).
    (10) You must conduct monitoring for each connector in gas/vapor or 
light liquid service as required by Sec.  60.5401b(h).
    (11) For each pump equipped with a dual mechanical seal system that 
degasses the barrier fluid reservoir to a process or a control device, 
each pump which captures and transports leakage from the seal or seals 
to a process or a control device, or each pressure relief device which 
captures and transports leakage through the pressure relief device to a 
process or a control device, you must meet the requirements of 
paragraph (h)(11)(i) through (vi) of this section.
    (i) Reduce methane and VOC emissions by 95.0 percent or greater and 
as demonstrated by the requirements of Sec.  60.5413b or route to a 
process.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411b(a) and (c) to capture all emissions from each pump 
equipped with a dual mechanical seal system that degasses the barrier 
fluid reservoir, each pump which captures and transports leakage from 
the seal or seals, or each pressure relief device which captures and 
transports leakage through the pressure relief device and route all 
emissions to a process or to a control device that meets the conditions 
specified in Sec.  60.5412b.
    (iii) If routing to a control device, conduct an initial 
performance test as required in Sec.  60.5413b within 180 days after 
initial startup or by May 7, 2024, whichever date is later, or install 
a control device tested under Sec.  60.5413b(d) which meets the 
criteria in Sec.  60.5413b(d)(11) and (e), and you must comply with the 
continuous compliance requirements of Sec.  60.5415b(f).
    (iv) Conduct the initial inspections of the closed vent system and 
bypasses, if applicable, as required in Sec.  60.5416b(a) and (b).
    (v) Install and operate the continuous parameter monitoring systems 
in

[[Page 17087]]

accordance with Sec.  60.5417b(a) through (i), as applicable.
    (vi) Maintain the records as required by Sec.  60.5420b(c)(8) and 
(c)(10) through (c)(13), as applicable and submit the reports as 
required by Sec.  60.5420b(b)(11) through (13), as applicable.
    (12) You must tag and repair each identified leak as required in 
Sec.  60.5400b(h) or Sec.  60.5400b(i), as applicable.
    (13) You must submit the notice required by Sec.  60.5420b(a)(1).
    (14) You must submit the initial semiannual report and subsequent 
semiannual report as required by Sec.  60.5422b.
    (15) You must maintain the records specified by Sec.  60.5421b.
    (i) Sweetening unit affected facility. To achieve initial 
compliance with the SO<INF>2</INF> standard for your sweetening unit 
affected facility as required by Sec.  60.5405b, you must comply with 
paragraphs (i)(1) through (14) of this section.
    (1) You must conduct an initial performance test as required by 
Sec.  60.8 and according to the requirements of Sec.  60.5406b.
    (2) You must determine the minimum required initial reduction 
efficiency of SO<INF>2</INF> emissions (Z<INF>i</INF>) as required by 
Sec.  60.5406b(b).
    (3) You must determine the emission reduction efficiency (R) 
achieved by your sulfur reduction technology using the procedures in 
Sec.  60.5406b(c)(1) through (4).
    (4) You must demonstrate compliance with the standard as required 
by Sec.  60.5405b(a) by comparing the minimum required SO<INF>2</INF> 
emission reduction efficiency (Z<INF>i</INF>) to the emission reduction 
efficiency achieved by the sulfur recovery technology (R), where R must 
be greater than or equal to Z<INF>i</INF>.
    (5) You must install, calibrate, maintain, and operate monitoring 
devices or perform measurements to determine the accumulation of sulfur 
product, the H<INF>2</INF>S concentration, the average acid gas flow 
rate, and the sulfur feed rate in accordance with Sec.  60.5407b(a).
    (6) You must determine the required SO<INF>2</INF> emissions 
reduction efficiency each 24-hour period in accordance with Sec.  
60.5407b(a), (d), and (e), as applicable.
    (7) You must install, calibrate, maintain, and operate monitoring 
devices and continuous emission monitors in accordance with Sec.  
60.5407b(b), (f), and (g), if you use an oxidation control system or a 
reduction control system followed by an incineration device.
    (8) You must continuously operate the incineration device if you 
use an oxidation control system, or a reduction control system followed 
by an incineration device.
    (9) You must install, calibrate, maintain, and operate a continuous 
monitoring system to measure the emission rate of reduced sulfur 
compounds in accordance with Sec.  60.5407b(c), (f), and (g), if you 
use a reduction control system not followed by an incineration device.
    (10) You must submit the notification required by Sec.  
60.5420b(a)(1).
    (11) You must submit the initial annual report required by Sec.  
60.5423b(b).
    (12) You must submit the performance test report in accordance with 
the requirements of Sec.  60.5420b(b)(12).
    (13) You must submit the annual excess emissions reports required 
by Sec.  60.5423b(d), if applicable.
    (14) You must maintain the records required by Sec.  60.5423b(a), 
(e) and (f), as applicable.
    (j) Storage vessel affected facility. To achieve initial compliance 
with the GHG and VOC standards for each storage vessel affected 
facility as required by Sec.  60.5395b, you must comply with paragraphs 
(j)(1) through (9) of this section. To achieve initial compliance with 
the GHG and VOC standards for each storage vessel affected facility 
that complies by using a floating roof in accordance with Sec.  
60.5395b(b)(2), you must comply with paragraphs (j)(1) and (10) of this 
section.
    (1) You must determine the potential for methane and VOC emissions 
as specified in Sec.  60.5365b(e)(2).
    (2) You must reduce methane and VOC emissions by 95.0 percent or 
greater according to Sec.  60.5395b(a) and as demonstrated by the 
requirements of Sec.  60.5413b or route to a process.
    (3) If you use a control device to reduce emissions, you must equip 
each storage vessel in the storage vessel affected facility with a 
cover that meets the requirements of Sec.  60.5411b(b), install a 
closed vent system that meets the requirements of Sec.  60.5411b(a) and 
(c) to capture all emissions from the storage vessel affected facility, 
and route all emissions to a control device that meets the conditions 
specified in Sec.  60.5412b. If you route emissions to a process, you 
must equip each storage vessel in the storage vessel affected facility 
with a cover that meets the requirements of Sec.  60.5411b(b), install 
a closed vent system that meets the requirements of Sec.  60.5411b(a) 
and (c) to capture all emissions from the storage vessel affected 
facility, and route all emissions to a process.
    (4) If you use a control device to reduce emissions, you must 
conduct an initial performance test as required in Sec.  60.5413b 
within 180 days after initial startup or within 180 days of May 7, 
2024, whichever date is later, or install a control device tested under 
Sec.  60.5413b(d) which meets the criteria in Sec.  60.5413b(d)(11) and 
(e), and you must comply with the continuous compliance requirements of 
Sec.  60.5415b(f).
    (5) You must conduct the initial inspections of the closed vent 
system and bypasses, if applicable, as required in Sec.  60.5416b(a) 
and (b).
    (6) You must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417b(a) through (i), as 
applicable.
    (7) You must maintain the records as required by Sec.  
60.5420b(c)(8) through (13), as applicable and submit the reports as 
required by Sec.  60.5420b(b)(11) through (13), as applicable.
    (8) You must submit the initial annual report for your storage 
vessel affected facility required by Sec.  60.5420b(b)(1) and (8).
    (9) You must maintain the records required for your storage vessel 
affected facility, as specified in Sec.  60.5420b(c)(7) for each 
storage vessel affected facility.
    (10) For each storage vessel affected facility that complies by 
using a floating roof, you must meet the requirements of Sec.  
60.112b(a)(1) or (2) and the relevant monitoring, inspection, 
recordkeeping, and reporting requirements in subpart Kb of this part. 
You must submit a statement that you are complying with Sec.  
60.112b(d)(a)(1) or (2) in accordance with Sec.  60.5395b(b)(2) with 
the initial annual report specified in Sec.  60.5420b(b)(1) and (8).
    (k) Fugitive emission components affected facility. To achieve 
initial compliance with the GHG and VOC standards for fugitive 
emissions components affected facilities as required by Sec.  60.5397b, 
you must comply with paragraphs (k)(1) through (5) of this section.
    (1) You must develop a fugitive emissions monitoring plan as 
required in Sec.  60.5397b(b), (c), and (d).
    (2) You must conduct an initial monitoring survey as required in 
Sec.  60.5397b(e) and (f).
    (3) You must repair each identified source of fugitive emissions 
for each affected facility as required in Sec.  60.5397b(h).
    (4) You must submit the initial annual report for each fugitive 
emissions components affected facility as required in Sec.  
60.5420b(b)(1) and (9).
    (5) You must maintain the records specified in Sec.  
60.5420b(c)(14).

[[Page 17088]]

Sec.  60.5411b   What additional requirements must I meet to determine 
initial compliance for my covers and closed vent systems?

    For each cover or closed vent system at your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, storage 
vessel, and process unit equipment affected facilities, you must comply 
with the applicable requirements of paragraphs (a) through (c) of this 
section.
    (a) Closed vent system requirements. (1) Reciprocating compressor 
rod packing, process controllers, and pumps. You must design the closed 
vent system to capture and route all gases, vapors, and fumes to a 
process.
    (2) Associated gas wells, centrifugal compressors, process 
controllers in Alaska, pumps complying with Sec.  60.5393b(b)(1), 
storage vessels, and process unit equipment. You must design the closed 
vent system to capture and route all gases, vapors, and fumes to a 
process or a control device that meets the requirements specified in 
Sec.  60.5412b(a) through (d) of this section. For pumps complying with 
Sec.  60.5393b(b)(3), you must design the closed vent system to capture 
and route all gases, vapors, and fumes to a control device that meets 
the requirements specified in Sec.  60.5412b(a) through (d) of this 
section.
    (3) You must design and operate the closed vent system with no 
identifiable emissions as demonstrated by Sec.  60.5416b(a) and (b).
    (4) Bypass devices. You must meet the requirements specified in 
paragraphs (a)(4)(i) and (ii) of this section if the closed vent system 
contains one or more bypass devices that could be used to divert all or 
a portion of the gases, vapors, or fumes from entering the control 
device or being routed to a process.
    (i) Except as provided in paragraph (a)(4)(ii) of this section, you 
must comply with either paragraph (a)(4)(i)(A) or (B) of this section 
for each bypass device.
    (A) You must properly install, calibrate, maintain, and operate a 
flow indicator at the inlet to the bypass device. The flow indicator 
must be capable of taking periodic readings as specified in Sec.  
60.5416b(a)(4)(i) and sound an alarm, or initiate notification via 
remote alarm to the nearest field office, when the bypass device is 
open such that the stream is being, or could be, diverted away from the 
control device or process, and sent to the atmosphere. You must 
maintain records of each time the alarm is activated according to Sec.  
60.5420b(c)(10).
    (B) You must secure the bypass device valve installed at the inlet 
to the bypass device in the non-diverting position using a car-seal or 
a lock-and-key type configuration.
    (ii) Low leg drains, high point bleeds, analyzer vents, open-ended 
valves or lines, and safety devices are not subject to the requirements 
of paragraph (a)(4)(i) of this section.
    (b) Cover requirements for storage vessels and centrifugal 
compressors, and reciprocating compressors. (1) The cover and all 
openings on the cover (e.g., access hatches, sampling ports, pressure 
relief devices and gauge wells) shall form a continuous impermeable 
barrier over the entire surface area of the liquid in the storage 
vessel or centrifugal compressor wet seal fluid degassing system, or 
reciprocating compressor rod packing emissions collection system.
    (2) 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 as follows:
    (i) To add material to, or remove material from the unit (this 
includes openings necessary to equalize or balance the internal 
pressure of the unit following changes in the level of the material in 
the unit);
    (ii) To inspect or sample the material in the unit;
    (iii) To inspect, maintain, repair, or replace equipment located 
inside the unit; or
    (iv) To vent liquids, gases, or fumes from the unit through a 
closed vent system designed and operated in accordance with the 
requirements of paragraph (a) of this section to a control device or to 
a process.
    (3) Each storage vessel thief hatch shall be equipped, maintained 
and operated with a weighted mechanism or equivalent, to ensure that 
the lid remains properly seated and sealed under normal operating 
conditions, including such times when working, standing/breathing, and 
flash emissions may be generated. You must select gasket material for 
the hatch based on composition of the fluid in the storage vessel and 
weather conditions.
    (4) You must design and operate the cover with no identifiable 
emissions as demonstrated by Sec.  60.5416b(a) and (b), except when 
operated as provided in paragraphs (b)(2)(i) through (iii) of this 
section.
    (c) Design requirements. (1) You must conduct an assessment that 
the closed vent system is of sufficient design and capacity to ensure 
that all gases, vapors, and fumes from the affected facility are routed 
to the control device or process and that the control device or process 
is of sufficient design and capacity to accommodate all emissions from 
the affected facility. The assessment must be certified by a qualified 
professional engineer or an in-house engineer with expertise on the 
design and operation of the closed vent system in accordance with 
paragraphs (c)(1)(i) and (ii) of this section.
    (i) You must provide the following certification, signed and dated 
by a qualified professional engineer or an in-house engineer: ``I 
certify that the closed vent system design and capacity assessment was 
prepared under my direction or supervision. I further certify that the 
closed vent system design and capacity assessment was conducted, and 
this report was prepared pursuant to the requirements of subpart OOOOb 
of this part. Based on my professional knowledge and experience, and 
inquiry of personnel involved in the assessment, the certification 
submitted herein is true, accurate, and complete.''
    (ii) The assessment shall be prepared under the direction or 
supervision of a qualified professional engineer or an in-house 
engineer who signs the certification in paragraph (c)(1)(i) of this 
section.


Sec.  60.5412b   What additional requirements must I meet for 
determining initial compliance of my control devices?

    You must meet the requirements of paragraphs (a) and (b) of this 
section for each control device used to comply with the emissions 
standards for your well, centrifugal compressor, reciprocating 
compressor, storage vessel, process controller, pump, or process unit 
equipment affected facility. If you use a carbon adsorption system as a 
control device to meet the requirements of paragraph (a)(2) of this 
section, you also must meet the requirements in paragraph (c) of this 
section.
    (a) Each control device used to meet the emissions reduction 
standard in Sec.  60.5377b(f) for your associated gas well at a well 
affected facility; Sec.  60.5376b(g) for your well affected facility 
gas well that unloads liquids; Sec.  60.5380b(a)(1) for your 
centrifugal compressor affected facility; Sec.  60.5385b(d)(2) for your 
reciprocating compressor affected facility; Sec.  60.5395b(a)(2) for 
your storage vessel affected facility; Sec.  60.5390b(b)(3) for your 
process controller affected facility in Alaska; Sec.  60.5393b(b)(1) 
for your pumps affected facility; or either Sec.  60.5400b(f) or Sec.  
60.5401b(e) for your process equipment affected facility must be 
installed according to paragraphs (a)(1) through (3) of this section. 
As an alternative to paragraphs (a)(1) through

[[Page 17089]]

(a)(3) of this section, you may install a control device model tested 
under Sec.  60.5413b(d), which meets the criteria in Sec.  
60.5413b(d)(11) and which meets the initial and continuous compliance 
requirements in Sec.  60.5413b(e).
    (1) Each enclosed combustion device (e.g., thermal vapor 
incinerator, catalytic vapor incinerator, boiler, or process heater) 
must be designed and operated in accordance with paragraph (a)(1)(i) of 
this section, meet one of the operating limits specified in paragraphs 
(a)(1)(ii) through (v) of this section, and except for boilers and 
process heaters meeting the requirements of paragraph (a)(1)(iii) of 
this section and catalytic vapor incinerators meeting the requirements 
of paragraph (a)(1)(v) of this section, meet the operating limits 
specified in paragraphs (a)(1)(vi) through (ix) of this section. 
Alternatively, the enclosed combustion device must meet the 
requirements specified in paragraph (d) of this section.
    (i) You must reduce the mass content of methane and VOC in the 
gases vented to the device by 95.0 percent by weight or greater or 
reduce the concentration of total organic compounds (TOC) in the 
exhaust gases at the outlet to the device to a level equal to or less 
than 275 ppmv as propane on a wet basis corrected to 3 percent oxygen 
as determined in accordance with the requirements of Sec.  60.5413b(b), 
with the exceptions noted in Sec.  60.5413b(a).
    (ii) For an enclosed combustion device for which you demonstrate 
during the performance test conducted under Sec.  60.5413b(b) that 
combustion zone temperature is an indicator of destruction efficiency, 
you must operate at or above the minimum temperature established during 
the most recent performance test. During the performance test conducted 
under Sec.  60.5413b(b), you must continuously record the temperature 
of the combustion zone and average the temperature for each test run. 
The established minimum temperature limit is the average of the test 
run averages.
    (iii) For an enclosed combustion device which is a boiler or 
process heater, you must introduce the vent stream into the flame zone 
of the boiler or process heater and introduce the vent stream with the 
primary fuel or use the vent stream as the primary fuel.
    (iv) For an enclosed combustion device other than those meeting the 
operating limits in paragraphs (a)(1)(ii), (iii), and (v) of this 
section, if the enclosed combustion device is unassisted or pressure-
assisted, you must maintain the net heating value (NHV) of the gas sent 
to the enclosed combustion device at or above the applicable limits 
specified in paragraphs (a)(1)(iv)(A) and (B) of this section. If the 
enclosed combustion device is steam-assisted or air-assisted, you must 
meet the applicable limits specified in paragraphs (a)(1)(iv)(C) and 
(D) of this section, as appropriate.
    (A) For enclosed combustion devices that do not use assist gas or 
pressure-assisted burner tips to promote mixing at the burner tip, 200 
British thermal units (Btu) per standard cubic feet (Btu/scf).
    (B) For enclosed combustion devices that use pressure-assisted 
burner tips to promote mixing at the burner tip, 800 Btu/scf.
    (C) For steam-assisted and air-assisted enclosed combustion 
devices, maintain the combustion zone NHV (NHV<INF>cz</INF>) at or 
above 270 Btu/scf.
    (D) For enclosed combustion devices with perimeter assist air, 
maintain the NHV dilution parameter (NHV<INF>dil</INF>) at or above 22 
British thermal units per square foot (Btu/sqft). If the only assist 
air provided to the enclosed combustion control device is perimeter 
assist air intentionally entrained in lower and/or upper steam at the 
burner tip and the effective diameter is 9 inches or greater, you are 
only required to comply with the NHV<INF>cz</INF> limit specified in 
paragraph (a)(1)(iv)(C) of this section.
    (v) For an enclosed combustion device which is a catalytic vapor 
incinerator, you must operate the catalytic vapor incinerator at or 
above the minimum temperature of the catalyst bed inlet and at or above 
the minimum temperature differential between the catalyst bed inlet and 
the catalyst bed outlet established in accordance with Sec.  
60.5417b(f) and as determined in your performance test conducted in 
accordance with Sec.  60.5413b(b).
    (vi) Unless you have an enclosed combustion device with pressure-
assisted burner tips to promote mixing at the burner tip, you must 
operate each enclosed combustion device at or below the maximum inlet 
gas flow rate established in accordance with Sec.  60.5417b(f) and as 
determined in your performance test conducted in accordance with Sec.  
60.5413b(b).
    (vii) You must operate the combustion control device at or above 
the minimum inlet gas flow rate established in accordance with Sec.  
60.5417b(f).
    (viii) You must install and operate a continuous burning pilot or 
combustion flame. An alert must be sent to the nearest control room 
whenever the pilot or combustion flame is unlit.
    (ix) You must operate the enclosed combustion device with no 
visible emissions, except for periods not to exceed a total of 1 minute 
during any 15-minute period. A visible emissions test using section 11 
of Method 22 of appendix A-7 to this part must be performed at least 
once every calendar month, separated by at least 15 days between each 
test. The observation period shall be 15 minutes or once the amount of 
time visible emissions is present has exceeded 1 minute, whichever time 
period is less. Alternatively, you may conduct visible emissions 
monitoring according to Sec.  60.5417b(h). Devices failing the visible 
emissions test must follow manufacturer's repair instructions, if 
available, or best combustion engineering practice as outlined in the 
unit inspection and maintenance plan, to return the unit to compliant 
operation. All inspection, repair, and maintenance activities for each 
unit must be recorded in a maintenance and repair log and must be 
available for inspection. Following return to operation from 
maintenance or repair activity, each device must pass a Method 22 of 
appendix A-7 to this part visual observation as described in this 
paragraph or be monitored according to Sec.  60.5417b(h).
    (2) Each vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device must be designed and 
operated to reduce the mass content of methane and VOC in the gases 
vented to the device by 95.0 percent by weight or greater as determined 
in accordance with the requirements of Sec.  60.5413b(b). As an 
alternative to the performance testing requirements of Sec.  
60.5413b(b), you may demonstrate initial compliance by conducting a 
design analysis for vapor recovery devices according to the 
requirements of Sec.  60.5413b(c). For a condenser, you also must 
calculate the daily average condenser outlet temperature in accordance 
with Sec.  60.5417b(e), and you must determine the condenser efficiency 
for the current operating day using the daily average condenser outlet 
temperature and the condenser performance curve established in 
accordance with Sec.  60.5417b(f)(2). You must determine the average 
TOC emission reduction in accordance with Sec.  60.5415b(f)(1)(ix)(D). 
For a carbon adsorption system, you also must comply with paragraph (c) 
of this section.
    (3) Each flare must be designed and operated according to the 
requirements specified in paragraphs (a)(3)(i) through (viii) of this 
section, as applicable. Alternatively, flares must meet the 
requirements specified in paragraph (d) of this section.

[[Page 17090]]

    (i) For unassisted flares, you must maintain the NHV of the vent 
gas sent to the flare at or above 200 Btu/scf.
    (ii) For flares that use pressure-assisted burner tips to promote 
mixing at the burner tip, you must maintain the NHV of the vent gas 
sent to the flare at or above 800 Btu/scf.
    (iii) For steam-assisted and air-assisted flares, you must maintain 
the NHV<INF>cz</INF> at or above 270 Btu/scf.
    (iv) For flares with perimeter assist air, you must maintain the 
NHV<INF>dil</INF> at or above 22 Btu/sqft. If the only assist air 
provided to the flare is perimeter assist air intentionally entrained 
in lower and/or upper steam at the flare tip and the effective diameter 
is 9 inches or greater, you are not required to comply with the 
NHV<INF>dil</INF> limit.
    (v) For flares other than pressure-assisted flares, you must 
demonstrate compliance with the flare tip velocity limits in Sec.  
60.18(b) according to Sec.  60.5417b(d)(8)(iv). The maximum flare tip 
velocity limits do not apply for pressure-assisted flares.
    (vi) You must operate the flare at or above the minimum inlet gas 
flow rate. The minimum inlet gas flow rate is established based on 
manufacturer recommendations.
    (vii) You must operate the flare with no visible emissions, except 
for periods not to exceed a total of 1 minute during any 15-minute 
period. You must conduct the compliance determination with the visible 
emission limits using Method 22 of appendix A-7 to this part, or you 
must monitor the flare according to Sec.  60.5417b(h).
    (viii) You must install and operate a continuous burning pilot or 
combustion flame. An alert must be sent to the nearest control room 
whenever the pilot or combustion flame is unlit.
    (b) You must operate each control device installed on your well, 
centrifugal compressor, reciprocating compressor, storage vessel, 
process controller, pump, or process unit equipment affected facility 
in accordance with the requirements specified in paragraphs (b)(1) and 
(2) of this section.
    (1) You must operate each control device used to comply with this 
subpart at all times when gases, vapors, and fumes are vented from the 
affected facility through the closed vent system to the control device. 
You may vent more than one affected facility to a control device used 
to comply with this subpart.
    (2) For each control device monitored in accordance with the 
requirements of Sec.  60.5417b(a) through (i), you must demonstrate 
compliance according to the requirements of Sec.  60.5415b(f), as 
applicable.
    (c) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (a)(2) of this section, you must 
comply with the requirements of paragraph (c)(1) of this section. If 
the carbon adsorption system is a regenerative-type carbon adsorption 
system, you also must comply with the requirements of paragraph (c)(2) 
of this section.
    (1) You must manage the carbon in accordance with the requirements 
specified in paragraphs (c)(1)(i) and (ii) of this section.
    (i) Following the initial startup of the control device, you must 
replace all carbon in the carbon adsorption system with fresh carbon on 
a regular, predetermined time interval that is no longer than the 
carbon service life established according to Sec.  60.5413b(c)(2) or 
(3). You must maintain records identifying the schedule for replacement 
and records of each carbon replacement as required in Sec.  
60.5420b(c)(10) and (12).
    (ii) You must either regenerate, reactivate, or burn the spent 
carbon removed from the carbon adsorption system in one of the units 
specified in paragraphs (c)(1)(ii)(A) through (F) of this section.
    (A) Regenerate or reactivate the spent carbon in a unit for which 
you have been issued a final permit under 40 CFR part 270 that 
implements the requirements of 40 CFR part 264, subpart X.
    (B) Regenerate or reactivate the spent carbon in a unit equipped 
with an operating organic air emissions control in accordance with an 
emissions standard for VOC under another subpart in 40 CFR part 63 or 
this part.
    (C) Burn the spent carbon in a hazardous waste incinerator for 
which the owner or operator complies with the requirements of 40 CFR 
part 63, subpart EEE, and has submitted a Notification of Compliance 
under 40 CFR 63.1207(j).
    (D) Burn the spent carbon in a hazardous waste boiler or industrial 
furnace for which the owner or operator complies with the requirements 
of 40 CFR part 63, subpart EEE, and has submitted a Notification of 
Compliance under 40 CFR 63.1207(j).
    (E) Burn the spent carbon in an industrial furnace for which you 
have been issued a final permit under 40 CFR part 270 that implements 
the requirements of 40 CFR part 266, subpart H.
    (F) Burn the spent carbon in an industrial furnace that you have 
designed and operated in accordance with the interim status 
requirements of 40 CFR part 266, subpart H.
    (2) You must comply with the requirements of paragraph (c)(2)(i) 
through (iii) of this section for each regenerative-type carbon 
adsorption system.
    (i) You must measure and record the average total regeneration 
stream mass flow or volumetric flow during each carbon bed regeneration 
cycle to demonstrate compliance with the total regeneration stream flow 
established in accordance with Sec.  60.5413b(c)(2).
    (ii) You must check the mechanical connections for leakage at least 
every month, and you must perform a visual inspection at least every 3 
months of all components of the flow continuous parameter monitoring 
system for physical and operational integrity and all electrical 
connections for oxidation and galvanic corrosion, if your continuous 
parameter monitoring system is not equipped with a redundant flow 
sensor.
    (iii) You must measure and record the average carbon bed 
temperature for the duration of the carbon bed steaming cycle and 
measure the actual carbon bed temperature after regeneration and within 
15 minutes of completing the cooling cycle. You must maintain the 
average carbon bed temperature above the temperature limit in 
established accordance with Sec.  60.5413b(c)(2) during the carbon bed 
steaming cycle and below the carbon bed temperature established in in 
accordance with Sec.  60.5413b(c)(2) after the regeneration cycle.
    (d) To demonstrate that a flare or enclosed combustion device 
reduces methane and VOC in the gases vented to the device by 95.0 
percent by weight or greater, as outlined in Sec.  60.8(b), you may 
submit a request for an alternative test method. At a minimum, the 
request must follow the requirements outlined in paragraphs (d)(1) 
through (5) of this section.
    (1) The alternative method must be capable of demonstrating 
continuous compliance with a combustion efficiency of 95.0 percent or 
greater or it must be capable of demonstrating continuous compliance 
with the following metrics:
    (i) NHV<INF>cz</INF> of 270 Btu/scf or greater.
    (ii) NHV<INF>dil</INF> of 22 Btu/sqft or greater, if the 
alternative test method will be used for enclosed combustion devices or 
flares with perimeter assist air.
    (2) The alternative method must be validated according to Method 
301 in appendix A of 40 CFR part 63 for each type of control device 
covered by the alternative test method (e.g., air-assisted flare, 
unassisted enclosed combustion

[[Page 17091]]

device) or the alternative test method must contain performance-based 
procedures and indicators to ensure self-validation.
    (3) At a minimum the alternative test method must provide a reading 
for each successive 15-minute period.
    (4) The alternative test method must be capable of documenting 
periods when the enclosed combustion device or flare operates with 
visible emissions. If the alternative test method cannot identify 
periods of visible emissions, you must conduct the inspections required 
by Sec.  5417b(d)(8)(v).
    (5) If the alternative test method demonstrates compliance with the 
metrics specified in paragraphs (d)(1)(i) and (ii) of this section 
instead of demonstrating continuous compliance with 95.0 percent or 
greater combustion efficiency, you must still install the pilot or 
combustion flame monitoring system required by Sec.  60.5417b(d)(8)(i). 
If the alternative test method demonstrates continuous compliance with 
a combustion efficiency of 95.0 percent or greater, the requirement in 
Sec.  60.5417b(d)(8)(i) no longer applies.


Sec.  60.5413b  What are the performance testing procedures for control 
devices?

    This section applies to the performance testing of control devices 
used to demonstrate compliance with the emissions standards for your 
well, centrifugal compressor, reciprocating compressor, storage vessel, 
process controller, pump affected facilities complying with Sec.  
60.5393b(b)(1), or process unit equipment affected facility. You must 
demonstrate that a control device achieves the performance requirements 
of Sec.  60.5412b(a)(1) or (2) using the performance test methods and 
procedures specified in this section. For condensers and carbon 
adsorbers, you may use a design analysis as specified in paragraph (c) 
of this section in lieu of complying with paragraph (b) of this 
section. In addition, this section contains the requirements for 
enclosed combustion device performance tests conducted by the 
manufacturer applicable to well, centrifugal compressor, reciprocating 
compressor, storage vessel, process controller, pump affected 
facilities complying with Sec.  60.5393b(b)(1), or process unit 
equipment affected facilities.
    (a) Performance test exemptions. You are exempt from the 
requirements to conduct initial and periodic performance tests and 
design analyses if you use any of the control devices described in 
paragraphs (a)(1) through (6) of this section. You are exempt from the 
requirements to conduct an initial performance test if you use a 
control device described in paragraph (a)(7) of this section.
    (1) A flare that is designed and operated in accordance with the 
requirements in Sec.  60.5412b(a)(3). You must conduct the compliance 
determination using Method 22 of appendix A-7 to this part to determine 
visible emissions or monitor the flare according to Sec.  60.5417b(h). 
The net heating value of the vent gas must be determined according to 
Sec.  60.5417b(d)(8)(ii).
    (2) A boiler or process heater with a design heat input capacity of 
44 megawatts or greater.
    (3) A boiler or process heater into which the vent stream is 
introduced with the primary fuel or is used as the primary fuel.
    (4) A boiler or process heater burning hazardous waste for which 
you have been issued a final permit under 40 CFR part 270 and comply 
with the requirements of 40 CFR part 266, subpart H; you have certified 
compliance with the interim status requirements of 40 CFR part 266, 
subpart H; you have submitted a Notification of Compliance under 40 CFR 
63.1207(j) and comply with the requirements of 40 CFR part 63, subpart 
EEE; or you comply with 40 CFR part 63, subpart EEE and will submit a 
Notification of Compliance under 40 CFR 63.1207(j) by the date 
specified in Sec.  60.5420b(b)(12) for submitting the initial 
performance test report.
    (5) A hazardous waste incinerator for which you have submitted a 
Notification of Compliance under 40 CFR 63.1207(j), or for which you 
will submit a Notification of Compliance under 40 CFR 63.1207(j) by the 
date specified in Sec.  60.5420b(b)(12) for submitting the initial 
performance test report, and you comply with the requirements of 40 CFR 
part 63, subpart EEE.
    (6) A control device for which performance test is waived in 
accordance with Sec.  60.8(b).
    (7) A control device whose model can be demonstrated to meet the 
performance requirements of Sec.  60.5412b(a)(1)(i) through a 
performance test conducted by the manufacturer, as specified in 
paragraph (d) of this section.
    (b) Test methods and procedures. You must use the test methods and 
procedures specified in paragraphs (b)(1) through (4) of this section, 
as applicable, for each performance test conducted to demonstrate that 
a control device meets the requirements of Sec.  60.5412b(a)(1) or (2). 
You must conduct the initial and periodic performance tests according 
to the schedule specified in paragraph (b)(5) of this section. Each 
performance test must consist of a minimum of 3 test runs. Each run 
must be at least 1 hour long.
    (1) You must use Method 1 or 1A of appendix A-1 to this part, as 
appropriate, to select the sampling sites. Any references to 
particulate mentioned in Methods 1 and 1A do not apply to this section.
    (i) Sampling sites must be located at the inlet of the first 
control device and at the outlet of the final control device to 
determine compliance with a control device percent reduction 
requirement.
    (ii) The sampling site must be located at the outlet of the 
combustion device to determine compliance with a TOC exhaust gas 
concentration limit.
    (2) You must determine the gas volumetric flow rate using Method 2, 
2A, 2C, or 2D of appendix A-2 to this part, as appropriate.
    (3) To determine compliance with the control device percent 
reduction performance requirement in Sec.  60.5412b(a)(1)(i) or (a)(2), 
you must use Method 25A of appendix A-7 to this part. You must use 
Method 4 of appendix A-3 to this part to convert the Method 25A results 
to a dry basis. You must use the procedures in paragraphs (b)(3)(i) 
through (iii) of this section to calculate percent reduction 
efficiency.
    (i) You must compute the mass rate of TOC using the following 
equations:
[GRAPHIC] [TIFF OMITTED] TR08MR24.006


[[Page 17092]]


Where:

E<INF>i</INF>, E<INF>o</INF> = Mass rate of TOC at the inlet and 
outlet of the control device, respectively, dry basis, kilograms per 
hour.
K<INF>2</INF> = Constant, 2.494 x 10<SUP>-6</SUP> (parts per 
million) (gram-mole per standard cubic meter) (kilogram/gram) 
(minute/hour), where standard temperature (gram-mole per standard 
cubic meter) is 20 degrees Celsius.
C<INF>i</INF>, C<INF>o</INF> = Concentration of TOC, as propane, of 
the gas stream as measured by Method 25A of appendix A-7 to this 
part at the inlet and outlet of the control device, respectively, 
dry basis, parts per million by volume.
M<INF>p</INF> = Molecular weight of propane, 44.1 gram/gram-mole.
Q<INF>i</INF>, Q<INF>o</INF> = Flow rate of gas stream at the inlet 
and outlet of the control device, respectively, dry standard cubic 
meter per minute.

    (ii) You must calculate the percent reduction in TOC as follows:
    [GRAPHIC] [TIFF OMITTED] TR08MR24.007
    
Where:

R<INF>cd</INF> = Control efficiency of control device, percent.
E<INF>i</INF>, = Mass rate of TOC at the inlet to the control device 
as calculated under paragraph (b)(3)(i) of this section, kilograms 
per hour.
E<INF>o</INF> = Mass rate of TOC at the outlet of the control 
device, as calculated under paragraph (b)(3)(i) of this section, 
kilograms per hour.

    (iii) If the vent stream entering a boiler or process heater with a 
design capacity less than 44 megawatts is introduced with the 
combustion air or as a secondary fuel, you must determine the weight-
percent reduction of total TOC across the device by comparing the TOC 
in all combusted vent streams and primary and secondary fuels with the 
TOC exiting the device, respectively.
    (4) You must use Method 25A of appendix A-7 to this part to measure 
TOC, as propane, to determine compliance with the TOC exhaust gas 
concentration limit specified in Sec.  60.5412b(a)(1)(i). You must 
determine the concentration in parts per million by volume on a wet 
basis and correct it to 3 percent oxygen. You must use the emission 
rate correction factor for excess air, integrated sampling and analysis 
procedures of Method 3A or 3B of appendix A-2 to this part, ASTM D6522-
20, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (both 
incorporated by reference, see Sec.  60.17) to determine the oxygen 
concentration. The samples must be taken during the same time that the 
samples are taken for determining TOC concentration. You must correct 
the TOC concentration for percent oxygen as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.008

Where:

C<INF>c</INF> = TOC concentration, as propane, corrected to 3 
percent oxygen, parts per million by volume on a wet basis.
C<INF>m</INF> = TOC concentration, as propane, parts per million by 
volume on a wet basis.
%O<INF>2m</INF> = Concentration of oxygen, percent by volume as 
measured, wet.

    (5) You must conduct performance tests according to the schedule 
specified in paragraphs (b)(5)(i) through (iii) of this section.
    (i) You must conduct an initial performance test within 180 days 
after initial startup for your affected facility. You must submit the 
performance test results as required in Sec.  60.5420b(b)(12).
    (ii) You must conduct periodic performance tests for all control 
devices required to conduct initial performance tests. You must conduct 
the first periodic performance test no later than 60 months after the 
initial performance test required in paragraph (b)(5)(i) of this 
section. You must conduct subsequent periodic performance tests at 
intervals no longer than 60 months following the previous periodic 
performance test or whenever you desire to establish a new operating 
limit. If a control device is not operational at the time a performance 
test is due, you must conduct the performance test no later than 30 
calendar days after returning the control device to service. You must 
submit the periodic performance test results as specified in Sec.  
60.5420b(b)(12).
    (iii) If the initial performance test was conducted by the 
manufacturer under paragraph (d) of this section, you must conduct the 
first periodic performance test no later than 60 months after initial 
installation and startup of the control device. You must conduct 
subsequent periodic performance tests at intervals no longer than 60 
months following the previous periodic performance test. If a control 
device is not operational at the time a performance test is due, you 
must conduct the performance test no later than 30 calendar days after 
returning the control device to service. You must submit the periodic 
performance test results as specified in Sec.  60.5420b(b)(12).
    (c) Control device design analysis to meet the requirements of 
Sec.  60.5412b(a)(2). (1) For a condenser, the design analysis must 
include an analysis of the vent stream composition, constituent 
concentrations, flow rate, relative humidity, and temperature and must 
establish the design outlet organic compound concentration level, 
design average temperature of the condenser exhaust vent stream and the 
design average temperatures of the coolant fluid at the condenser inlet 
and outlet.
    (2) For a regenerable carbon adsorption system, the design analysis 
shall include the vent stream composition, constituent concentrations, 
flow rate, relative humidity and temperature and shall establish the 
design exhaust vent stream organic compound concentration level, 
adsorption cycle time, number and capacity of carbon beds, type and 
working capacity of activated carbon used for the carbon beds, design 
total regeneration stream flow over the period of each complete carbon 
bed

[[Page 17093]]

regeneration cycle, design carbon bed temperature after regeneration, 
design carbon bed regeneration time and design service life of the 
carbon.
    (3) For a nonregenerable carbon adsorption system, such as a carbon 
canister, the design analysis shall include the vent stream 
composition, constituent concentrations, flow rate, relative humidity 
and temperature and shall establish the design exhaust vent stream 
organic compound concentration level, capacity of the carbon bed, type 
and working capacity of activated carbon used for the carbon bed and 
design carbon replacement interval based on the total carbon working 
capacity of the control device and source operating schedule. In 
addition, these systems shall incorporate dual carbon canisters in case 
of emission breakthrough occurring in one canister.
    (4) If you and the Administrator do not agree on a demonstration of 
control device performance using a design analysis, then you must 
perform a performance test in accordance with the requirements of 
paragraph (b) of this section to resolve the disagreement. The 
Administrator may choose to have an authorized representative observe 
the performance test.
    (d) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph (d) applies to the 
performance testing of a combustion control device conducted by the 
device manufacturer. The manufacturer must demonstrate that a specific 
model of control device achieves the performance requirements in 
paragraph (d)(11) of this section by conducting a performance test as 
specified in paragraphs (d)(2) through (10) of this section. You must 
submit a test report for each combustion control device in accordance 
with the requirements in paragraph (d)(12) of this section.
    (2) Performance testing must consist of three 1-hour (or longer) 
test runs for each of the four firing rate settings specified in 
paragraphs (d)(2)(i) through (iv) of this section, making a total of 12 
test runs per test. Propene (propylene) gas must be used for the 
testing fuel. All fuel analyses must be performed by an independent 
third-party laboratory (not affiliated with the control device 
manufacturer or fuel supplier).
    (i) 90-100 percent of maximum design rate (fixed rate).
    (ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 100 percent of the maximum design 
rate. Hold at 100 percent for 5 minutes. In the 10- to 15-minute time 
range, incrementally ramp back down to 70 percent of the maximum design 
rate. Repeat three more times for a total of 60 minutes of sampling.
    (iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 70 percent of the maximum design 
rate. Hold at 70 percent for 5 minutes. In the 10- to 15-minute time 
range, incrementally ramp back down to 30 percent of the maximum design 
rate. Repeat three more times for a total of 60 minutes of sampling.
    (iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the 
minimum firing rate. During the first 5 minutes, incrementally ramp the 
firing rate to 30 percent of the maximum design rate. Hold at 30 
percent for 5 minutes. In the 10- to 15-minute time range, 
incrementally ramp back down to the minimum firing rate. Repeat three 
more times for a total of 60 minutes of sampling.
    (3) All models employing multiple enclosures must be tested 
simultaneously and with all burners operational. Results must be 
reported for each enclosure individually and for the average of the 
emissions from all interconnected combustion enclosures/chambers. 
Control device operating data must be collected continuously throughout 
the performance test using an electronic Data Acquisition System. A 
graphic presentation or strip chart of the control device operating 
data and emissions test data must be included in the test report in 
accordance with paragraph (d)(12) of this section. Inlet fuel meter 
data may be manually recorded provided that all inlet fuel data 
readings are included in the final report.
    (4) Inlet testing must be conducted as specified in paragraphs 
(d)(4)(i) and (ii) of this section.
    (i) The inlet gas flow metering system must be located in 
accordance with Method 2A of appendix A-1 of this part (or other 
approved procedure) to measure inlet gas flow rate at the control 
device inlet location. You must position the fitting for filling fuel 
sample containers a minimum of eight pipe diameters upstream of any 
inlet gas flow monitoring meter.
    (ii) Inlet flow rate must be determined using Method 2A to appendix 
A-1 of this part. Record the start and stop reading for each 60-minute 
THC test. Record the gas pressure and temperature at 5-minute intervals 
throughout each 60-minute test.
    (5) Inlet gas sampling must be conducted as specified in paragraphs 
(d)(5)(i) and (ii) of this section.
    (i) At the inlet gas sampling location, securely connect a fused 
silica-coated stainless steel evacuated canister fitted with a flow 
controller sufficient to fill the canister over a 3-hour period. 
Filling must be conducted as specified in paragraphs (d)(5)(i)(A) 
through (C) of this section.
    (A) Open the canister sampling valve at the beginning of each test 
run and close the canister at the end of each test run.
    (B) Fill one canister across the three test runs such that one 
composite fuel sample exists for each test condition.
    (C) Label the canisters individually and record sample information 
on a chain of custody form.
    (ii) Analyze each inlet gas sample using the methods in paragraphs 
(d)(5)(ii)(A) through (C) of this section. You must include the results 
in the test report required by paragraph (d)(12) of this section.
    (A) Hydrocarbon compounds containing between one and five atoms of 
carbon plus benzene using ASTM D1945-03(R2010) (incorporated by 
reference, see Sec.  60.17).
    (B) Hydrogen (H<INF>2</INF>), carbon monoxide (CO), carbon dioxide 
(CO<INF>2</INF>), nitrogen (N<INF>2</INF>), oxygen (O<INF>2</INF>) 
using ASTM D1945-03(R2010) (incorporated by reference, see Sec.  
60.17).
    (C) Higher heating value using ASTM D3588-98(R2003) or ASTM D4891-
89(R2006) (both incorporated by reference, see Sec.  60.17).
    (6) Outlet testing must be conducted in accordance with the 
criteria in paragraphs (d)(6)(i) through (v) of this section.
    (i) Sample and flow rate must be measured in accordance with 
paragraphs (d)(6)(i)(A) and (B) of this section.
    (A) The outlet sampling location must be a minimum of four 
equivalent stack diameters downstream from the highest peak flame or 
any other flow disturbance, and a minimum of one equivalent stack 
diameter upstream of the exit or any other flow disturbance. A minimum 
of two sample ports must be used.
    (B) Flow rate must be measured using Method 1 of appendix A-1 to 
this part for determining flow measurement traverse point location, and 
Method 2 of appendix A-1 to this part for measuring duct velocity. If 
low flow conditions are encountered (i.e., velocity pressure 
differentials less than 0.05 inches of water) during the performance 
test, a more sensitive manometer must be used to obtain an accurate 
flow profile.
    (ii) Molecular weight and excess air must be determined as 
specified in paragraph (d)(7) of this section.

[[Page 17094]]

    (iii) Carbon monoxide must be determined as specified in paragraph 
(d)(8) of this section.
    (iv) THC must be determined as specified in paragraph (d)(9) of 
this section.
    (v) Visible emissions must be determined as specified in paragraph 
(d)(10) of this section.
    (7) Molecular weight and excess air determination must be performed 
as specified in paragraphs (d)(7)(i) through (iii) of this section.
    (i) An integrated bag sample must be collected during the moisture 
test required by Method 4 of appendix A-3 to this part following the 
procedure specified in (d)(7)(i)(A) and (B) of this section. Analyze 
the bag sample using a gas chromatograph-thermal conductivity detector 
(GC-TCD) analysis meeting the criteria in paragraphs (d)(7)(i)(C) and 
(D) of this section.
    (A) Collect the integrated sample throughout the entire test and 
collect representative volumes from each traverse location.
    (B) Purge the sampling line with stack gas before opening the valve 
and beginning to fill the bag. Clearly label each bag and record sample 
information on a chain of custody form.
    (C) The bag contents must be vigorously mixed prior to the gas 
chromatograph analysis.
    (D) The GC-TCD calibration procedure in Method 3C of appendix A-2 
to this part must be modified as follows: For the initial calibration, 
triplicate injections of any single concentration must agree within 5 
percent of their mean to be valid. The calibration response factor for 
a single concentration re-check must be within 10 percent of the 
original calibration response factor for that concentration. If this 
criterion is not met, repeat the initial calibration using at least 
three concentration levels.
    (ii) Calculate and report the molecular weight of oxygen, carbon 
dioxide, methane and nitrogen in the integrated bag sample and include 
in the test report specified in paragraph (d)(12) of this section. 
Moisture must be determined using Method 4 of appendix A-3 to this 
part. Traverse both ports with the sampling train required by Method 4 
of appendix A-3 to this part during each test run. Ambient air must not 
be introduced into the integrated bag sample required by Method 3C of 
appendix A-2 to this part during the port change.
    (iii) Excess air must be determined using resultant data from the 
Method 3C tests and Method 3B of appendix A-2 to this part, equation 
3B-1 in Method 3B, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion 
only) (incorporated by reference, see Sec.  60.17).
    (8) Carbon monoxide must be determined using Method 10 of appendix 
A-4 to this part. Run the test simultaneously with Method 25A of 
appendix A-7 to this part using the same sampling points. An instrument 
range of 0-10 parts per million by volume-dry (ppmvd) is recommended.
    (9) Total hydrocarbon determination must be performed as specified 
by in paragraphs (d)(9)(i) through (vii) of this section.
    (i) Conduct THC sampling using Method 25A of appendix A-7 to this 
part, except that the option for locating the probe in the center 10 
percent of the stack is not allowed. The THC probe must be traversed to 
16.7 percent, 50 percent, and 83.3 percent of the stack diameter during 
each test run.
    (ii) A valid test must consist of three Method 25A tests, each no 
less than 60 minutes in duration.
    (iii) A 0 to 10 parts per million by volume-wet (ppmvw) (as 
propane) measurement range is preferred; as an alternative a 0 to 30 
ppmvw (as propane) measurement range may be used.
    (iv) Calibration gases must be propane in air and be certified 
through EPA-600/R-12/531--``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' (incorporated by 
reference, see Sec.  60.17).
    (v) THC measurements must be reported in terms of ppmvw as propane.
    (vi) THC results must be corrected to 3 percent CO<INF>2</INF>, as 
measured by Method 3C of appendix A-2 to this part. You must use the 
following equation for this diluent concentration correction:
[GRAPHIC] [TIFF OMITTED] TR08MR24.009

Where:

C<INF>meas</INF> = The measured concentration of the pollutant.
CO<INF>2meas</INF> = The measured concentration of the 
CO<INF>2</INF> diluent.
3 = The corrected reference concentration of CO<INF>2</INF> diluent.
C<INF>corr</INF> = The corrected concentration of the pollutant.

    (vii) Subtraction of methane or ethane from the THC data is not 
allowed in determining results.
    (10) Visible emissions must be determined using Method 22 of 
appendix A-7 to this part. The test must be performed continuously 
during each test run. A digital color photograph of the exhaust point, 
taken from the position of the observer and annotated with date and 
time, must be taken once per test run and the 12 photos included in the 
test report specified in paragraph (d)(12) of this section.
    (11)(i) The control device model tested must meet the criteria in 
paragraphs (d)(11)(i)(A) through (D) of this section. These criteria 
must be reported in the test report required by paragraph (d)(12) of 
this section.
    (A) Results from Method 22 of appendix A-7 to this part determined 
under paragraph (d)(10) of this section with no indication of visible 
emissions.
    (B) Average results from Method 25A of appendix A-7 to this part 
determined under paragraph (d)(9) of this section equal to or less than 
10.0 ppmvw THC as propane corrected to 3.0 percent CO<INF>2</INF>.
    (C) Average CO emissions determined under paragraph (d)(8) of this 
section equal to or less than 10 parts ppmvd, corrected to 3.0 percent 
CO<INF>2</INF>.
    (D) Excess air determined under paragraph (d)(7) of this section 
equal to or greater than 150 percent.
    (ii) The manufacturer must determine a minimum inlet gas flow rate 
above which each control device model must be operated to achieve the 
criteria in paragraph (d)(11)(iii) of this section. The manufacturer 
must determine a maximum inlet gas flow rate which must not be exceeded 
for each control device model to achieve the criteria in paragraph 
(d)(11)(iii) of this section. The minimum and maximum inlet gas flow 
rate must be included in the test report required by paragraph (d)(12) 
of this section.
    (iii) A manufacturer must demonstrate a destruction efficiency of 
at least 95.0 percent for THC, as propane. A control device model that 
demonstrates a

[[Page 17095]]

destruction efficiency of 95.0 percent for THC, as propane, will meet 
the control requirement for 95.0 percent destruction of VOC and methane 
required under this subpart.
    (12) The owner or operator of a combustion control device model 
tested under this paragraph (d)(12) must submit the information listed 
in paragraphs (d)(12)(i) through (vi) of this section for each test run 
in the test report required by this section in accordance with Sec.  
60.5420b(b)(13). Owners or operators who claim that any of the 
performance test information being submitted is confidential business 
information (CBI) must submit a complete file including information 
claimed to be CBI to the OAQPS CBI office. The preferred method to 
receive CBI is for it to be transmitted electronically using email 
attachments, File Transfer Protocol, or other online file sharing 
services. Electronic submissions must be transmitted directly to the 
OAQPS CBI Office at the email address <a href="/cdn-cgi/l/email-protection#f9969888898a9a9b90b99c8998d79e968f"><span class="__cf_email__" data-cfemail="432c2232333020212a032633226d242c35">[email protected]</span></a> and should 
include clear CBI markings and be flagged to the attention of the 
Leader, Measurement Policy Group. 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 <a href="/cdn-cgi/l/email-protection#7c131d0d0c0f1f1e153c190c1d521b130a"><span class="__cf_email__" data-cfemail="46292737363525242f0623362768212930">[email protected]</span></a> to request a file transfer link. 
If you cannot transmit the file electronically, you may send CBI 
information through the postal service to the following address: U.S. 
EPA, Attn: OAQPS Document Control Officer and Measurement Policy Group 
Leader, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 12055, 
RTP, North Carolina 27711. The mailed CBI material should be double 
wrapped and clearly marked. Any CBI markings should not show through 
the outer envelope. The same file with the CBI omitted must be 
submitted to <a href="/cdn-cgi/l/email-protection#420d2b2e1d232c261d0523311d1216020712036c050d14"><span class="__cf_email__" data-cfemail="93dcfaffccf2fdf7ccd4f2e0ccc3c7d3d6c3d2bdd4dcc5">[email protected]</span></a>.
    (i) A full schematic of the control device and dimensions of the 
device components.
    (ii) The maximum net heating value of the device.
    (iii) The test fuel gas flow range (in both mass and volume). 
Include the minimum and maximum allowable inlet gas flow rate.
    (iv) The air/stream injection/assist ranges, if used.
    (v) The test conditions listed in paragraphs (d)(12)(v)(A) through 
(O) of this section, as applicable for the tested model.
    (A) Fuel gas delivery pressure and temperature.
    (B) Fuel gas moisture range.
    (C) Purge gas usage range.
    (D) Condensate (liquid fuel) separation range.
    (E) Combustion zone temperature range. This is required for all 
devices that measure this parameter.
    (F) Excess air range.
    (G) Flame arrestor(s).
    (H) Burner manifold.
    (I) Continuous pilot flame indicator.
    (J) Pilot flame design fuel and calculated or measured fuel usage.
    (K) Tip velocity range.
    (L) Momentum flux ratio.
    (M) Exit temperature range.
    (N) Exit flow rate.
    (O) Wind velocity and direction.
    (vi) The test report must include all calibration quality 
assurance/quality control data, calibration gas values, gas cylinder 
certification, strip charts, or other graphic presentations of the data 
annotated with test times and calibration values.
    (e) Initial and continuous compliance for combustion control 
devices tested by the manufacturer in accordance with paragraph (d) of 
this section. This paragraph (e) applies to the demonstration of 
compliance for a combustion control device tested under the provisions 
in paragraph (d) of this section. Owners or operators must demonstrate 
that a control device achieves the performance criteria in paragraph 
(d)(11) of this section by installing a device tested under paragraph 
(d) of this section, complying with the criteria specified in 
paragraphs (e)(1) through (10) of this section, maintaining the records 
specified in Sec.  60.5420b(c)(11) and submitting the report specified 
in Sec.  60.5420b(b)(11)(v) and (13).
    (1) The inlet gas flow rate must be equal to or greater than the 
minimum inlet gas flow rate and equal to or less than the maximum inlet 
gas flow rate specified by the manufacturer.
    (2) A pilot or combustion flame must be present at all times of 
operation. An alert must be sent to the nearest control room whenever 
the pilot or combustion flame is unlit.
    (3) Devices must be operated with no visible emissions, except for 
periods not to exceed a total of 1 minute during any 15-minute period. 
A visible emissions test conducted according to section 11 of Method 22 
of appendix A-7 to this part must be performed at least once every 
calendar month, separated by at least 15 days between each test. The 
observation period shall be 15 minutes or once the amount of time 
visible emissions is present has exceeded 1 minute, whichever time 
period is less. Alternatively, you may conduct visible emissions 
monitoring according to Sec.  60.5417b(h).
    (4) Devices failing the visible emissions test must follow 
manufacturer's repair instructions, if available, or best combustion 
engineering practice as outlined in the unit inspection and maintenance 
plan, to return the unit to compliant operation. All repairs and 
maintenance activities for each unit must be recorded in a maintenance 
and repair log and must be available for inspection.
    (5) Following return to operation from maintenance or repair 
activity, each device must pass a visual observation according to 
Method 22 of appendix A-7 to this part as described in paragraph (e)(3) 
of this section or be monitored according to Sec.  60.5417b(h).
    (6) If the owner or operator operates a combustion control device 
model tested under this section, an electronic copy of the performance 
test results required by this section shall be submitted via email to 
<a href="/cdn-cgi/l/email-protection#f8b79194a799969ca7bf998ba7a8acb8bda8b9d6bfb7ae"><span class="__cf_email__" data-cfemail="fab59396a59b949ea5bd9b89a5aaaebabfaabbd4bdb5ac">[email protected]</span></a> unless the test results for that model of 
combustion control device are posted at the following website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
    (7) Ensure that each enclosed combustion device is maintained in a 
leak free condition.
    (8) Operate each control device following the manufacturer's 
written operating instructions, procedures and maintenance schedule to 
ensure good air pollution control practices for minimizing emissions.
    (9) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417b(a) and (c) through (i).
    (10) Comply with the applicable NHV limit specified in Sec.  
60.5412b(a)(1)(iv).


Sec.  60.5415b   How do I demonstrate continuous compliance with the 
standards for each of my affected facilities?

    (a) Well completion standards for well affected facility. For each 
well completion operation at your well affected facility, you must 
demonstrate continuous compliance with the requirements of Sec.  
60.5375b by submitting the annual report required by Sec.  
60.5420b(b)(1) and (2) and maintaining the records for each completion 
operation specified in Sec.  60.5420b(c)(1).
    (b) Gas well liquids unloading standards for well affected 
facility. For each well liquids unloading operation at your well 
affected facility, you must demonstrate continuous compliance with the 
requirements of Sec.  60.5376b by submitting the annual report 
information specified in Sec.  60.5420b(b)(1) and (3) and maintaining 
the records for each well liquids

[[Page 17096]]

unloading event specified in Sec.  60.5420b(c)(2). For each gas well 
liquids unloading well affected facility that complies with the 
requirements of Sec.  60.5376b(g), you must route emissions to a 
control device through a closed vent system and continuously comply 
with the closed vent requirements of Sec.  60.5416b. You also must 
comply with the requirements specified in paragraph (f) of this section 
and maintain the records in Sec.  60.5420b(c)(8), (10) and (12).
    (c) Associated gas well standards for well affected facility. For 
each associated gas well, you must demonstrate continuous compliance 
with the requirements of Sec.  60.5377b by submitting the reports 
required by Sec.  60.5420b(b)(1) and (4) and maintaining the records 
specified in Sec.  60.5420b(c)(3). For each associated gas well that 
complies with the requirements of Sec.  60.5377b(d) or (f), you must 
route emissions to a control device through a closed vent system and 
continuously comply with the closed vent requirements of Sec.  
60.5416b. You also must comply with the requirements specified in 
paragraph (f) of this section and maintain the records in Sec.  
60.5420b(c)(8), (10) and (12).
    (d) Centrifugal compressor affected facility. For each wet seal 
centrifugal compressor affected facility complying with Sec.  
60.5380b(a)(1) and (2), or with Sec.  60.5380b(a)(3) by routing 
emissions to a control device or to a process, you must demonstrate 
continuous compliance according to paragraph (d)(1) and paragraphs 
(d)(3) and (4) of this section. For each self-contained wet seal 
centrifugal compressor complying with the requirements in Sec.  
60.5380b(a)(4), you must demonstrate continuous compliance according to 
paragraphs (d)(2) through (4) of this section. For each centrifugal 
compressor on the Alaska North Slope equipped with sour seal oil 
separator and capture system, complying with the requirements of Sec.  
60.5380b(a)(5), you must demonstrate continuous compliance according to 
paragraphs (d)(2) through (4) of this section. For each dry seal 
centrifugal compressor complying with the requirements in Sec.  
60.5380b(a)(6), you must demonstrate continuous compliance according to 
paragraphs (d)(2) through (4) of this section.
    (1) For each wet seal centrifugal compressor affected facility 
complying by routing emissions to a control device or to a process, you 
must operate the wet seal emissions collection system to route 
emissions to a control device or a process through a closed vent system 
and continuously comply with the cover and closed vent requirements of 
Sec.  60.5416b. If you comply with Sec.  60.5380b(a)(2) by using a 
control device, you also must comply with the requirements in paragraph 
(f) of this section.
    (2) You must maintain volumetric flow rate at or below the flow 
rates specified in Sec.  60.5380b(a)(5) for you centrifugal compressor 
and you must conduct the required volumetric flow rate measurement of 
your self-contained wet seal centrifugal compressor, Alaska North Slope 
centrifugal compressor equipped with sour seal oil separator and 
capture system, or dry seal centrifugal compressor in accordance with 
Sec.  60.5380b(a)(6) on or before 8,760 hours of operation after your 
last volumetric flow rate measurement which demonstrates compliance 
with the volumetric flow rate specified in Sec.  60.5380b(a)(5) for you 
centrifugal compressor.
    (3) You must submit the annual reports as required in Sec.  
60.5420b(b)(1), (5), and (11)(i) through (iv), as applicable.
    (4) You must maintain records as required in Sec.  60.5420b(c)(4), 
(8) through (10), and (12), as applicable.
    (e) Pump affected facility. To demonstrate continuous compliance 
with the GHG and VOC standards for your pump affected facility as 
required by Sec.  60.5393b, you must comply with paragraphs (e)(1) 
through (3) of this section.
    (1) For pump affected facilities complying with the requirements of 
Sec.  60.5393b(a) by routing emissions to a process, and for pump 
affected facilities complying with the requirements of Sec.  
60.5393b(b)(2), or (3), you must continuously comply with the closed 
vent requirements of Sec.  60.5416b. If you comply with Sec.  
60.5393b(b)(3), you also must comply with the requirements in paragraph 
(f) of this section.
    (2) You must submit the annual reports for your pump affected 
facility as required in Sec.  60.5420b(b)(1), (10), and (11)(i) through 
(iv), as applicable.
    (3) You must maintain the records for your pump affected facility 
as specified in Sec.  60.5420b(c)(8), (10), (12), and (15), as 
applicable.
    (f) Additional continuous compliance requirements for well, 
centrifugal compressor, reciprocating compressor, process controllers 
in Alaska, storage vessel, process unit equipment, or pump affected 
facilities. For each associated gas well, each gas well that conducts 
liquids unloading, each centrifugal compressor affected facility, each 
reciprocating compressor affected facility, each process controller 
affected facility in Alaska, each storage vessel affected facility, 
each process unit equipment affected facility, and each pump affected 
facility referenced to this paragraph from either paragraph (b), (c), 
(d)(1), (e)(1), (g), (h)(2)(iv), (i) or (j) of this section, you must 
also install monitoring systems as specified in Sec.  60.5417b, 
demonstrate continuous compliance according to paragraph (f)(1) of this 
section, maintain the records in paragraph (f)(2) of this section, and 
comply with the reporting requirements specified in paragraph (f)(3) of 
this section.
    (1) You must demonstrate continuous compliance with the control 
device performance requirements of Sec.  60.5412b(a) using the 
procedures specified in paragraphs (f)(1)(i) through (viii) of this 
section and conducting the monitoring as required by Sec.  60.5417b. If 
you use a condenser as the control device to achieve the requirements 
specified in Sec.  60.5412b(a)(2), you may demonstrate compliance 
according to paragraph (f)(1)(ix) of this section. You may switch 
between compliance with paragraphs (f)(1)(i) through (viii) of this 
section and compliance with paragraph (f)(1)(ix) of this section only 
after at least 1 year of operation in compliance with the selected 
approach. You must provide notification of such a change in the 
compliance method in the next annual report, following the change. If 
you use an enclosed combustion device or a flare as the control device, 
you must also conduct the monitoring required in paragraph (f)(1)(x) of 
this section. If you use an enclosed combustion device or flare using 
an alternative test method approved under Sec.  60.5412b(d), you must 
use the procedures in paragraph (f)(1)(xi) of this section in lieu of 
the procedures in paragraphs (f)(1)(i) through (viii) of this section, 
but you must still conduct the monitoring required in paragraph 
(f)(1)(x) of this section.
    (i) You must operate below (or above) the site-specific maximum (or 
minimum) parameter value established according to the requirements of 
Sec.  60.5417b(f)(1). For flares, you must operate above the limits 
specified in paragraphs (f)(1)(vii)(B) of this section.
    (ii) You must calculate the average of the applicable monitored 
parameter in accordance with Sec.  60.5417b(e).
    (iii) Compliance with the operating parameter limit is achieved 
when the average of the monitoring parameter value calculated under 
paragraph (f)(1)(ii) of this section is either equal to or greater than 
the minimum parameter value or equal to or less than the maximum 
parameter value established under paragraph (f)(1)(i) of this section. 
When performance testing of a

[[Page 17097]]

combustion control device is conducted by the device manufacturer as 
specified in Sec.  60.5413b(d), compliance with the operating parameter 
limit is achieved when the criteria in Sec.  60.5413b(e) are met.
    (iv) You must operate the continuous monitoring system required in 
Sec.  60.5417b(a) at all times the affected source is operating, except 
for periods of monitoring system malfunctions, repairs associated with 
monitoring system malfunctions and required monitoring system quality 
assurance or quality control activities, including, as applicable, 
system accuracy audits and required zero and span adjustments. A 
monitoring system malfunction is any sudden, infrequent, not reasonably 
preventable failure of the monitoring system to provide valid data. 
Monitoring system failures that are caused in part by poor maintenance 
or careless operation are not malfunctions. You are required to 
complete monitoring system repairs in response to monitoring system 
malfunctions and to return the monitoring system to operation as 
expeditiously as practicable.
    (v) You may not use data recorded during monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
or required monitoring system quality assurance or control activities 
in calculations used to report emissions or operating levels. You must 
use all the data collected during all other required data collection 
periods to assess the operation of the control device and associated 
control system.
    (vi) Failure to collect required data is a deviation of the 
monitoring requirements.
    (vii) If you use an enclosed combustion device to meet the 
requirements of Sec.  60.5412b(a)(1) and you demonstrate compliance 
using the test procedures specified in Sec.  60.5413b(b), or you use a 
flare designed and operated in accordance with Sec.  60.5412b(a)(3), 
you must comply with the applicable requirements in paragraphs 
(f)(1)(vii)(A) through (E) of this section.
    (A) For each enclosed combustion device which is not a catalytic 
vapor incinerator and for each flare, you must comply with the 
requirements in paragraphs (f)(1)(vii)(A)(1) through (4) of this 
section.
    (1) A pilot or combustion flame must be present at all times of 
operation. An alert must be sent to the nearest control room whenever 
the pilot or combustion flame is unlit.
    (2) Devices must be operated with no visible emissions, except for 
periods not to exceed a total of 1 minute during any 15-minute period. 
A visible emissions test conducted according to section 11 of Method 22 
of appendix A-7 to this part, must be performed at least once every 
calendar month, separated by at least 15 days between each test. The 
observation period shall be 15 minutes or once the amount of time 
visible emissions is present has exceeded 1 minute, whichever time 
period is less. Alternatively, you may conduct visible emissions 
monitoring according to Sec.  60.5417b(h).
    (3) Devices failing the visible emissions test must follow 
manufacturer's repair instructions, if available, or best combustion 
engineering practice as outlined in the unit inspection and maintenance 
plan, to return the unit to compliant operation. All repairs and 
maintenance activities for each unit must be recorded in a maintenance 
and repair log and must be available for inspection.
    (4) Following return to operation from maintenance or repair 
activity, each device must pass a Method 22 of appendix A-7 to this 
part visual observation as described in paragraph (f)(1)(vii)(D) of 
this section or be monitored according to Sec.  60.5417b(h).
    (B) For flares, you must comply with the requirements in paragraphs 
(f)(1)(vii)(B)(1) through (6) of this section.
    (1) For unassisted flares, maintain the NHV of the gas sent to the 
flare at or above 200 Btu/scf.
    (2) If you use a pressure assisted flare, maintain the NHV of gas 
sent to the flare at or above 800 Btu/scf.
    (3) For steam-assisted and air-assisted flares, maintain the 
NHV<INF>cz</INF> at or above 270 Btu/scf.
    (4) For flares with perimeter assist air, maintain the 
NHV<INF>dil</INF> at or above 22 Btu/sqft. If the only assist air 
provided to the flare is perimeter assist air intentionally entrained 
in lower and/or upper steam at the flare tip and the effective diameter 
is 9 inches or greater, you are not required to comply with the 
NHV<INF>dil</INF> limit.
    (5) Unless you use a pressure-assisted flare, maintain the flare 
tip velocity below the applicable limits in Sec.  60.18(b).
    (6) Maintain the total gas flow to the flare above the minimum 
inlet gas flow rate. The minimum inlet gas flow rate is established 
based on manufacturer recommendations.
    (C) For enclosed combustion devices for which, during the 
performance test conducted under Sec.  60.5413b(b), the combustion zone 
temperature is not an indicator of destruction efficiency, you must 
comply with the requirements in paragraphs (f)(1)(vii)(C)(1) through 
(5) of this section, as applicable.
    (1) Maintain the total gas flow to the enclosed combustion device 
at or above the minimum inlet gas flow rate and at or below the maximum 
inlet flow rate for the enclosed combustion device established in 
accordance with Sec.  60.5417b(f).
    (2) For unassisted enclosed combustion devices, maintain the NHV of 
the gas sent to the enclosed combustion device at or above 200 Btu/scf.
    (3) For enclosed combustion devices that use pressure-assisted 
burner tips to promote mixing at the burner tip, maintain the NHV of 
the gas sent to the enclosed combustion device at or above 800 Btu/scf.
    (4) For steam-assisted and air-assisted enclosed combustion 
devices, maintain the NHV<INF>cz</INF> at or above 270 Btu/scf.
    (5) For enclosed combustion devices with perimeter assist air, 
maintain the NHV<INF>dil</INF> at or above 22 Btu/sqft. If the only 
assist air provided to the enclosed combustion device is perimeter 
assist air intentionally entrained in lower and/or upper steam at the 
flare tip and the effective diameter is 9 inches or greater, you are 
not required to comply with the NHV<INF>dil</INF> limit.
    (D) For enclosed combustion devices for which, during the 
performance test conducted under Sec.  60.5413b(b), the combustion zone 
temperature is demonstrated to be an indicator of destruction 
efficiency, you must comply with the requirements in paragraphs 
(f)(1)(vii)(D)(1) and (2) of this section.
    (1) Maintain the temperature at or above the minimum temperature 
established during the most recent performance test. The minimum 
temperature limit established during the most recent performance test 
is the average temperature recorded during each test run, averaged 
across the 3 test runs (average of the test run averages).
    (2) Maintain the total gas flow to the enclosed combustion device 
at or above the minimum inlet gas flow rate and at or below the maximum 
inlet flow rate for the enclosed combustion device established in 
accordance with Sec.  60.5417b(f).
    (E) For catalytic vapor incinerators you must operate the catalytic 
vapor incinerator at or above the minimum temperature of the catalyst 
bed inlet and at or above the minimum temperature differential between 
the catalyst bed inlet and the catalyst bed outlet established in 
accordance with Sec.  60.5417b(f).
    (viii) If you use a carbon adsorption system as the control device 
to meet the requirements of Sec.  60.5412b(a)(2), you

[[Page 17098]]

must demonstrate compliance by the procedures in paragraphs 
(f)(1)(viii)(A) and (B) of this section, as applicable.
    (A) If you use a regenerative-type carbon adsorption system, you 
must comply with paragraphs (f)(1)(viii)(A)(1) through (4) of this 
section.
    (1) You must maintain the average regenerative mass flow or 
volumetric flow to the carbon adsorber during each bed regeneration 
cycle above the limit established in in accordance with Sec.  
60.5413b(c)(2).
    (2) You must maintain the average carbon bed temperature above the 
temperature limit established in accordance with Sec.  60.5413b(c)(2) 
during the carbon bed steaming cycle and below the carbon bed 
temperature established in in accordance with Sec.  60.5413b(c)(2) 
after the regeneration cycle.
    (3) You must check the mechanical connections for leakage at least 
every month, and you must perform a visual inspection at least every 3 
months of all components of the continuous parameter monitoring system 
for physical and operational integrity and all electrical connections 
for oxidation and galvanic corrosion if your continuous parameter 
monitoring system is not equipped with a redundant flow sensor.
    (4) You must replace all carbon in the carbon adsorption system 
with fresh carbon on a regular, predetermined time interval that is no 
longer than the carbon service life established according to Sec.  
60.5413b(c)(2).
    (B) If you use a nonregenerative-type carbon adsorption system, you 
must replace all carbon in the control device with fresh carbon on a 
regular, predetermined time interval that is no longer than the carbon 
service life established according to Sec.  60.5413b(c)(3).
    (ix) If you use a condenser as the control device to achieve the 
percent reduction performance requirements specified in Sec.  
60.5412b(a)(2), you must demonstrate compliance using the procedures in 
paragraphs (f)(1)(ix)(A) through (E) of this section.
    (A) You must establish a site-specific condenser performance curve 
according to Sec.  60.5417b(f)(2).
    (B) You must calculate the daily average condenser outlet 
temperature in accordance with Sec.  60.5417b(e).
    (C) You must determine the condenser efficiency for the current 
operating day using the daily average condenser outlet temperature 
calculated under paragraph (f)(1)(ix)(B) of this section and the 
condenser performance curve established under paragraph (f)(1)(ix)(A) 
of this section.
    (D) Except as provided in paragraphs (f)(1)(ix)(D)(1) and (2) of 
this section, at the end of each operating day, you must calculate the 
365-day rolling average TOC emission reduction, as appropriate, from 
the condenser efficiencies as determined in paragraph (f)(1)(ix)(C) of 
this section.
    (1) After the compliance dates specified in Sec.  60.5370b(a), if 
you have less than 120 days of data for determining average TOC 
emission reduction, you must calculate the average TOC emission 
reduction for the first 120 days of operation after the compliance 
date. You have demonstrated compliance with the overall 95.0 percent 
reduction requirement if the 120-day average TOC emission reduction is 
equal to or greater than 95.0 percent.
    (2) After 120 days and no more than 364 days of operation after the 
compliance date specified in Sec.  60.5370b(a), you must calculate the 
average TOC emission reduction as the TOC emission reduction averaged 
over the number of days between the current day and the applicable 
compliance date. You have demonstrated compliance with the overall 95.0 
percent reduction requirement if the average TOC emission reduction is 
equal to or greater than 95.0 percent.
    (E) If you have data for 365 days or more of operation, you have 
demonstrated compliance with the TOC emission reduction if the rolling 
365-day average TOC emission reduction calculated in paragraph 
(f)(1)(ix)(D) of this section is equal to or greater than 95.0 percent.
    (x) During each inspection conducted using an OGI camera under 
Sec.  60.5397b and during each periodic screening event or each 
inspection conducted using an OGI camera under Sec.  60.5398b, you must 
observe each enclosed combustion device and flare to determine if it is 
operating properly. You must determine whether there is a flame present 
and whether any uncontrolled emissions from the control device are 
visible with the OGI camera or the technique used to conduct the 
periodic screening event. During each inspection conducted under Sec.  
60.5397b using AVO, you must observe each enclosed combustion device 
and flare to determine if it is operating properly. Visually confirm 
that the pilot or combustion flame is lit and that the pilot or 
combustion flame is operating properly.
    (xi) If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412b(d), you must 
comply with paragraphs (f)(1)(xi)(A) through (E) of this section.
    (A) You must maintain the combustion efficiency at or above 95.0 
percent. Alternatively, if the alternative test method does not 
directly monitor combustion efficiency, you must comply with the 
applicable requirements in paragraphs (f)(1)(xi)(A)(1) and (2) of this 
section.
    (1) Maintain the NHV<INF>cz</INF> at or above 270 Btu/scf.
    (2) For flares or enclosed combustion devices with perimeter assist 
air, maintain the NHV<INF>dil</INF> at or above 22 Btu/sqft. If the 
only assist air provided to the flare or enclosed combustion device is 
perimeter assist air intentionally entrained in lower and/or upper 
steam at the flare tip and the effective diameter is 9 inches or 
greater, you are only required to comply with the NHV<INF>cz</INF> 
limit specified in paragraph (f)(1)(xi)(A)(1) of this section.
    (B) You must calculate the value of the applicable monitored 
metric(s) in accordance with the approved alternative test method. 
Compliance with the limit is achieved when the calculated values are 
within the range specified in paragraph (f)(1)(xi)(A) of this section.
    (C) You must conduct monitoring using the alternative test method 
at all times the affected source is operating, except for periods of 
monitoring system malfunctions, repairs associated with monitoring 
system malfunctions and required monitoring system quality assurance or 
quality control activities, including, as applicable, system accuracy 
audits and required zero and span adjustments. A monitoring system 
malfunction is any sudden, infrequent, not reasonably preventable 
failure of the monitoring system to provide valid data. Monitoring 
system failures that are caused in part by poor maintenance or careless 
operation are not malfunctions. You are required to complete monitoring 
system repairs in response to monitoring system malfunctions and to 
return the monitoring system to operation as expeditiously as 
practicable.
    (D) You may not use data recorded during monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
or required monitoring system quality assurance or control activities 
in calculations used to report values to demonstrate compliance with 
the limits specified in paragraph (f)(1)(xi)(A) of this section. You 
must use all the data collected during all other required data 
collection periods to assess the operation of the control device and 
associated control system.

[[Page 17099]]

    (E) Failure to collect required data is a deviation of the 
monitoring requirements.
    (2) You must maintain the records as specified in Sec.  
60.5420b(c)(11) and (13).
    (3) You must comply with the reporting requirements in Sec.  
60.5420b(b)(11) through (13).
    (g) Reciprocating compressor affected facility. For each 
reciprocating compressor affected facility complying with Sec.  
60.5385b(a) through (c), you must demonstrate continuous compliance 
according to paragraphs (g)(1), (5), and (6) of this section. For each 
reciprocating compressor affected facility complying with Sec.  
60.5385b(d)(1) or (2), you must demonstrate continuous compliance 
according to paragraphs (g)(2), (5) and (6) of this section. For each 
reciprocating compressor affected facility complying with Sec.  
60.5385b(d)(3), you must demonstrate continuous compliance according to 
paragraphs (g)(3) through (6) of this section.
    (1) You must maintain the volumetric flow rate at or below 2 scfm 
per cylinder (or at or below the combined volumetric flow rate 
determined by multiplying the number of cylinders by 2 scfm), and you 
must conduct the required volumetric flow rate measurement of your 
reciprocating compressor rod packing vents in accordance with Sec.  
60.5385b(b) on or before 8,760 hours of operation after your last 
volumetric flow rate measurement which demonstrated compliance with the 
applicable volumetric flow rate.
    (2) You must operate the rod packing emissions collection system to 
route emissions to a control device or to a process through a closed 
vent system and continuously comply with the cover and closed vent 
requirements of Sec.  60.5416b. If you comply with Sec.  60.5385b(d) by 
using a control device, you also must comply with the requirements in 
paragraph (f) of this section.
    (3) You must continuously monitor the number of hours of operation 
for each reciprocating compressor affected facility since initial 
startup, since May 7, 2024, since the previous flow rate measurement, 
or since the date of the most recent reciprocating compressor rod 
packing replacement, whichever date is latest.
    (4) You must replace the reciprocating compressor rod packing on or 
before the total number of hours of operation reaches 8,760 hours.
    (5) You must submit the annual reports as required in Sec.  
60.5420b(b)(1), (6), and (11)(i) through (iv), as applicable.
    (6) You must maintain records as required in Sec.  60.5420b(c)(5), 
(8) through (10), and (12), as applicable.
    (h) Process controller affected facility. To demonstrate continuous 
compliance with GHG and VOC emission standards for your process 
controller affected facility as required by Sec.  60.5390b, you must 
comply with paragraphs (h)(1) through (4) of this section, as 
applicable.
    (1) You must demonstrate that your process controller affected 
facility does not emit any VOC or methane to the atmosphere by meeting 
the requirements of paragraphs (h)(1)(i) or (ii) of this section.
    (i) If you comply by routing the emissions to a process, you must 
comply with the closed vent system inspection and monitoring 
requirements of Sec.  60.5416b.
    (ii) If you comply by using a self-contained natural gas-driven 
process controller, you must conduct the no identifiable emissions 
inspections required by Sec.  60.5416b(b).
    (2) For each process controller affected facility located at a site 
in Alaska that does not have access to electrical power and that 
complies by reducing methane and VOC emissions from all controllers in 
the process controller affected facility by 95.0 percent in accordance 
with Sec.  60.5390b(b)(3), you must comply with the closed vent 
requirements of Sec.  60.5416b and the requirements in paragraph (f) of 
this section for the control device.
    (3) You must submit the annual report for your process controller 
as required in Sec.  60.5420b(b)(1), (7), and (11)(i) through (iv), as 
applicable.
    (4) You must maintain the records as specified in Sec.  
60.5420b(c)(6), (8), (10), and (12) for each process controller 
affected facility, as applicable.
    (i) Storage vessel affected facility. For each storage vessel 
affected facility, you must demonstrate continuous compliance with the 
requirements of Sec.  60.5395b according to paragraphs (i)(1) through 
(10) of this section, as applicable.
    (1) For each storage vessel affected facility complying with the 
requirements of Sec.  60.5395b(a)(2), you must demonstrate continuous 
compliance according to paragraphs (i)(5), (9) and (10) of this 
section.
    (2) For each storage vessel affected facility complying with the 
requirements of Sec.  60.5395b(a)(3), you must demonstrate continuous 
compliance according to paragraphs (i)(2)(i), (ii), or (iii) of this 
section, as applicable, and (i)(9) and (10) of this section.
    (i) You must maintain the uncontrolled actual VOC emissions at less 
than 4 tpy and the uncontrolled actual methane emissions at less than 
14 tpy from the storage vessel affected facility.
    (ii) You must comply with paragraph (i)(5) of this section as soon 
as liquids from the well are routed to the storage vessel affected 
facility following fracturing or refracturing according to the 
requirements of Sec.  60.5395b(a)(3)(i).
    (iii) You must comply with paragraph (i)(5) of this section within 
30 days of the monthly determination according to the requirements of 
Sec.  60.5395b(a)(3)(ii), where the monthly emissions determination 
indicates that VOC emissions from your storage vessel affected facility 
increase to 4 tpy or greater and the increase is not associated with 
fracturing or refracturing of a well feeding the storage vessel 
affected facility.
    (3) For each storage vessel affected facility or portion of a 
storage vessel affected facility removed from service, you must 
demonstrate compliance with the requirements of Sec.  60.5395b(c)(1) by 
complying with paragraphs (i)(6), (7), (9), and (10) of this section.
    (4) For each storage vessel affected facility or portion of a 
storage vessel affected facility returned to service, you must 
demonstrate compliance with the requirements of Sec.  60.5395b(c)(1) by 
complying with paragraphs (i)(8) through (10) of this section.
    (5) For each storage vessel affected facility, you must comply with 
paragraphs (i)(5)(i) and (ii) of this section.
    (i) You must reduce VOC emissions as specified in Sec.  
60.5395b(a)(2).
    (ii) For each control device installed to meet the requirements of 
Sec.  60.5395b(a)(2), you must demonstrate continuous compliance with 
the performance requirements of Sec.  60.5412b for each storage vessel 
affected facility using the procedure specified in paragraphs 
(i)(5)(ii)(A) and (i)(5)(ii)(B) of this section. When routing emissions 
to a process, you must demonstrate continuous compliance as specified 
in paragraph (i)(5)(ii)(A) of this section.
    (A) You must comply with Sec.  60.5416b for each cover and closed 
vent system.
    (B) You must comply with the requirements specified in paragraph 
(f) of this section.
    (6) You must completely empty and degas each storage vessel, such 
that each storage vessel no longer contains crude oil, condensate, 
produced water or intermediate hydrocarbon liquids. For a portion of a 
storage vessel affected facility to be removed from service, you must 
completely empty and degas the

[[Page 17100]]

storage vessel(s), such that the storage vessel(s) no longer contains 
crude oil, condensate, produced water, or intermediate hydrocarbon 
liquids. A storage vessel where liquid is left on walls, as bottom 
clingage, or in pools due to floor irregularity is considered to be 
completely empty.
    (7) You must disconnect the storage vessel(s) from the tank battery 
by isolating the storage vessel(s) from the tank battery such that the 
storage vessel(s) is no longer manifolded to the tank battery by liquid 
or vapor transfer.
    (8) You must determine the affected facility status of a storage 
vessel returned to service as provided in Sec.  60.5365b(e)(6).
    (9) You must submit the annual reports as required by Sec.  
60.5420b(b)(1), (8), and (11)(i) through (iv).
    (10) You must maintain the records as required by Sec.  
60.5420b(c)(7) through (10) and (c)(12), as applicable.
    (j) Process unit equipment affected facility. For each process unit 
equipment affected facility, you must demonstrate continuous compliance 
with the requirements of Sec.  60.5400b according to paragraphs (j)(1) 
through (4) and(11) through (15) of this section, unless you meet and 
comply with the exception in Sec.  60.5402b(b), (e), or (f) or meet the 
exemption in Sec.  60.5402b(c). Alternatively, if you comply with the 
GHG and VOC standards for process unit affected facilities using the 
standards in Sec.  60.5401b, you must comply with paragraphs (j)(5) 
through (15) of this section, unless you meet the exemption in Sec.  
60.5402b(b) or (c) or the exception in Sec.  60.5402b(e) and (f).
    (1) You must conduct monitoring for each pump in light liquid 
service, pressure relief device in gas/vapor service, valve in gas/
vapor and light liquid service and connector in gas/vapor and light 
liquid service as required by Sec.  60.5400b(b).
    (2) You must conduct monitoring as required by Sec.  60.5400b(c) 
for each pump in light liquid service.
    (3) You must conduct monitoring as required by Sec.  60.5400b(d) 
for each pressure relief device in gas/vapor service.
    (4) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec.  60.5400b(e).
    (5) You must conduct monitoring for each pump in light liquid 
service as required by Sec.  60.5401b(b).
    (6) You must conduct monitoring for each pressure relief device in 
gas/vapor service as required by Sec.  60.5401b(c).
    (7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec.  60.5401b(d).
    (8) You must conduct monitoring for each valve in gas/vapor or 
light liquid service as required by Sec.  60.5401b(f).
    (9) You must conduct monitoring for each pump, valve, and connector 
in heavy liquid service and each pressure relief device in light liquid 
or heavy liquid service as required by Sec.  60.5401b(g).
    (10) You must conduct monitoring for each connector in gas/vapor or 
light liquid service as required by Sec.  60.5401b(h).
    (11) You must collect emissions and meet the closed vent system 
requirements as required by Sec.  60.5416b for each pump equipped with 
a dual mechanical seal system that degasses the barrier fluid reservoir 
to a process or a control device, each pump which captures and 
transports leakage from the seal or seals to a process or control 
device, or each pressure relief device which captures and transports 
leakage through the pressure relief device to a process or control 
device.
    (12) You comply with the requirements specified in paragraph (f) of 
this section.
    (13) You must tag and repair each identified leak as required in 
Sec.  60.5400(h) or Sec.  60.5401b(i), as applicable.
    (14) You must submit semiannual reports as required by Sec.  
60.5422b and the annual reports in Sec.  60.5420b(b)(11)(i) through 
(iv), as applicable.
    (15) You must maintain the records specified by Sec.  
60.5420b(c)(8), (c)(10), and (c)(12) as applicable and Sec.  60.5421b.
    (k) Sweetening unit affected facility. For each sweetening unit 
affected facility, you must demonstrate continuous compliance with the 
requirements of Sec.  60.5405b(b) according to paragraphs (k)(1) 
through (10) of this section.
    (1) You must determine the minimum required continuous reduction 
efficiency of SO<INF>2</INF> emissions (Z<INF>c</INF>) as required by 
Sec.  60.5406b(b).
    (2) You must determine the emission reduction efficiency (R) 
achieved by your sulfur reduction technology using the procedures in 
Sec.  60.5406b(c)(1) through (c)(4).
    (3) You must demonstrate compliance with the standard at Sec.  
60.5405b(b) by comparing the minimum required sulfur dioxide emission 
reduction efficiency (Z<INF>c</INF>) to the emission reduction 
efficiency achieved by the sulfur recovery technology (R), where R must 
be greater than or equal to Z<INF>c</INF>.
    (4) You must calibrate, maintain, and operate monitoring devices or 
perform measurements to determine the accumulation of sulfur product, 
the H<INF>2</INF>S concentration, the average acid gas flow rate, and 
the sulfur feed rate in accordance with Sec.  60.5407b(a).
    (5) You must determine the required SO<INF>2</INF> emissions 
reduction efficiency each 24-hour period in accordance with Sec.  
60.5407b(a), Sec.  60.5407b(d), and Sec.  60.5407b(e), as applicable.
    (6) You must calibrate, maintain, and operate monitoring devices 
and continuous emission monitors in accordance with Sec.  60.5407b(b), 
(f), and (g), if you use an oxidation control system or a reduction 
control system followed by an incineration device.
    (7) You must continuously operate the incineration device, if you 
use an oxidation control system or a reduction control system followed 
by an incineration device.
    (8) You must calibrate, maintain, and operate a continuous 
monitoring system to measure the emission rate of reduced sulfur 
compounds in accordance with Sec.  60.5407b(c), (f), and (g), if you 
use a reduction control system not followed by an incineration device.
    (9) You must submit the reports as required by Sec.  60.5423b(b) 
and (d).
    (10) You must maintain the records as required by Sec.  
60.5423b(a), (e), and (f), as applicable.
    (l) Continuous compliance. For each fugitive emissions components 
affected facility, you must demonstrate continuous compliance with the 
requirements of Sec.  60.5397b(a) according to paragraphs (l)(1) 
through (4) of this section.
    (1) You must conduct periodic monitoring surveys as required in 
Sec.  60.5397b(e) and (g).
    (2) You must repair each identified source of fugitive emissions as 
required in Sec.  60.5397b(h).
    (3) You must submit annual reports for fugitive emissions 
components affected facilities as required in Sec.  60.5420b(b)(1) and 
(9).
    (4) You must maintain records as specified in Sec.  
60.5420b(c)(16).


Sec.  60.5416b   What are the initial and continuous cover and closed 
vent system inspection and monitoring requirements?

    For each closed vent system and cover at your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, storage 
vessel, and process unit equipment affected facilities, you must comply 
with the applicable requirements of paragraphs (a) and (b) of this 
section. Each self-contained natural gas process controller must comply 
with paragraph (b) of this section.
    (a) Inspections for closed vent systems, covers, and bypass 
devices. If

[[Page 17101]]

you install a control device or route emissions to a process, you must 
inspect each closed vent system according to the procedures and 
schedule specified in paragraphs (a)(1) and (2) of this section, 
inspect each cover according to the procedures and schedule specified 
in paragraph (a)(3) of this section, and inspect each bypass device 
according to the procedures of paragraph (a)(4) of this section, except 
as provided in paragraphs (b)(6) and (7) of this section.
    (1) For each closed vent system joint, seam, or other connection 
that is permanently or semi-permanently sealed (e.g., a welded joint 
between two sections of hard piping or a bolted and gasketed ducting 
flange), you must meet the requirements specified in paragraphs 
(a)(1)(i) through (iii) of this section.
    (i) Conduct an initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section to demonstrate 
that the closed vent system operates with no identifiable emissions 
within the first 30 calendar days after startup of the affected 
facility routing emissions through the closed vent system.
    (ii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in piping; loose connections; liquid 
leaks; or broken or missing caps or other closure devices. You must 
monitor a component or connection using the test methods and procedures 
in paragraph (b) of this section to demonstrate that it operates with 
no identifiable emissions following any time the component is repaired 
or replaced or the connection is unsealed.
    (iii) Conduct AVO inspections in accordance with and at the same 
frequency as specified for fugitive emissions components affected 
facilities located at the same type of site as specified in Sec.  
60.5397b(g). Process unit equipment affected facilities must conduct 
annual AVO inspections concurrent with the inspections required by 
paragraph (a)(1)(ii) of this section.
    (2) For closed vent system components other than those specified in 
paragraph (a)(1) of this section, you must meet the requirements of 
paragraphs (a)(2)(i) through (iv) of this section.
    (i) Conduct an initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section within the first 
30 calendars days after startup of the affected facility routing 
emissions through the closed vent system to demonstrate that the closed 
vent system operates with no identifiable emissions.
    (ii) Conduct inspections according to the test methods, procedures, 
and frequencies specified in paragraph (b) of this section to 
demonstrate that the components or connections operate with no 
identifiable emissions.
    (iii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in ductwork; loose connections; liquid 
leaks; or broken or missing caps or other closure devices. You must 
monitor a component or connection using the test methods and procedures 
in paragraph (b) of this section to demonstrate that it operates with 
no identifiable emissions following any time the component is repaired 
or replaced or the connection is unsealed.
    (iv) Conduct AVO inspections in accordance with and at the same 
frequency as specified for fugitive emissions components affected 
facilities located at the same type of site, as specified in Sec.  
60.5397b(g). Process unit equipment affected facilities must conduct 
annual AVO inspections concurrent with the inspections required by 
paragraph (a)(2)(iii) of this section.
    (3) For each cover, you must meet the requirements of paragraphs 
(a)(3)(i) through (iv) of this section.
    (i) Conduct the inspections specified in paragraphs (a)(3)(ii) 
through (iv) of this section to identify defects that could result in 
air emissions and to ensure the cover operates with no identifiable 
emissions. Defects include, but are not limited to, visible cracks, 
holes, or gaps in the cover, or between the cover and the separator 
wall; broken, cracked, or otherwise damaged seals or gaskets on closure 
devices; and broken or missing hatches, access covers, caps, or other 
closure devices. In the case where the storage vessel is buried 
partially or entirely underground, you must inspect only those portions 
of the cover that extend to or above the ground surface, and those 
connections that are on such portions of the cover (e.g., fill ports, 
access hatches, gauge wells, etc.) and can be opened to the atmosphere.
    (ii) An initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section, following 
installation of the cover to demonstrate that each cover operates with 
no identifiable emissions.
    (iii) Conduct AVO inspections in accordance with and at the same 
frequency as specified for fugitive emissions components affected 
facilities located at the same type of site as specified in Sec.  
60.5397b(g). Process unit equipment affected facilities must conduct 
annual AVO inspections concurrent with the inspections required by 
paragraph (a)(1)(ii) of this section.
    (iv) Inspections according to the test methods, procedures, and 
schedules specified in paragraph (b) of this section to demonstrate 
that each cover operates with no identifiable emissions.
    (4) For each bypass device, except as provided for in Sec.  
60.5411b(a)(4)(ii), you must meet the requirements of paragraph 
(a)(4)(i) or (ii) of this section.
    (i) Set the flow indicator to take a reading at least once every 15 
minutes at the inlet to the bypass device that could divert the stream 
away from the control device and to the atmosphere.
    (ii) If the bypass device valve installed at the inlet to the 
bypass device is secured in the non-diverting position using a car-seal 
or a lock-and-key type configuration, visually inspect the seal or 
closure mechanism at least once every month to verify that the valve is 
maintained in the non-diverting position and the vent stream is not 
diverted through the bypass device.
    (b) No identifiable emissions test methods and procedures. If you 
are required to conduct an inspection of a closed vent system and cover 
as specified in paragraph (a)(1), (2), or (3) of this section or Sec.  
60.5398b(b), you must meet the requirements of paragraphs (b)(1) 
through (9) of this section. You must meet the requirements of 
paragraphs (b)(1), (2), (4), and (9) of this section for each self-
contained process controller at your process controller affected 
facility as specified at Sec.  60.5390b(a)(2).
    (1) Initial and periodic inspection. You must conduct initial and 
periodic no identifiable emissions inspections as specified in 
paragraphs (b)(1)(i) through (iii) of this section, as applicable.
    (i) You must conduct inspections for no identifiable emissions from 
your covers and closed vent systems at your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, or 
storage vessel affected facility, using the procedures for conducting 
OGI inspections in Sec.  60.5397b(c)(7). As an alternative you may 
conduct inspections in accordance with Method 21 of appendix A-7 to 
this part. Monitoring must be conducted at the same frequency as 
specified for fugitive emissions components affected facilities located 
at the same type of site, as specified in Sec.  60.5397b(g).
    (ii) For covers and closed vent systems located at onshore natural 
gas processing plants, OGI inspections for no identifiable emissions 
must be

[[Page 17102]]

conducted initially and bimonthly in accordance with appendix K to this 
part. As an alternative you must conduct quarterly inspections for no 
identifiable emissions in accordance with Method 21 of appendix A-7 to 
this part.
    (iii) For your self-contained process controller, you must conduct 
initial and quarterly inspections for no identifiable emissions using 
the procedures for conducting OGI inspections in Sec.  60.5397b(c)(7). 
As an alternative you may conduct quarterly inspections in accordance 
with Method 21 of appendix A-7 to this part.
    (2) OGI application, Where OGI is used, the closed vent system, 
cover, or self-contained process controller is determined to operate 
with no identifiable emissions if no emissions are imaged during the 
inspection. Emissions imaged by OGI constitute a deviation of the no 
identifiable emissions standard until an OGI inspection conducted in 
accordance with this paragraph (b)(2) of this section determines that 
the closed vent system, cover, or self-contained process controller, as 
applicable, operates with no identifiable emissions.
    (3) AVO application. Where AVO inspections are required, the closed 
vent system or cover is determined to operate with no identifiable 
emissions if no emissions are detected by AVO. Emissions detected by 
AVO constitute a deviation of the no identifiable emissions standard 
until an AVO inspection determines that the closed vent system or cover 
operates with no identifiable emissions.
    (4) Method 21 application. Where Method 21 of appendix A-7 to this 
part is used for the inspection, the requirements of paragraphs 
(b)(4)(i) through (vii) of this section apply.
    (i) The detection instrument must meet the performance criteria of 
Method 21 of appendix A-7 to this part, except that the instrument 
response factor criteria in section 8.1.1 of Method 21 must be for the 
average composition of the fluid and not for each individual organic 
compound in the stream.
    (ii) You must calibrate the detection instrument before use on each 
day of its use by the procedures specified in Method 21 of appendix A-7 
to this part.
    (iii) Calibration gases must be as specified in paragraphs 
(b)(4)(iii)(A) and (B) of this section.
    (A) Zero air (less than 10 parts per million by volume hydrocarbon 
in air).
    (B) A mixture of methane in air at a concentration less than 500 
ppmv.
    (iv) You may choose to adjust or not adjust the detection 
instrument readings to account for the background organic concentration 
level. If you choose to adjust the instrument readings for the 
background level, you must determine the background level value 
according to the procedures in Method 21 of appendix A-7 to this part.
    (v) Your detection instrument must meet the performance criteria 
specified in paragraphs (b)(4)(v)(A) and (B) of this section.
    (A) Except as provided in paragraph (b)(4)(v)(B) of this section, 
the detection instrument must meet the performance criteria of Method 
21 of appendix A-7 to this part, except the instrument response factor 
criteria in section 8.1.1 of Method 21 must be for the average 
composition of the process fluid, not each individual volatile organic 
compound in the stream. For process streams that contain nitrogen, air, 
or other inerts that are not organic hazardous air pollutants or 
volatile organic compounds, you must calculate the average stream 
response factor on an inert-free basis.
    (B) If no instrument is available that will meet the performance 
criteria specified in paragraph (b)(4)(v)(A) of this section, you may 
adjust the instrument readings by multiplying by the average response 
factor of the process fluid, calculated on an inert-free basis, as 
described in paragraph (b)(4)(v)(A) of this section.
    (vi) You must determine if a potential leak interface operates with 
no identifiable emissions using the applicable procedure specified in 
paragraph (b)(4)(vi)(A) or (B) of this section.
    (A) If you choose not to adjust the detection instrument readings 
for the background organic concentration level, then you must directly 
compare the maximum organic concentration value measured by the 
detection instrument to the applicable value for the potential leak 
interface as specified in paragraph (b)(4)(vii) of this section.
    (B) If you choose to adjust the detection instrument readings for 
the background organic concentration level, you must compare the value 
of the arithmetic difference between the maximum organic concentration 
value measured by the instrument and the background organic 
concentration value as determined in paragraph (b)(4)(iv) of this 
section with the applicable value for the potential leak interface as 
specified in paragraph (b)(4)(vii) of this section.
    (vii) A closed vent system, cover, or self-contained process 
controller is determined to operate with no identifiable emissions if 
the organic concentration value determined in paragraph (b)(4)(vi) of 
this section is less than 500 ppmv. An organic concentration value 
determined in paragraph (b)(4)(vi) of this section of greater than or 
equal to 500 ppmv constitutes a deviation of the no identifiable 
emissions standard until an inspection conducted in accordance with 
paragraph (b)(4) of this section determines that the closed vent 
system, cover, or self-contained process controller, as applicable, 
operates with no identifiable emissions.
    (5) Repairs. Whenever emissions or a defect is detected, you must 
repair the emissions or defect as soon as practicable according to the 
requirements of paragraphs (b)(5)(i) through (iii) of this section, 
except as provided in paragraph (b)(6) of this section.
    (i) A first attempt at repair must be made no later than 5 calendar 
days after the emissions or defect is detected.
    (ii) Repair must be completed no later than 30 calendar days after 
the emissions or defect is detected.
    (iii) For covers, grease or another substance compatible with the 
gasket material must be applied to deteriorating or cracked gaskets to 
improve the seal while awaiting repair.
    (6) Delay of repair. Delay of repair of a closed vent system or 
cover for which emissions or defects have been detected is allowed if 
the repair is technically infeasible without a shutdown, or if you 
determine that emissions resulting from immediate repair would be 
greater than the emissions likely to result from delay of repair. You 
must complete repair of such equipment by the end of the next shutdown.
    (7) Unsafe to inspect requirements. You may designate any parts of 
the closed vent system or cover as unsafe to inspect if the 
requirements of paragraphs (b)(7)(i) and (ii) of this section are met. 
Unsafe to inspect parts are exempt from the inspection requirements of 
paragraphs (a)(1) through (3) of this section.
    (i) You determine that the equipment is unsafe to inspect because 
inspecting personnel would be exposed to an imminent or potential 
danger as a consequence of complying with paragraphs (a)(1), (2), or 
(3) of this section.
    (ii) You have a written plan that requires inspection of the 
equipment as frequently as practicable during safe-to-inspect times.
    (8) Difficult to inspect requirements. You may designate any parts 
of the closed vent system or cover as difficult to inspect if the 
requirements of paragraphs (b)(8)(i) and (ii) of this section are met. 
Difficult to inspect parts are exempt from the inspection

[[Page 17103]]

requirements of paragraphs (a)(1) through (3) of this section.
    (i) You determine that the equipment cannot be inspected without 
elevating the inspecting personnel more than 2 meters above a support 
surface.
    (ii) You have a written plan that requires inspection of the 
equipment at least once every 5 years.
    (9) Records and reports. You must maintain records of all 
inspection results as specified in Sec.  60.5420b(c)(8) through (10). 
You must submit the reports as specified in Sec.  60.5420b(b)(11).


Sec.  60.5417b   What are the continuous monitoring requirements for my 
control devices?

    You must meet the requirements of this section to demonstrate 
continuous compliance for each control device used to meet emission 
standards for your well, centrifugal compressor, reciprocating 
compressor, process controller, pump, storage vessel, and process unit 
equipment affected facilities.
    (a) For each control device used to comply with the emission 
reduction standard in Sec.  60.5377b(b) for well affected facilities, 
Sec.  60.5380b(a)(1) for centrifugal compressor affected facilities, 
Sec.  60.5385b(d)(2) for reciprocating compressor affected facilities, 
Sec.  60.5390b(b)(3) for your process controller affected facility in 
Alaska, Sec.  60.5393b(b)(1) for your pumps affected facility, Sec.  
60.5395b(a)(2) for your storage vessel affected facility, or either 
Sec.  60.5400b(f) or Sec.  60.5401b(e) for your process equipment 
affected facility, you must install and operate a continuous parameter 
monitoring system for each control device as specified in paragraphs 
(c) through (h) of this section, except as provided for in paragraph 
(b) of this section. If you install and operate a flare in accordance 
with Sec.  60.5412b(a)(3), you are exempt from the requirements of 
paragraph (f) of this section. If you operate an enclosed combustion 
device or flare using an alternative test method approved under Sec.  
60.5412b(d), you must operate the control device as specified in 
paragraph (i) of this section instead of using the procedures specified 
in paragraphs (c) through (h) of this section. You must keep records 
and report in accordance with paragraph (j) of this section.
    (b) You are exempt from the monitoring requirements specified in 
paragraphs (c) through (g) of this section for the control devices 
listed in paragraphs (b)(1) and (2) of this section.
    (1) A boiler or process heater in which all vent streams are 
introduced with the primary fuel or are used as the primary fuel.
    (2) A boiler or process heater with a design heat input capacity 
equal to or greater than 44 megawatts.
    (c) You must meet the specifications and requirements of paragraphs 
(c)(1) through (4) of this section.
    (1) Except for continuous parameter monitoring systems used to 
detect the presence of a pilot or combustion flame, each continuous 
parameter monitoring system must measure data values at least once 
every hour and record the values for each parameter as required in 
paragraphs (c)(1)(i) or (ii) of this section. Continuous parameter 
monitoring systems used to detect the presence of a pilot or combustion 
flame must record a reading at least once every 5 minutes.
    (i) Each measured data value.
    (ii) Each block average value for each 1-hour period or shorter 
periods calculated from all measured data values during each period.
    (2) You must prepare a monitoring plan that covers each control 
device for affected facilities within each company-defined area. The 
monitoring plan must address the monitoring system design, data 
collection, and the quality assurance and quality control elements 
outlined in paragraphs (c)(2)(i) through (v) of this section. You must 
install, calibrate, operate, and maintain each continuous parameter 
monitoring system in accordance with the procedures in your monitoring 
plan. Heat sensing monitoring devices that indicate the continuous 
ignition of a pilot or combustion flame are exempt from the 
calibration, quality assurance and quality control requirements of this 
section.
    (i) The performance criteria and design specifications for the 
monitoring system equipment, including the sample interface, detector 
signal analyzer, and data acquisition and calculations.
    (ii) Sampling interface (e.g., thermocouple) location such that the 
monitoring system will provide representative measurements.
    (iii) Equipment performance checks, system accuracy audits, or 
other audit procedures.
    (iv) Ongoing operation and maintenance procedures in accordance 
with provisions in Sec.  60.13(b).
    (v) Ongoing recordkeeping procedures in accordance with provisions 
in Sec.  60.7(f).
    (3) You must conduct the continuous parameter monitoring system 
equipment performance checks, system accuracy audits, or other audit 
procedures specified in the monitoring plan at least once every 12 
months.
    (4) You must conduct a performance evaluation of each continuous 
parameter monitoring system in accordance with the monitoring plan. 
Heat sensing monitoring devices that indicate the continuous ignition 
of a pilot or combustion flame are exempt from the calibration, quality 
assurance and quality control requirements of this section.
    (d) You must install, calibrate, operate, and maintain a device 
equipped with a continuous recorder to measure the values of operating 
parameters appropriate for the control device as specified in 
paragraphs (d)(1) through (8) of this section, as applicable. Instead 
of complying with the requirements in paragraphs (d)(1) through (8) of 
this section, you may install an organic monitoring device equipped 
with a continuous recorder that measures the concentration level of 
organic compounds in the exhaust vent stream from the control device to 
demonstrate compliance with the applicable performance requirement 
specified in Sec.  60.5412b(a)(1). The monitor must meet the 
requirements of Performance Specification 8 or 9 of appendix B to this 
part. You must install, calibrate, and maintain the monitor according 
to the manufacturer's specifications and the requirements in 
Performance Specification 8 or 9. You may also request approval from 
the Administrator to monitor different operating parameters than those 
specified in paragraphs (d)(1) through (8) of this section in 
accordance with Sec.  60.13(i).
    (1) For an enclosed combustion device that demonstrates during the 
performance test conducted under Sec.  60.5413b(b) that combustion zone 
temperature is an accurate indicator of performance, a temperature 
monitoring device equipped with a continuous recorder. The monitoring 
device must have a minimum accuracy of <plus-minus>1 percent of the 
temperature being monitored in degrees Celsius, or <plus-minus>2.5 
[deg]C, whichever value is greater. You must install the temperature 
sensor at a location representative of the combustion zone temperature. 
You must also comply with the requirements of paragraphs (d)(8)(i), 
(iv), and (v) of this section.
    (2) For a catalytic vapor incinerator, a temperature monitoring 
device equipped with a continuous recorder. The device must be capable 
of monitoring temperature at two locations and have a minimum accuracy 
of <plus-minus>1 percent of the temperature being monitored in degrees 
Celsius, or <plus-minus>2.5 [deg]C, whichever value is greater. You 
must install one temperature sensor in the vent stream at the nearest 
feasible point

[[Page 17104]]

to the catalyst bed inlet, and you must install a second temperature 
sensor in the vent stream at the nearest feasible point to the catalyst 
bed outlet.
    (3) For a boiler or process heater, a temperature monitoring device 
equipped with a continuous recorder. The temperature monitoring device 
must have a minimum accuracy of <plus-minus>1 percent of the 
temperature being monitored in degrees Celsius, or <plus-minus>2.5 
[deg]C, whichever value is greater. You must install the temperature 
sensor at a location representative of the combustion zone temperature.
    (4) For a condenser, a temperature monitoring device equipped with 
a continuous recorder. The temperature monitoring device must have a 
minimum accuracy of <plus-minus>1 percent of the temperature being 
monitored in degrees Celsius, or <plus-minus>2.5 [deg]C, whichever 
value is greater. You must install the temperature sensor at a location 
in the exhaust vent stream from the condenser.
    (5) For a regenerative-type carbon adsorption system, a continuous 
monitoring system that meets the specifications in paragraphs (d)(5)(i) 
and (ii) of this section. You also must monitor the design carbon 
service life established using a design analysis performed as specified 
in Sec.  60.5413b(c)(2).
    (i) The continuous parameter monitoring system must measure and 
record the average total regeneration stream mass flow or volumetric 
flow during each carbon bed regeneration cycle. The flow sensor must 
have a measurement sensitivity of 5 percent of the flow rate or 10 
cubic feet per minute, whichever is greater. You must check the 
mechanical connections for leakage at least every month, and you must 
perform a visual inspection at least every 3 months of all components 
of the flow continuous parameter monitoring system for physical and 
operational integrity and all electrical connections for oxidation and 
galvanic corrosion if your flow continuous parameter monitoring system 
is not equipped with a redundant flow sensor; and
    (ii) The continuous parameter monitoring system must measure and 
record the average carbon bed temperature for the duration of the 
carbon bed steaming cycle and measure the actual carbon bed temperature 
after regeneration and within 15 minutes of completing the cooling 
cycle. The temperature monitoring device must have a minimum accuracy 
of <plus-minus>1 percent of the temperature being monitored in degrees 
Celsius, or <plus-minus>2.5 [deg]C, whichever value is greater.
    (6) For a nonregenerative-type carbon adsorption system, you must 
monitor the design carbon replacement interval established using a 
design analysis performed as specified in Sec.  60.5413b(c)(3). The 
design carbon replacement interval must be based on the total carbon 
working capacity of the control device and source operating schedule.
    (7) For a combustion control device whose model is tested under 
Sec.  60.5413b(d), continuous monitoring systems as specified in 
paragraphs (d)(8)(i) through (iv) and (d)(8)(vi) of this section and 
visible emission observations conducted as specified in paragraph 
(d)(8)(v) of this section.
    (8) For an enclosed combustion device other than those listed in 
paragraphs (d)(1) through (3) and (7) of this section or for a flare, 
continuous monitoring systems as specified in paragraphs (d)(8)(i) 
through (iv) of this section and visible emission observations 
conducted as specified in paragraph (d)(8)(v) of this section. 
Additionally, for enclosed combustion devices or flares that are air-
assisted or steam-assisted, the continuous monitoring systems specified 
in paragraph (d)(8)(vi) of this section.
    (i) Continuously monitor at least once every five minutes for the 
presence of a pilot flame or combustion flame using a device 
(including, but not limited to, a thermocouple, ultraviolet beam 
sensor, or infrared sensor) capable of detecting that the pilot or 
combustion flame is present at all times. An alert must be sent to the 
nearest control room whenever the pilot or combustion flame is unlit. 
Continuous monitoring systems used for the presence of a pilot flame or 
combustion flame are not subject to a minimum accuracy requirement 
beyond being able to detect the presence or absence of a flame and are 
exempt from the calibration requirements of this section.
    (ii) Except as provided in this paragraph (d)(8)(ii) and paragraph 
(d)(8)(iii) of this section, use one of the following methods to 
continuously determine the NHV of the inlet gas to the enclosed 
combustion device or flare at standard conditions. If the only inlet 
gas stream to the enclosed combustion device or flare is associated gas 
from a well affected facility, the NHV of the inlet stream is 
considered to be sufficiently above the minimum required NHV for the 
inlet gas, and you are not required to conduct the continuous 
monitoring in this paragraph (d)(8)(ii) of this section or the 
demonstration in paragraph (d)(8)(iii) of this section.
    (A) A calorimeter with a minimum accuracy of <plus-minus>2 percent 
of span.
    (B) A gas chromatograph that meets the requirements in paragraphs 
(d)(8)(ii)(B)(1) through (5) of this section.
    (1) You must follow the procedure in Performance Specification 9 of 
appendix B of this part, except that a single daily mid-level 
calibration check can be used (rather than triplicate analysis), the 
multi-point calibration can be conducted quarterly (rather than 
monthly), and the sampling line temperature must be maintained at a 
minimum temperature of 60 [deg]C (rather than 120 [deg]C). Calibration 
gas cylinders must be certified to an accuracy of 2 percent and 
traceable to National Institute of Standards and Technology (NIST) 
standards.
    (2) You must meet the accuracy requirements in Performance 
Specification 9 of appendix B of this part.
    (3) You must use a calibration gas or multiple gases that includes 
the compounds that are reasonably expected to be present in the flare 
gas stream. If multiple calibration gases are necessary to cover all 
compounds, you must calibrate the instrument on all of the gases. You 
may only use the compounds used to calibrate the gas chromatograph in 
the calculation of the vent gas NHV.
    (4) In lieu of the calibration gas described in paragraph 
(d)(8)(ii)(B)(3) of this section, you may use a surrogate calibration 
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All 
of the calibration gases may be combined in one cylinder. If multiple 
calibration gases are necessary to cover all compounds, you must 
calibrate the instrument on all of the gases. Use the response factor 
for the nearest normal hydrocarbon (i.e., n-alkane) in the calibration 
mixture to quantify unknown components detected in the analysis. Use 
the response factor for n-pentane to quantify unknown components 
detected in the analysis that elute after n-pentane.
    (5) To determine the NHV of the vent gas, determine the product of 
the volume fraction of the individual component in the vent gas and the 
net heating value of that individual component. Sum the products for 
all components in the vent gas to determine the NHV for the vent gas. 
For the net heating value of each individual component, use the net 
heating value at 25 [deg]C and 1 atmosphere.
    (C) A mass spectrometer that meets the requirements in paragraphs 
(d)(8)(ii)(C)(1) through (6) of this section.
    (1) You must meet applicable requirements in Performance

[[Page 17105]]

Specification 9 of appendix B of this part for continuous monitoring 
system acceptance including, but not limited to, performing an initial 
multi-point calibration check at three concentrations following the 
procedure in Section 10.1. A single daily mid-level calibration check 
can be used (rather than triplicate analysis), the multi-point 
calibration can be conducted quarterly (rather than monthly), and the 
sampling line temperature must be maintained at a minimum temperature 
of 60 [deg]C (rather than 120 [deg]C). Calibration gas cylinders must 
be certified to an accuracy of 2 percent and traceable to NIST 
standards.
    (2) The average instrument calibration error (CE) for each 
calibration compound at any calibration concentration must not differ 
by more than 10 percent from the certified cylinder gas value. The CE 
for each component in the calibration blend must be calculated using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.010

Where:

Cm = Average instrument response (ppm).
Ca = Certified cylinder gas value (ppm).

    (3) You must use a calibration gas or multiple gases that includes 
the compounds that are reasonably expected to be present in the flare 
gas stream. If multiple calibration gases are necessary to cover all 
compounds, you must calibrate the instrument on all of the gases. You 
may only use the compounds used to calibrate the mass spectrometer in 
the calculation of the vent gas NHV.
    (4) In lieu of the calibration gas described in paragraph 
(d)(8)(ii)(C)(3) of this section, you may use a surrogate calibration 
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All 
of the calibration gases may be combined in one cylinder. If multiple 
calibration gases are necessary to cover all compounds, you must 
calibrate the instrument on all of the gases. For unknown gas 
components that have similar analytical mass fragments to calibration 
compounds, you may report the unknowns as an increase in the overlapped 
calibration gas compound. For unknown compounds that produce mass 
fragments that do not overlap calibration compounds, you may use the 
response factor for the nearest molecular weight hydrocarbon in the 
calibration mix to quantify the unknown component. You may use the 
response factor for n-pentane to quantify any unknown components 
detected with a higher molecular weight than n-pentane.
    (5) You must perform an initial calibration to identify mass 
fragment overlap and response factors for the target compounds.
    (6) To determine the NHV of the vent gas, determine the product of 
the volume fraction of the individual component in the vent gas and the 
net heating value of that individual component. Sum the products for 
all components in the vent gas to determine the NHV for the vent gas. 
For the net heating value of each individual component, use the net 
heating value at 25 [deg]C and 1 atmosphere.
    (D) A grab sampling system capable of collecting an evacuated 
canister sample for subsequent compositional analysis at least once 
every eight hours. Subsequent compositional analysis of the samples 
must be performed according to ASTM D1945-14 (R2019) (incorporated by 
reference, see Sec.  60.17). To determine the NHV of the vent gas, 
determine the product of the volume fraction of the individual 
component in the vent gas and the net heating value of that individual 
component. Sum the products for all components in the vent gas to 
determine the NHV for the vent gas. For the net heating value of each 
individual component, use the net heating value at 25 [deg]C and 1 
atmosphere.
    (iii) For an unassisted or pressure-assisted flare or enclosed 
combustion device, if you demonstrate according to the methods 
described in paragraphs (d)(8)(iii)(A) through (F) of this section that 
the NHV of the inlet gas to the enclosed combustion device or flare 
consistently exceeds the applicable operating limit specified in Sec.  
60.5415b(f)(1)(vii)(B) or (C), continuous monitoring of the NHV is not 
required, but you must conduct the ongoing sampling in paragraph 
(d)(8)(iii)(G) of this section. For flares and enclosed combustion 
devices that use only perimeter assist air and do not use steam assist 
or premix assist air, if you demonstrate according to the methods 
described in paragraphs (d)(8)(iii)(A) through (F) of this section that 
the NHV of the inlet gas to the enclosed combustion device or flare 
consistently exceeds 300 Btu/scf, continuous monitoring of the NHV is 
not required, but you must conduct the ongoing sampling in paragraph 
(d)(8)(iii)(G) of this section. For an unassisted or pressure-assisted 
flare or enclosed combustion device, in lieu of conducting the 
demonstration outlined in paragraphs (d)(8)(iii)(A) through (D) of this 
section, you may conduct the demonstration outlined in paragraph 
(d)(8)(iii)(H) of this section, but you must still comply with 
paragraphs (d)(8)(iii)(E) through (G) of this section.
    (A) Continuously monitor or collect a sample of the inlet gas to 
the enclosed combustion device or flare twice daily to determine the 
average NHV of the gas stream for 14 consecutive operating days. If you 
do not continuously monitor the NHV, the minimum time of collection for 
each individual sample be at least one hour. Consecutive samples must 
be separated by at least 6 hours. If inlet gas flow is intermittent 
such that there are not at least 28 samples over the 14 operating day 
period, you must continue to collect samples of the inlet gas beyond 
the 14 operating day period until you collect a minimum of 28 samples.
    (B) If you collect samples twice per day, count the number of 
samples where the NHV value is less than 1.2 times the applicable 
operating limit specified in Sec.  60.5415b(f)(1)(vii)(B), (C), or 
paragraph (d)(8)(iii) of this section (i.e., values that are less than 
240, 360, or 960 Btu/scf, as applicable) during the sample collection 
period in paragraph (d)(8)(iii)(A) of this section.
    (C) If you continuously sample the inlet stream for 14 days, count 
the number of hourly average NHV values that are less than the 
applicable operating limit specified in Sec.  60.5415b(f)(1)(vii)(B), 
Sec.  60.5415b(f)(1)(vii)(C)(1), or paragraph (d)(8)(iii) of this 
section (i.e., values that are less than 200, 300, or 800 Btu/scf, as 
applicable), during the sample collection period in paragraph 
(d)(8)(iii)(A) of this section.

[[Page 17106]]

    (D) If there are no samples counted under paragraph (d)(8)(iii)(B) 
of this section or there are no hourly values counted under paragraph 
(d)(8)(iii)(C) of this section, the gas stream is considered to 
consistently exceed the applicable NHV operating limit and on-going 
continuous monitoring is not required.
    (E) If process operations are revised that could impact the NHV of 
the gas sent to the enclosed combustion device or flare, such as the 
removal or addition of process equipment, and at any time the 
Administrator requires, re-evaluation of the gas stream must be 
performed according to paragraphs (d)(8)(iii)(A) through (D) of this 
section to ensure the gas stream still consistently exceeds the 
applicable operating limit specified in Sec.  60.5415b(f)(1)(vii)(B), 
(f)(1)(vii)(C)(1), or paragraph (d)(8)(iii) of this section.
    (F) When collecting samples under paragraph (d)(8)(iii)(A) of this 
section, the owner or operator must account for any sources of inert 
gases that can be sent to the enclosed combustion device or flare 
(e.g., streams from compressors in acid gas service, streams from 
enhanced oil recovery facilities). The report in Sec.  
60.5420b(b)(11)(v)(I) and the records of the demonstration in Sec.  
60.5420b(c)(11)(vi) must note whether the enclosed combustion device or 
flare has the potential to receive inert gases, and if so, whether the 
sampling included periods where the highest percentage of inert gases 
were sent to the enclosed combustion device or flare. If the 
introduction of inerts is intermittent and does not occur during the 
initial demonstration, the introduction of inerts will be considered a 
revision to process operations that triggers a re-evaluation under 
paragraph (d)(8)(iii)(E) of this section. If conditions at the site did 
not allow sampling during periods where the introduction of inert gases 
was at the highest percentage possible, increasing the percentage of 
inerts will be considered a revision to process operations that 
triggers a re-evaluation under paragraph (d)(8)(iii)(E) of this 
section.
    (G) You must collect three samples of the inlet gas to the enclosed 
combustion device or flare at least once every 5 years. The minimum 
time of collection for each individual sample must be at least one 
hour. The samples must be taken during the period with the lowest 
expected NHV (i.e., the period with the highest percentage of inerts). 
The first set of periodic samples must be taken, or continuous 
monitoring commenced, no later than 60 calendar months following the 
last sample taken under paragraph (d)(8)(iii)(A) of this section. 
Subsequent periodic samples must be taken, or continuous monitoring 
commenced, no later than 60 calendar months following the previous 
sample. If any sample has an NHV value less than 1.2 times the 
applicable operating limit specified in Sec.  60.5415b(f)(1)(vii)(B), 
Sec.  60.5415b(f)(1)(vii)(C), or paragraph (d)(8)(iii) of this section 
(i.e., values that are less than 240, 360, or 960 Btu/scf, as 
applicable), you must conduct the monitoring required by paragraph 
(d)(8)(ii) of this section.
    (H) You may request an alternative test method under Sec.  
60.5412b(d) to demonstrate that the flare or enclosed combustion device 
reduces methane and VOC in the gases vented to the device by 95.0 
percent by weight or greater. You must use an alternative test method 
that demonstrates compliance with the combustion efficiency limit; you 
may not use an alternative test method that demonstrates compliance 
with NHV<INF>cz</INF> and NHV<INF>dil</INF> in lieu of measuring 
combustion efficiency directly. You must measure data values at the 
frequency specified in the alternative test method and conduct the 
quality assurance and quality control requirements outlined in the 
alternative test method at the frequency outlined in the alternative 
test method. You must monitor the combustion efficiency of the flare 
continuously for 14 days. If there are no values of the combustion 
efficiency measured by the alternative test method that are less than 
95.0 percent, the gas stream is considered to consistently exceed the 
applicable NHV operating limit, and you are not required to 
continuously monitor the NHV of the inlet gas to the flare or enclosed 
combustion device.
    (iv) Except as noted in paragraphs (d)(8)(iv)(A) through (E) of 
this section, a continuous parameter monitoring system for measuring 
the flow of gas to the enclosed combustion device or flare. You may use 
direct flow meters or other parameter monitoring systems combined with 
engineering calculations, such as inlet line pressure, line size, and 
burner nozzle dimensions, to satisfy this requirement. The monitoring 
instrument must have an accuracy of <plus-minus>10 percent or better at 
the maximum expected flow rate.
    (A) Pressure-assisted flares and pressure-assisted enclosed 
combustion devices are not required to have a continuous parameter 
monitoring system for measuring the inlet flow of gas to the device if 
you install, calibrate, maintain, and operate a backpressure regulator 
valve calibrated to open at the minimum pressure set point 
corresponding to the minimum inlet gas flow rate. The set point must be 
consistent with manufacturer specifications for minimum flow or 
pressure and must be supported by an engineering evaluation. At least 
annually, you must confirm that the backpressure regulator valve set 
point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (B) Unassisted flares are not required to have a continuous 
parameter monitoring system for measuring the inlet flow of gas to the 
device if you meet the conditions in paragraphs (d)(8)(iv)(B)(1) and 
(2) of this section.
    (1) You must demonstrate, based on the maximum potential pressure 
of units manifolded to the flare and applicable engineering 
calculations for the manifolded closed vent system, that the maximum 
flow rate to the flare cannot cause the flare tip velocity to exceed 
18.3 meter/second (60 feet/second). If there are changes to the process 
or control device that can be reasonably expected to impact the maximum 
flow rate to the flare, you must conduct a new demonstration to 
determine whether the maximum flow rate to the flare is less than 18.3 
meter/second (60 feet/second).
    (2) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (C) Unassisted enclosed combustion devices are not required to have 
a continuous parameter monitoring system for measuring the inlet flow 
of gas to the device if you meet the conditions in paragraphs 
(d)(8)(iv)(C)(1) and (2) of this section.
    (1) You must demonstrate, based on the maximum potential pressure 
of units manifolded to the enclosed combustion device and applicable 
engineering calculations for the manifolded closed vent system, that 
the maximum flow rate to the enclosed combustion device cannot cause 
the maximum inlet flow rate established in accordance with paragraph 
(f)(1) of this section to be exceeded. If there are

[[Page 17107]]

changes to the process or control device that can be reasonably 
expected to impact the maximum flow rate to the enclosed combustion 
device, you must conduct a new demonstration to determine whether the 
maximum flow rate to the enclosed combustor is less than the maximum 
inlet flow rate established in accordance with paragraph (f)(1) of this 
section.
    (2) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (D) Air-assisted flares or enclosed combustion devices that use 
only perimeter assist air and have no assist steam or premix assist air 
are not required to have a continuous parameter monitoring system for 
measuring the inlet flow of gas to the device or the flow of assist air 
if you meet the conditions in paragraphs (d)(8)(iv)(D)(1) and (2) of 
this section. For these flares and enclosed combustion devices, 
NHV<INF>cz</INF> is assumed to be equal to the vent gas NHV.
    (1) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (2) You must demonstrate, based on the maximum flow rate of 
perimeter assist air to the enclosed combustion device or flare and 
applicable engineering calculations, that the NHV<INF>dil</INF> can 
never be less than the minimum required NHV<INF>dil.</INF> The 
demonstration must clearly document why the maximum flow rate of 
perimeter assist air will never exceed the rate used in the 
demonstration. You must use the minimum flow rate of vent gas allowed 
by your backpressure regulator valve and the minimum expected value of 
the NHV of the inlet gas to the enclosed combustion device or flare 
based on previous sampling results or process knowledge of the streams 
sent to the enclosed combustion device or flare in your demonstration. 
You must update this demonstration if there are changes to the 
backpressure regulator valve, the backpressure regulator valve set 
point, or the maximum flow rate of perimeter assist air. You must also 
update this demonstration if any sampling results of the NHV of the 
inlet gas to the enclosed combustion device or flare under paragraphs 
(d)(8)(ii) or (iii) of this section are lower than the NHV vent gas 
value used in your demonstration.
    (E) Air-assisted flares or enclosed combustion devices that use 
only premix assist air and have no assist steam or perimeter assist air 
are not required to have a continuous parameter monitoring system for 
measuring the inlet flow of gas to the device or the flow of assist air 
if you meet the conditions in paragraphs (d)(8)(iv)(E)(1) and (2) of 
this section.
    (1) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (2) You must demonstrate, based on the maximum flow rate of premix 
assist air to the enclosed combustion device or flare and applicable 
engineering calculations, that the NHV<INF>cz</INF> will never be less 
than the minimum required NHV<INF>cz.</INF> The demonstration must 
clearly document why the maximum flow rate of premix assist air will 
never exceed the rate used in the demonstration. You must use the 
minimum flow rate of vent gas allowed by your backpressure regulator 
valve in and the minimum expected value of the NHV of the inlet gas to 
the enclosed combustion device or flare based on previous sampling 
results or process knowledge of the streams sent to the enclosed 
combustion device or flare in your demonstration. You must update this 
demonstration if there are changes to the backpressure regulator valve, 
the backpressure regulator valve set point, or the maximum flow rate of 
premix assist air. You must also update this demonstration if any 
sampling results of the NHV of the inlet gas to the enclosed combustion 
device or flare under paragraphs (d)(8)(ii) or (iii) of this section 
are lower than the NHV vent gas value used in your demonstration.
    (v) Conduct inspections monthly and at other times as requested by 
the Administrator to monitor for visible emissions from the combustion 
device using section 11 of Method 22 of appendix A of this part or 
conduct visible emissions monitoring according to paragraph (h) of this 
section. The observation period shall be 15 minutes or once the amount 
of time visible emissions is present has exceeded 1 minute. Devices 
must be operated with no visible emissions, except for periods not to 
exceed a total of 1 minute during any 15-minute period.
    (vi) If you use a flare or enclosed combustion device that is air-
assisted or steam-assisted, you must also meet the following 
requirements.
    (A) Except as allowed by paragraph (d)(8)(iv)(E) of this section, 
you must monitor and calculate NHV<INF>cz</INF> as specified in Sec.  
63.670(m) of this chapter. Additionally, for flares and enclosed 
combustion devices that use only perimeter assist air and do not use 
steam assist or premix assist air, the NHV<INF>cz</INF> is equal to the 
vent gas NHV. When NHV<INF>cz</INF> is equal to the vent gas NHV, you 
are not required to continuously monitor NHV<INF>cz</INF> if you meet 
the requirements in paragraph (d)(8)(iii) of this section.
    (B) Except as allowed by paragraph (d)(8)(iv)(D) of this section, 
for each flare using perimeter assist air, you must also monitor and 
calculate NHV<INF>dil</INF> as specified in Sec.  63.670(n) of this 
chapter. If the only assist air provided to the flare or enclosed 
combustion control device is perimeter assist air intentionally 
entrained in lower and/or upper steam at the flare tip and the 
effective diameter is 9 inches or greater, you are only required to 
comply with the NHV<INF>cz</INF> limit specified in paragraph 
(f)(8)(vi)(A) of this section.
    (C) Except as allowed by paragraph (d)(8)(iv) of this section, you 
must monitor the flare vent gas and assist gas as specified in Sec.  
63.670(i) of this chapter.
    (D) You must determine the flare vent gas net heating value as 
specified in Sec.  63.670(l) of this chapter using one of the methods 
specified in paragraph (d)(8)(ii) of this section. Where the phrase 
``petroleum refinery'' is used, for purposes of this subpart, it will 
refer to flares controlling an affected facility under this subpart. If 
you are not

[[Page 17108]]

required to continuously monitor the NHV of the inlet gas because you 
have demonstrated that it consistently exceeds the applicable operating 
limit as provided in paragraph (d)(8)(iii) of this section, you must 
use the lowest net heating value measured in the sampling program in 
paragraph (d)(8)(iii) of this section for the calculations performed in 
paragraphs (d)(8)(vi)(A) and (B). You must update this value if a 
subsequent sampling result of the NHV of the inlet gas to the enclosed 
combustion device or flare under paragraph (d)(8)(iii) of this section 
is lower than the NHV vent gas value used in your calculations.
    (e) Calculate the value of the applicable monitored parameter in 
accordance with paragraphs (e)(1) through (5) of this section.
    (1) You must calculate the daily average value for condenser outlet 
temperature for each operating day, using the data recorded by the 
monitoring system. If the emissions unit operation is continuous, the 
operating day is a 24-hour period. If the emissions unit operation is 
not continuous, the operating day is the total number of hours of 
control device operation per 24-hour period. Valid data points must be 
available for 75 percent of the operating hours in an operating day to 
compute the daily average.
    (2) You must use the 5-minute readings from the heat sensing 
devices to assess the presence of a pilot or combustion flame.
    (3) You must use the regeneration cycle time (i.e., duration of the 
carbon bed steaming cycle) for each regenerative-type carbon adsorption 
system to calculate the average parameter to compare with the maximum 
steam mass flow or volumetric flow during each carbon bed regeneration 
cycle and the maximum carbon bed temperature during the steaming cycle. 
The carbon bed temperature after the regeneration cycle should not be 
averaged; you must use the carbon bed temperature measured within 15 
minutes of completing the cooling cycle to compare with the minimum 
carbon bed temperature after the regeneration cycle.
    (4) You must use 15-minute blocks to calculate NHV<INF>cz</INF> and 
NHV<INF>dil</INF>.
    (5) For all operating parameters others than those described in 
paragraphs (e)(1) through (4) of this section, you must calculate the 
3-hour rolling average of each monitored parameter. For each operating 
hour, calculate the hourly value of the operating parameter from your 
continuous monitoring system. Average the three most recent hours of 
data to determine the 3-hour average. Determine the 3-hour rolling 
average by recalculating the 3-hour average each hour.
    (f) For each operating parameter monitor installed in accordance 
with the requirements of paragraph (d) of this section, you must comply 
with paragraph (f)(1) of this section for all control devices. When 
condensers are installed, you must also comply with paragraph (f)(2) of 
this section.
    (1) You must establish a minimum operating parameter value or a 
maximum operating parameter value, as appropriate for the control 
device, to define the conditions at which the control device must be 
operated to continuously achieve the applicable performance 
requirements of Sec.  60.5412b(a)(1) or (2). You must establish each 
minimum or maximum operating parameter value as specified in paragraphs 
(f)(1)(i) through (iv) of this section.
    (i) If you conduct performance tests in accordance with the 
requirements of Sec.  60.5413b(b) to demonstrate that the control 
device achieves the applicable performance requirements specified in 
Sec.  60.5412b(a)(1) or (2), then you must establish the minimum 
operating parameter value or the maximum operating parameter value 
based on values measured during the performance test and supplemented, 
as necessary, by a condenser or carbon adsorption system design 
analysis or control device manufacturer recommendations or a 
combination of both. If you operate an enclosed combustion device, you 
must establish the maximum inlet flow rate based on values measured 
during the performance test and you may establish the minimum inlet 
flow rate based on control device manufacturer recommendations.
    (ii) If you use a condenser or carbon adsorption system design 
analysis in accordance with the requirements of Sec.  60.5413b(c) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec.  60.5412b(a)(2), then you must establish 
the minimum operating parameter value or the maximum operating 
parameter value based on the design analysis and supplemented, as 
necessary, by the manufacturer's recommendations.
    (iii) If you operate a control device where the performance test 
requirement was met under Sec.  60.5413b(d) to demonstrate that the 
control device achieves the applicable performance requirements 
specified in Sec.  60.5412b(a)(1), then your control device inlet gas 
flow rate must be equal to or greater than the minimum inlet gas flow 
rate and equal to or less than the maximum inlet gas flow rate 
determined by the manufacturer.
    (iv) If you operate an enclosed combustion device where the 
combustion zone temperature is not an indicator of destruction 
efficiency or a control device where the performance test requirement 
was met under Sec.  60.5413b(d), you must maintain the NHV of the gas 
sent to the enclosed combustion device, the NHV<INF>cz</INF>, and the 
NHV<INF>dil</INF> above the applicable limits specified in paragraphs 
Sec.  60.5412b(a)(1)(iv)(A) through (D).
    (2) If you use a condenser as specified in paragraph (d)(1)(v) of 
this section, you must establish a condenser performance curve showing 
the relationship between condenser outlet temperature and condenser 
control efficiency, according to the requirements of paragraphs 
(f)(2)(i) and (ii) of this section.
    (i) If you conduct a performance test in accordance with the 
requirements of Sec.  60.5413b(b) to demonstrate that the condenser 
achieves the applicable performance requirements of Sec.  
60.5412b(a)(2), then the condenser performance curve must be based on 
values measured during the performance test and supplemented as 
necessary by control device design analysis, or control device 
manufacturer's recommendations, or a combination or both.
    (ii) If you use a control device design analysis in accordance with 
the requirements of Sec.  60.5413b(c)(1) to demonstrate that the 
condenser achieves the applicable performance requirements specified in 
Sec.  60.5412b(a)(2), then the condenser performance curve must be 
based on the condenser design analysis and supplemented, as necessary, 
by the control device manufacturer's recommendations.
    (g) A deviation for a control device is determined to have occurred 
when the monitoring data or lack of monitoring data result in any one 
of the criteria specified in paragraphs (g)(1) through (7) of this 
section being met. If you monitor multiple operating parameters for the 
same control device during the same operating day and more than one of 
these operating parameters meets a deviation criterion specified in 
paragraphs (g)(1) through (7) of this section, then a single excursion 
is determined to have occurred for the control device for that 
operating day.
    (1) A deviation occurs when the average value of a monitored 
operating parameter determined in accordance with paragraph (e) of this 
section is less than the minimum operating parameter limit (and, if 
applicable, greater than the

[[Page 17109]]

maximum operating parameter limit) established in paragraph (f)(1) of 
this section; for flares, when the average value of a monitored 
operating parameter determined in accordance with paragraph (e) of this 
section is above the limits specified in Sec.  60.5415b(f)(1)(vii)(B); 
or when the heat sensing device indicates that there is no pilot or 
combustion flame present for any time period. If you use a backpressure 
regulator valve to maintain the inlet gas flow to an enclosed 
combustion device or flare above the minimum value, a deviation occurs 
if the annual inspection finds that the backpressure regulator valve 
set point is not set correctly or indicates that the backpressure 
regulator valve does not fully close when not in the open position.
    (2) If you are subject to Sec.  60.5412b(a)(2), a deviation occurs 
when the 365-day average condenser efficiency calculated according to 
the requirements specified in Sec.  60.5415b(f)(1)(ix)(D) is less than 
95.0 percent.
    (3) If you are subject to Sec.  60.5412b(a)(2) and you have less 
than 365 days of data, a deviation occurs when the average condenser 
efficiency calculated according to the procedures specified in Sec.  
60.5415b(f)(1)(ix)(D)(1) or (2) is less than 95.0 percent.
    (4) A deviation occurs when the monitoring data are not available 
for at least 75 percent of the operating hours in a day.
    (5) If the closed vent system contains one or more bypass devices 
that could be used to divert all or a portion of the gases, vapors, or 
fumes from entering the control device, a deviation occurs when the 
requirements of paragraph (g)(5)(i) or (ii) of this section are met.
    (i) For each bypass line subject to Sec.  60.5411b(a)(4)(i)(A), the 
flow indicator indicates that flow has been detected and that the 
stream has been diverted away from the control device to the 
atmosphere.
    (ii) For each bypass line subject to Sec.  60.5411b(a)(4)(i)(B), if 
the seal or closure mechanism has been broken, the bypass line valve 
position has changed, the key for the lock-and-key type lock has been 
checked out, or the car-seal has broken.
    (6) For a combustion control device whose model is tested under 
Sec.  60.5413b(d), a deviation occurs when the conditions of paragraph 
(g)(4), (5), or (6)(i) through (vi) of this section are met.
    (i) The hourly inlet gas flow rate is less than the minimum inlet 
gas flow rate or greater than the maximum inlet gas flow rate 
determined by the manufacturer. If you use a backpressure regulator 
valve to maintain the inlet gas flow above the minimum value, a 
deviation occurs if the annual inspection finds that the backpressure 
regulator valve set point is not set correctly or indicates that the 
backpressure regulator valve does not fully close when not in the open 
position.
    (ii) Results of the monthly visible emissions test conducted under 
Sec.  60.5413b(e)(3) or monitoring under paragraph (h) of this section 
indicate visible emissions exceed 1 minute in any 15-minute period.
    (iii) There is no indication of the presence of a pilot or 
combustion flame for any 5-minute time period.
    (iv) The control device is not maintained in a leak free condition.
    (v) The control device is not operated in accordance with the 
manufacturer's written operating instructions, procedures and 
maintenance schedule.
    (vi) The NHV of the vent gas, the NHV<INF>cz</INF>, or the 
NHV<INF>dil</INF> is below the applicable limit specified in Sec.  
60.5412b(a)(1)(iv).
    (7) For an enclosed combustion device or flare subject to paragraph 
(d)(8) of this section, a deviation occurs when any of the conditions 
described by paragraphs (g)(1), (4) or (5) of this section are met or 
when the results of the visible emissions monitoring conducted under 
paragraph (d)(8)(v) or (h) of this section exceed 1 minute in any 15-
minute period.
    (h) For enclosed combustion devices and flares, in lieu of 
conducting a visible emissions observation using Method 22 of appendix 
A-7 to this part, you may use a video surveillance camera to 
continuously monitor and record the flare flame according to the 
requirements in paragraphs (h)(1) through (6) of this section.
    (1) You must provide real-time high-definition video surveillance 
camera output (i.e., at least 720p) at a frame rate of at least 15 
frames per second to the control room or other continuously manned 
location where the camera images may be viewed at the same resolution 
at any time.
    (2) You must record at least one frame every 15 seconds with date 
and time stamp.
    (3) The camera must be located at a reasonable distance above the 
flare flame at an angle suitable for visual emissions observations. The 
position of the camera should be such that the sun is not in the field 
of view.
    (4) The camera must be located no more than 400 m (0.25 miles) from 
the emission source.
    (5) Operators must look at the video feed at least once daily for 
an observation period of at least 1 minute to determine if visible 
emissions are present. If visible emissions are present during a daily 
observation, the operator must observe the video feed for 15 minutes or 
until the amount of time visible emissions is present has exceeded 1 
minute, whichever time period is less.
    (6) Enclosed combustion devices and flares must be operated with no 
visible emissions, except for periods not to exceed a total of 1 minute 
during any 15-minute period.
    (i) If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412b(d), you must 
comply with paragraphs (i)(1) through (6) of this section.
    (1) You must measure data values at the frequency specified in the 
alternative test method.
    (2) You must prepare a monitoring plan that covers each control 
device for affected facilities within each company-defined area. The 
monitoring plan must address the monitoring system design, data 
collection, and the quality assurance and quality control elements 
outlined in the alternative test method and in paragraphs (i)(2)(i) 
through (iii) of this section. You must operate and maintain each 
monitoring system in accordance with the procedures in your monitoring 
plan.
    (i) The performance criteria and design specifications for the 
monitoring system equipment.
    (ii) Location of monitoring system in relation to the monitored 
control device.
    (iii) Ongoing reporting and recordkeeping procedures.
    (3) You must conduct the quality assurance and quality control 
requirements outlined in the alternative test method at the frequency 
outlined in the alternative test method.
    (4) If required by Sec.  5412b(d)(4), you must conduct the 
inspections required by paragraph (d)(8)(v) of this section.
    (5) If required by Sec.  5412b(d)(5), you must install the pilot or 
combustion flame monitoring system required by paragraph (d)(8)(i) of 
this section.
    (6) A deviation for the control device is determined to have 
occurred when the monitoring data or lack of monitoring data result in 
any one of the criteria specified in paragraphs (i)(6)(i) through (v) 
of this section being met.
    (i) A deviation occurs if the combustion efficiency is less than 
95.0 percent, the combustion zone NHV is less than 270 Btu/scf, or the 
NHV dilution parameter is less than 22 Btu/sqft.
    (ii) A deviation occurs when the monitoring data are not available 
for at

[[Page 17110]]

least 75 percent of the operating hours in a day.
    (iii) A deviation occurs when any of the conditions described by 
paragraph (g)(5) of this section are met.
    (iv) If required by paragraph (i)(4) of this section to conduct 
visible emissions inspections, a deviation occurs when the results of 
the visible emissions monitoring conducted under paragraph (d)(8)(v) or 
(h) of this section exceeds 1 minute in any 15-minute period.
    (v) If required by paragraph (i)(5) of this section to install a 
pilot or combustion flame monitoring system, a deviation occurs when 
there is no indication of the presence of a pilot or combustion flame 
for any 5-minute period.
    (j) You must submit annual reports for control devices as required 
in Sec.  60.5420b(b)(1) and (11). You must maintain records as 
specified in Sec.  60.5420b(c)(1).


Sec.  60.5420b   What are my notification, reporting, and recordkeeping 
requirements?

    (a) Notifications. You must submit notifications according to 
paragraphs (a)(1) and (2) of this section if you own or operate one or 
more of the affected facilities specified in Sec.  60.5365b that was 
constructed, modified, or reconstructed during the reporting period. 
You must submit the notification in paragraph (a)(3) of this section if 
you use an alternative standard for fugitive emissions components in 
accordance with Sec.  60.5399b. You must submit the notification in 
paragraph (a)(4) of this section if you undertake well closure 
activities as specified in Sec.  60.5397b(l).
    (1) If you own or operate a process unit equipment affected 
facility located at an onshore natural gas processing plant, or a 
sweetening unit, you must submit the notifications required in 
Sec. Sec.  60.7(a)(1), (3), and (4) and 60.15(d). If you own or operate 
a well, centrifugal compressor, reciprocating compressor, process 
controller, pump, storage vessel, collection of fugitive emissions 
components at a well site, or collection of fugitive emissions 
components at a compressor station affected facility, you are not 
required to submit the notifications required in Sec. Sec.  60.7(a)(1), 
(3), and (4) and 60.15(d).
    (2) If you own or operate a well affected facility, you must notify 
the Administrator no later than 2 days prior to the commencement of 
each well completion operation listing the anticipated date of the well 
completion operation. The notification shall include contact 
information for the owner or operator; the United States Well Number; 
the latitude and longitude coordinates for each well in decimal degrees 
to an accuracy and precision of five (5) decimals of a degree using the 
North American Datum of 1983; and the planned date of the beginning of 
flowback. You may submit the notification in writing or in electronic 
format. If you are subject to state regulations that require advance 
notification of well completions and you have met those notification 
requirements, then you are considered to have met the advance 
notification requirements of this paragraph.
    (3) An owner or operator electing to comply with the provisions of 
Sec.  60.5399b for fugitive emissions components shall notify the 
Administrator of the alternative fugitive emissions standard selected 
within the annual report, as specified in paragraph (b)(9)(iii) of this 
section.
    (4) An owner or operator who commences well closure activities must 
submit the following notices to the Administrator according to the 
schedule in paragraph (a)(4)(i) and (ii) of this section. The 
notification shall include contact information for the owner or 
operator; the United States Well Number; the latitude and longitude 
coordinates for each well at the well site in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using the North 
American Datum of 1983. You must submit notifications in portable 
document format (PDF) following the procedures specified in paragraph 
(d) of this section.
    (i) You must submit a well closure plan to the Administrator within 
30 days of the cessation of production from all wells located at the 
well site.
    (ii) You must submit a notification of the intent to close a well 
site 60 days before you begin well closure activities.
    (b) Reporting requirements. You must submit annual reports 
containing the information specified in paragraphs (b)(1) through (14) 
of this section following the procedure specified in paragraph (b)(15) 
of this section. You must submit performance test reports as specified 
in paragraph (b)(12) or (13) of this section, if applicable. The 
initial annual report is due no later than 90 days after the end of the 
initial compliance period as determined according to Sec.  60.5410b. 
Subsequent annual reports are due no later than the same date each year 
as the initial annual report. If you own or operate more than one 
affected facility, you may submit one report for multiple affected 
facilities provided the report contains all of the information required 
as specified in paragraphs (b)(1) through (14) of this section. Annual 
reports may coincide with title V reports as long as all the required 
elements of the annual report are included. You may arrange with the 
Administrator a common schedule on which reports required by this part 
may be submitted as long as the schedule does not extend the reporting 
period. You must submit the information in paragraph (b)(1)(v) of this 
section, as applicable, for your well affected facility which undergoes 
a change of ownership during the reporting period, regardless of 
whether reporting under paragraphs (b)(2) through (4) of this section 
is required for the well affected facility.
    (1) The general information specified in paragraphs (b)(1)(i) 
through (v) of this section is required for all reports.
    (i) The company name, facility site name associated with the 
affected facility, U.S. Well ID or U.S. Well ID associated with the 
affected facility, if applicable, and address of the affected facility. 
If an address is not available for the site, include a description of 
the site location and provide the latitude and longitude coordinates of 
the site in decimal degrees to an accuracy and precision of five (5) 
decimals of a degree using the North American Datum of 1983.
    (ii) An identification of each affected facility being included in 
the annual report.
    (iii) Beginning and ending dates of the reporting period.
    (iv) A certification by a certifying official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete. If 
your report is submitted via CEDRI, the certifier's electronic 
signature during the submission process replaces the requirement in 
this paragraph (b)(1)(iv).
    (v) Identification of each well affected facility for which 
ownership changed due to sale or transfer of ownership including the 
United States Well Number; the latitude and longitude coordinates of 
the well affected facility in decimal degrees to an accuracy and 
precision of five (5) decimals of a degree using the North American 
Datum of 1983; and the information in paragraph (b)(1)(v)(A) or (B) of 
this section, as applicable.
    (A) The name and contact information, including the phone number, 
email address, and mailing address, of the owner or operator to which 
you sold or transferred ownership of the well affected facility 
identified in paragraph (b)(v) of this section.

[[Page 17111]]

    (B) The name and contact information, including the phone number, 
email address, and mailing address, of the owner or operator from whom 
you acquired the well affected facility identified in paragraph (b)(v) 
of this section.
    (2) For each well affected facility that is subject to Sec.  
60.5375b(a) or (f), the records of each well completion operation 
conducted during the reporting period, including the information 
specified in paragraphs (b)(2)(i) through (xiv) of this section, if 
applicable. In lieu of submitting the records specified in paragraphs 
(b)(2)(i) through (xiv) of this section, the owner or operator may 
submit a list of each well completion with hydraulic fracturing 
completed during the reporting period, and the digital photograph 
required by paragraph (c)(1)(v) of this section for each well 
completion. For each well affected facility that routes all flowback 
entirely through one or more production separators, only the records 
specified in paragraphs (b)(2)(i) through (iv) and (vi) of this section 
are required to be reported. For periods where salable gas is unable to 
be separated, the records specified in paragraphs (b)(2)(iv) and (viii) 
through (xii) of this section must also be reported, as applicable. For 
each well affected facility that is subject to Sec.  60.5375b(g), the 
record specified in paragraph (b)(2)(xv) of this section is required to 
be reported. For each well affected facility which makes a claim that 
the exemption in Sec.  60.5375b(h) was met, the records specified in 
paragraph (b)(2)(i) through (iv) and (b)(2)(xvi) of this section are 
required to be reported.
    (i) Well Completion ID.
    (ii) Latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983.
    (iii) U.S. Well ID.
    (iv) The date and time of the onset of flowback following hydraulic 
fracturing or refracturing or identification that the well immediately 
starts production.
    (v) The date and time of each attempt to direct flowback to a 
separator as required in Sec.  60.5375b(a)(1)(ii).
    (vi) The date and time that the well was shut in and the flowback 
equipment was permanently disconnected, or the startup of production.
    (vii) The duration (in hours) of flowback.
    (viii) The duration (in hours) of recovery and disposition of 
recovery (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).
    (ix) The duration (in hours) of combustion.
    (x) The duration (in hours) of venting.
    (xi) The specific reasons for venting in lieu of capture or 
combustion.
    (xii) For any deviations recorded as specified in paragraph 
(c)(1)(ii) of this section, the date and time the deviation began, the 
duration of the deviation in hours, and a description of the deviation.
    (xiii) For each well affected facility subject to Sec.  
60.5375b(f), a record of the well type (i.e., wildcat well, delineation 
well, or low pressure well (as defined Sec.  60.5430b)) and supporting 
inputs and calculations, if applicable.
    (xiv) For each well affected facility for which you claim an 
exception under Sec.  60.5375b(a)(2), the specific exception claimed 
and reasons why the well meets the claimed exception.
    (xv) For each well affected facility with less than 300 scf of gas 
per stock tank barrel of oil produced, the supporting analysis that was 
performed in order the make that claim, including but not limited to, 
GOR values for established leases and data from wells in the same basin 
and field.
    (xvi) For each well affected facility which meets the exemption in 
Sec.  60.5375b(h), a statement that the well completion operation 
requirements of Sec.  60.5375b(a)(1) through (3) were met.
    (3) For each well affected facility that is subject to Sec.  
60.5376b(a)(1) or (2), your annual report is required to include the 
information specified in paragraphs (b)(3)(i) and (ii) of this section, 
as applicable.
    (i) For each well affected facility where all gas well liquids 
unloading operations comply with Sec.  60.5376b(a)(1), your annual 
report must include the information specified in paragraphs 
(b)(3)(i)(A) through (C) of this section, as applicable.
    (A) Identification of each well affected facility (U.S. Well ID or 
U.S. Well ID associated with the well affected facility) that conducts 
a gas well liquid unloading operation during the reporting period using 
a method that does not vent to the atmosphere and the technology or 
technique used. If more than one non-venting technology or technique is 
used, you must identify all of the differing non-venting liquids 
unloading methods used during the reporting period.
    (B) Number of gas well liquids unloading operations conducted 
during the year where the well affected facility identified in 
(b)(3)(i)(A) had unplanned venting to the atmosphere and best 
management practices were conducted according to your best management 
practice plan, as required by Sec.  60.5376b(c). If no venting events 
occurred, the number would be zero. Other reported information required 
to be submitted where unplanned venting occurs is specified in 
paragraphs (b)(3)(i)(B)(1) and (2) of this section.
    (1) Log of best management practice plan steps used during the 
unplanned venting to minimize emissions to the maximum extent possible.
    (2) The number of liquids unloading events during the year where 
deviations from your best management practice plan occurred, the date 
and time the deviation began, the duration of the deviation in hours, 
documentation of why best management practice plan steps were not 
followed, and what steps, in lieu of your best management practice plan 
steps, were followed to minimize emissions to the maximum extent 
possible.
    (C) The number of liquids unloading events where unplanned 
emissions are vented to the atmosphere during a gas well liquids 
unloading operation where you complied with best management practices 
to minimize emissions to the maximum extent possible.
    (ii) For each well affected facility where all gas well liquids 
unloading operations comply with Sec.  60.5376b(b) and (c) best 
management practices, your annual report must include the information 
specified in paragraphs (b)(3)(ii)(A) through (E) of this section.
    (A) Identification of each well affected facility that conducts a 
gas well liquids unloading during the reporting period.
    (B) Number of liquids unloading events conducted during the 
reporting period.
    (C) Log of best management practice plan steps used during the 
reporting period to minimize emissions to the maximum extent possible.
    (D) The number of liquids unloading events during the year that 
best management practices were conducted according to your best 
management practice plan.
    (E) The number of liquids unloading events during the year where 
deviations from your best management practice plan occurred, the date 
and time the deviation began, the duration of the deviation in hours, 
documentation of why best management practice plan steps were not 
followed, and what steps, in lieu of your best management practice plan 
steps, were followed to minimize emissions to the maximum extent 
possible.
    (4) For each associated gas well subject to Sec.  60.5377b, your 
annual report is required to include the applicable information 
specified in

[[Page 17112]]

paragraphs (b)(4)(i) through (vi) of this section, as applicable.
    (i) For each associated gas well that complies with Sec.  
60.5377b(a)(1), (2), (3), or (4) your annual report is required to 
include the information specified in paragraphs (b)(4)(i)(A) and (B) of 
this section.
    (A) An identification of each associated gas well constructed, 
modified, or reconstructed during the reporting period that complies 
with Sec.  60.5377b(a)(1), (2), (3), or (4).
    (B) The information specified in paragraphs (b)(2)(i)(B)(1) through 
(3) of this section for each incident when the associated gas was 
temporarily routed to a flare or control device in accordance with 
Sec.  60.5377b(d)
    (1) The reason in Sec.  60.5377b(d)(1), (2), (3), or (4) for each 
incident.
    (2) The start date and time of each incident of routing associated 
gas to the flare or control device, along with the total duration in 
hours of each incident.
    (3) Documentation that all CVS requirements specified in Sec.  
60.5411b(a) and (c) and all applicable flare or control device 
requirements specified in Sec.  60.5412b were met during each period 
when the associated gas is routed to the flare or control device.
    (ii) For all instances where you temporarily vent the associated 
gas in accordance with Sec.  60.5377b(e), you must report the 
information specified in paragraphs (b)(4)(ii)(A) through (D) of this 
section. This information is required to be reported if you are 
routinely complying with Sec.  60.5377b(a) or Sec.  60.5377b(f) or 
temporarily complying with Sec.  60.5377b(d). In addition to this 
information for each incident, you must report the cumulative duration 
in hours of venting incidents and the cumulative VOC and methane 
emissions in pounds for all incidents in the calendar year.
    (A) The reason in Sec.  60.5377b(e)(1), (2), or (3) for each 
incident.
    (B) The start date and time of each incident of venting the 
associated gas, along with the total duration in hours of each 
incident.
    (C) The VOC and methane emissions in pounds that were emitted 
during each incident.
    (D) The total duration of venting for all incidents in the year, 
along with the cumulative VOC and methane emissions in pounds that were 
emitted.
    (iii) For each associated gas well that complies with the 
requirements of Sec.  60.5377b(f) your annual report must include the 
information specified in paragraphs (b)(4)(iii)(A) through (E) of this 
section. The information in paragraphs (b)(4)(iii)(A) and (B) of this 
section is only required in the initial annual report.
    (A) An identification of each associated gas well that commenced 
construction between May 7, 2024 and May 7, 2026. This identification 
must include the certification of why it is infeasible to comply with 
Sec.  60.5377b(a)(1), (2), (3), or (4) in accordance with Sec.  
60.5377b(g).
    (B) An identification of each associated gas well that commenced 
construction between December 6, 2022, and May 7, 2024. This 
identification must include the certification of why it is infeasible 
to comply with Sec.  60.5377b(a)(1), (2), (3), or (4) in accordance 
with Sec.  60.5377b(g).
    (C) An identification of each associated gas well modified or 
reconstructed during the reporting period that complies by routing the 
gas to a control device that reduces VOC and methane emissions by at 
least 95.0 percent. This identification must include the certification 
of why it is infeasible to comply with Sec.  60.5377b(a)(1), (2), (3), 
or (4) in accordance with Sec.  60.5377b(g).
    (D) For each associated gas well that was constructed, modified or 
reconstructed in a previous reporting period that complies by routing 
the gas to a control device that reduces VOC and methane emissions by 
at least 95.0 percent, a re-certification of why it is infeasible to 
comply with Sec.  60.5377b(a)(1), (2), (3), or (4) in accordance with 
Sec.  60.5377b(g).
    (E) The information specified in paragraphs (b)(11)(i) through (iv) 
of this section.
    (iv) If you comply with Sec.  60.5377b(f) with a control device, 
identification of the associated gas well using the control device and 
the information in paragraph (b)(11)(v) of this section.
    (v) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(b)(11)(i) and (ii) of this section, you must provide the information 
specified in Sec.  60.5424b.
    (vi) For each deviation recorded as specified in paragraph 
(c)(3)(v) of this section, the date and time the deviation began, the 
duration of the deviation in hours, and a description of the deviation. 
If no deviations occurred during the reporting period, you must include 
a statement that no deviations occurred during the reporting period.
    (5) For each wet seal centrifugal compressor affected facility, the 
information specified in paragraphs (b)(5)(i) through (v) of this 
section. For each self-contained wet seal centrifugal compressor, 
Alaska North Slope centrifugal compressor equipped with sour seal oil 
separator and capture system, or dry seal centrifugal compressor 
affected facility, the information specified in paragraphs (b)(5)(vi) 
through (ix) of this section.
    (i) An identification of each centrifugal compressor constructed, 
modified, or reconstructed during the reporting period.
    (ii) For each deviation that occurred during the reporting period 
and recorded as specified in paragraph (c)(4) of this section, the date 
and time the deviation began, the duration of the deviation in hours, 
and a description of the deviation. If no deviations occurred during 
the reporting period, you must include a statement that no deviations 
occurred during the reporting period.
    (iii) If required to comply with Sec.  60.5380b(a)(2), the 
information specified in paragraphs (b)(11)(i) through (iv) of this 
section.
    (iv) If complying with Sec.  60.5380b(a)(1) with a control device, 
identification of the centrifugal compressor with the control device 
and the information in paragraph (b)(11)(v) of this section.
    (v) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(b)(11)(i) and (ii) of this section, you must provide the information 
specified in Sec.  60.5424b.
    (vi) If complying with Sec.  60.5380b(a)(4) or (5) for a self-
contained wet seal centrifugal compressor, Alaska North Slope 
centrifugal compressor equipped with sour seal oil separator and 
capture system, or dry seal centrifugal compressor requirements, the 
cumulative number of hours of operation since initial startup, since 
May 7, 2024, or since the previous volumetric flow rate emissions 
measurement, as applicable, which have elapsed prior to conducting your 
volumetric flow rate emission measurement or emissions screening.
    (vii) A description of the method used and the results of the 
volumetric emissions measurement or emissions screening, as applicable.
    (viii) Number and type of seals on delay of repair and explanation 
for each delay of repair.
    (ix) Date of planned shutdown(s) that occurred during the reporting 
period if there are any seals that have been placed on delay of repair.
    (6) For each reciprocating compressor affected facility, the 
information specified in paragraphs (b)(6)(i) through (vii) of this 
section, as applicable.
    (i) The cumulative number of hours of operation since initial 
startup, since May 7, 2024, or since the previous volumetric flow rate 
measurement, or since the previous reciprocating

[[Page 17113]]

compressor rod packing replacement, as applicable, which have elapsed 
prior to conducting your volumetric flow rate measurement or emissions 
screening. Alternatively, a statement that emissions from the rod 
packing are being routed to a process or control device through a 
closed vent system.
    (ii) If applicable, for each deviation that occurred during the 
reporting period and recorded as specified in paragraph (c)(5)(i) of 
this section, the date and time the deviation began, duration of the 
deviation in hours and a description of the deviation. If no deviations 
occurred during the reporting period, you must include a statement that 
no deviations occurred during the reporting period.
    (iii) A description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable.
    (iv) If complying with Sec.  60.5385b(d), the information in 
paragraphs (b)(11)(i) through (iv) of this section.
    (v) Number and type of rod packing replacements/repairs on delay of 
repair and explanation for each delay of repair.
    (vi) Date of planned shutdown(s) that occurred during the reporting 
period if there are any rod packing replacements/repairs that have been 
placed on delay of repair.
    (vii) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(b)(11)(i) and (ii) of this section, you must provide the information 
specified in Sec.  60.5424b.
    (7) For each process controller affected facility, the information 
specified in paragraphs (b)(7)(i) through (iii) of this section in your 
initial annual report and in subsequent annual reports for each process 
controller affected facility that is constructed, modified, or 
reconstructed during the reporting period. Each annual report must 
contain the information specified in paragraphs (b)(7)(iv) through (x) 
of this section for each process controller affected facility.
    (i) An identification of each process controller that is driven by 
natural gas, as required by Sec.  60.5390b(d), that allows traceability 
to the records required in paragraph (c)(6)(i) of this section.
    (ii) For each process controller in the affected facility complying 
with Sec.  60.5390b(a), you must report the information specified in 
paragraphs (b)(7)(ii)(A) and (B) of this section, as applicable.
    (A) An identification of each process controller complying with 
Sec.  60.5390b(a) by routing the emissions to a process.
    (B) An identification of each process controller complying with 
Sec.  60.5390b(a) by using a self-contained natural gas-driven process 
controller.
    (iii) For each process controller affected facility located at a 
site in Alaska that does not have access to electrical power and that 
complies with Sec.  60.5390b(b), you must report the information 
specified in paragraphs (b)(7)(iii)(A), (B), or (C) of this section, as 
applicable.
    (A) For each process controller complying with Sec.  60.5390b(b)(1) 
process controller bleed rate requirements, you must report the 
information specified in paragraphs (b)(7)(iii)(A)(1) and (2) of this 
section.
    (1) The identification of process controllers designed and operated 
to achieve a bleed rate less than or equal to 6 scfh.
    (2) Where necessary to meet a functional need, the identification 
and demonstration why it is necessary to use a process controller with 
a natural gas bleed rate greater than 6 scfh.
    (B) An identification of each intermittent vent process controller 
complying with the requirements in paragraph Sec.  60.5390b(b)(2).
    (C) An identification of each process controller complying with the 
requirements in Sec.  60.5390b(b) by routing emissions to a control 
device in accordance with Sec.  60.5390b(b)(3).
    (iv) Identification of each process controller which changes its 
method of compliance during the reporting period and the applicable 
information specified in paragraphs (b)(7)(v) through (ix) of this 
section for the new method of compliance.
    (v) For each process controller in the affected facility complying 
with the requirements of Sec.  60.5390b(a) by routing the emissions to 
a process, you must report the information specified in (b)(11)(i) 
through (iii) of this section.
    (vi) For each process controller in the affected facility complying 
with the requirements of Sec.  60.5390b(a) by using a self-contained 
natural gas-driven process controller, you must report the information 
specified in paragraphs (b)(7)(vi)(A) and (B) of this section.
    (A) Dates of each inspection required under Sec.  60.5416b(b); and
    (B) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and the date of 
repair or date of anticipated repair if repair is delayed.
    (vii) For each process controller in the affected facility 
complying with the requirements of Sec.  60.5390b(b)(2), you must 
report the information specified in paragraphs (b)(7)(vii)(A) and (B) 
of this section.
    (A) Dates and results of the intermittent vent process controller 
monitoring required by Sec.  60.5390b(b)(2)(ii).
    (B) For each instance in which monitoring identifies emissions to 
the atmosphere from an intermittent vent controller during idle 
periods, the date of repair or replacement or the date of anticipated 
repair or replacement if the repair or replacement is delayed, and the 
date and results of the re-survey after repair or replacement.
    (viii) For each process controller affected facility complying with 
Sec.  60.5390b(b)(3) by routing emissions to a control device, you must 
report the information specified in paragraph (b)(11) of this section.
    (ix) For each deviation that occurred during the reporting period, 
the date and time the deviation began, the duration of the deviation in 
hours, and a description of the deviation. If no deviations occurred 
during the reporting period, you must include a statement that no 
deviations occurred during the reporting period.
    (x) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(b)(7)(ii)(B) and (b)(11)(i) and (ii) of this section, you must provide 
the information specified in Sec.  60.5424b.
    (8) For each storage vessel affected facility, the information in 
paragraphs (b)(8)(i) through (x) of this section.
    (i) An identification, including the location, of each storage 
vessel affected facility, including those for which construction, 
modification, or reconstruction commenced during the reporting period, 
and those provided in previous reports. The location of the storage 
vessel affected facility shall be in latitude and longitude coordinates 
in decimal degrees to an accuracy and precision of five (5) decimals of 
a degree using the North American Datum of 1983.
    (ii) Documentation of the methane and VOC emission rate 
determination according to Sec.  60.5365b(e)(1) for each tank battery 
that became an affected facility during the reporting period or is 
returned to service during the reporting period.
    (iii) For each deviation that occurred during the reporting period 
and recorded as specified in paragraph (c)(7)(iii) of this section, the 
date and time the deviation began, duration of the deviation in hours 
and a description of the deviation. If no deviations occurred during 
the reporting period, you must include a statement that no deviations 
occurred during the reporting period.
    (iv) For each storage vessel affected facility constructed, 
modified,

[[Page 17114]]

reconstructed, or returned to service during the reporting period 
complying with Sec.  60.5395b(a)(2) with a control device, report the 
identification of the storage vessel affected facility with the control 
device and the information in paragraph (b)(11)(v) of this section.
    (v) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(b)(11)(i) and (ii) of this section, you must provide the information 
specified in Sec.  60.5424b.
    (vi) If required to comply with Sec.  60.5395b(b)(1), the 
information in paragraphs (b)(11)(i) through (iv) of this section.
    (vii) You must identify each storage vessel affected facility that 
is removed from service during the reporting period as specified in 
Sec.  60.5395b(c)(1)(ii), including the date the storage vessel 
affected facility was removed from service. You must identify each 
storage vessel that that is removed from service from a storage vessel 
affected facility during the reporting period as specified in Sec.  
60.5395b(c)(2)(iii), including identifying the impacted storage vessel 
affected facility and the date each storage vessel was removed from 
service.
    (viii) You must identify each storage vessel affected facility or 
portion of a storage vessel affected facility returned to service 
during the reporting period as specified in Sec.  60.5395b(c)(4), 
including the date the storage vessel affected facility or portion of a 
storage vessel affected facility was returned to service.
    (ix) You must identify each storage vessel affected facility that 
no longer complies with Sec.  60.5395b(a)(3) and instead complies with 
Sec.  60.5395b(a)(2). You must identify whether the change in the 
method of compliance was due to fracturing or refracturing or whether 
the change was due to an increase in the monthly emissions 
determination. If the change was due to an increase in the monthly 
emissions determination, you must provide documentation of the 
emissions rate. You must identify the date that you complied with Sec.  
60.5395b(a)(2) and must submit the information in (b)(8)(iii) through 
(vii) of this section.
    (x) You must submit a statement that you are complying with Sec.  
60.112b(a)(1) or (2), if applicable, in your initial annual report.
    (9) For the fugitive emissions components affected facility, report 
the information specified in paragraphs (b)(9)(i) through (v) of this 
section, as applicable.
    (i)(A) 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.
    (B) For the fugitive emissions components affected facility at a 
well site or centralized production facility that became an affected 
facility during the reporting period, you must include the date of the 
startup of production or the date of the first day of production after 
modification. For the fugitive emissions components affected facility 
at a compressor station that became an affected facility during the 
reporting period, you must include the date of startup or the date of 
modification.
    (C) For the fugitive emissions components affected facility at a 
well site, you must specify what type of well site it is (i.e., single 
wellhead only well site, small wellsite, multi-wellhead only well site, 
or a well site with major production and processing equipment).
    (D) For the fugitive emissions components affected facility at a 
well site where during the reporting period you complete the removal of 
all major production and processing equipment such that the well site 
contains only one or more wellheads, you must include the date of the 
change to status as a wellhead only well site.
    (E) For the fugitive emissions components affected facility at a 
well site where you previously reported under paragraph (b)(9)(i)(D) of 
this section the removal of all major production and processing 
equipment and during the reporting period major production and 
processing equipment is added back to the well site, the date that the 
first piece of major production and processing equipment is added back 
to the well site.
    (F) For the fugitive emissions components affected facility at a 
well site where during the reporting period you undertake well closure 
requirements, the date of the cessation of production from all wells at 
the well site, the date you began well closure activities at the well 
site, and the dates of the notifications submitted in accordance with 
paragraph (a)(4) of this section.
    (ii) For each fugitive emissions monitoring survey performed during 
the annual reporting period, the information specified in paragraphs 
(b)(9)(ii)(A) through (G) of this section.
    (A) Date of the survey.
    (B) Monitoring instrument or, if the survey was conducted by AVO 
methods, notation that AVO was used.
    (C) Any deviations from the monitoring plan elements under Sec.  
60.5397b(c)(1), (2), and (7), (c)(8)(i), or (d) or a statement that 
there were no deviations from these elements of the monitoring plan.
    (D) Number and type of components for which fugitive emissions were 
detected.
    (E) Number and type of fugitive emissions components that were not 
repaired as required in Sec.  60.5397b(h).
    (F) 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.
    (G) Date of planned shutdown(s) that occurred during the reporting 
period if there are any components that have been placed on delay of 
repair.
    (iii) For the fugitive emissions components affected facility 
complying with an alternative fugitive emissions standard under Sec.  
60.5399b, in lieu of the information specified in paragraphs (b)(9)(i) 
and (ii) of this section, you must provide the information specified in 
paragraphs (b)(9)(iii)(A) through (C) of this section.
    (A) The alternative standard with which you are complying.
    (B) The site-specific reports specified by the specific alternative 
fugitive emissions standard, submitted in the format in which they were 
submitted to the state, local, or Tribal authority. If the report is in 
hard copy, you must scan the document and submit it as an electronic 
attachment to the annual report required in paragraph (b) of this 
section.
    (C) If the report specified by the specific alternative fugitive 
emissions standard is not site-specific, you must submit the 
information specified in paragraphs (b)(9)(i) and (ii) of this section 
for each individual site complying with the alternative standard.
    (iv) For well closure activities which occurred during the 
reporting period, the information in paragraphs (b)(9)(iv)(A) and (B) 
of this section.
    (A) A status report with dates for the well closure activities 
schedule developed in the well closure plan. If all steps in the well 
closure plan are completed in the reporting period, the date that all 
activities are completed.
    (B) If an OGI survey is conducted during the reporting period, the 
information in paragraphs (b)(9)(iv)(B)(1) through (3) of this section.
    (1) Date of the OGI survey.
    (2) Monitoring instrument used.
    (3) A statement that no fugitive emissions were found, or if 
fugitive emissions were found, a description of the steps taken to 
eliminate those emissions, the date of the resurvey, the results of the 
resurvey, and the date of

[[Page 17115]]

the final resurvey which detected no emissions.
    (v) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(b)(9)(i) and (ii) of this section, you must provide the information 
specified in Sec.  60.5424b.
    (10) For each pump affected facility, the information specified in 
paragraphs (b)(10)(i) through (iv) of this section in your initial 
annual report and in subsequent annual reports for each pump affected 
facility that is constructed, modified, or reconstructed during the 
reporting period. Each annual report must contain the information 
specified in paragraphs (b)(10)(v) through (ix) of this section for 
each pump affected facility.
    (i) The identification of each of your pumps that are driven by 
natural gas, as required by Sec.  60.5393b(a) that allows traceability 
to the records required by paragraph (c)(15)(i) of this section.
    (ii) For each pump affected facility for which there is a control 
device on site but it does not achieve a 95.0 percent emissions 
reduction, the certification that there is a control device available 
on site but it does not achieve a 95.0 percent emissions reduction 
required under Sec.  60.5393b(b)(3). You must also report the emissions 
reduction percentage the control device is designed to achieve.
    (iii) For each pump affected facility for which there is no control 
device or vapor recovery unit on site, the certification required under 
Sec.  60.5393b(b)(4) that there is no control device or vapor recovery 
unit on site.
    (iv) For each pump affected facility for which it is technically 
infeasible to route the emissions to a process or control device, the 
certification of technically infeasibility required under Sec.  
60.5393b(b)(5).
    (v) For any pump affected facility which has previously reported as 
required under paragraph (b)(10)(i) through (iv) of this section and 
for which a change in the reported condition has occurred during the 
reporting period, provide the identification of the pump affected 
facility and the date that the pump affected facility meets one of the 
change conditions described in paragraphs (b)(10)(v)(A), (B), or (C) of 
this section.
    (A) If you install a control device or vapor recovery unit, you 
must report that a control device or vapor recovery unit has been added 
to the site and that the pump affected facility now is required to 
comply with Sec.  60.5393b(b)(1) or (3), as applicable.
    (B) If your pump affected facility previously complied with Sec.  
60.5393b(b)(1) or (3) by routing emissions to a process or a control 
device and the process or control device is subsequently removed from 
the site or is no longer available such that there is no ability to 
route the emissions to a process or control device at the site, or that 
it is not technically feasible to capture and route the emissions to 
another control device or process located on site, report that you are 
no longer complying with the applicable requirements of Sec.  
60.5393b(b)(1) or (3) and submit the information provided in paragraphs 
(b)(10)(v)(B)(1) or (2) of this section.
    (1) Certification that there is no control device or vapor recovery 
unit on site.
    (2) Certification of the engineering assessment that it is 
technically infeasible to capture and route the emissions to another 
control device or process located on site.
    (C) If any pump affected facility or individual natural gas-driven 
pump changes its method of compliance during the reporting period other 
than for the reasons specified in paragraphs (10)(v)(A) and (B) of this 
section, identify the new compliance method for each natural gas-driven 
pump within the affected facility which changes its method of 
compliance during the reporting period and provide the applicable 
information specified in paragraphs (b)(10)(ii) through (iv) and (vi) 
through (viii) of this section for the new method of compliance.
    (vi) For each pump affected facility complying with the 
requirements of Sec.  60.5393b(a), (b)(1), or (b)(3) by routing the 
emissions to a process, you must report the information specified in 
paragraphs (b)(11)(i) through (iv) of this section.
    (vii) For each pump affected facility complying with the 
requirements of Sec.  60.5393b(b)(1) or (3) by routing the emissions to 
a control device, you must report the information required under 
paragraph (b)(11) of this section.
    (viii) For each deviation that occurred during the reporting 
period, the date and time the deviation began, the duration of the 
deviation in hours, and a description of the deviation. If no 
deviations occurred during the reporting period, you must include a 
statement that no deviations occurred during the reporting period.
    (ix) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(b)(11)(i) and (ii) of this section, you must provide the information 
specified in Sec.  60.5424b.
    (11) For each well, centrifugal compressor, reciprocating 
compressor, storage vessel, process controller, pump, or process unit 
equipment affected facility which uses a closed vent system routed to a 
control device to meet the emissions reduction standard, you must 
submit the information in paragraphs (b)(11)(i) through (v) of this 
section. For each reciprocating compressor, process controller, pump, 
storage vessel, or process unit equipment which uses a closed vent 
system to route to a process, you must submit the information in 
paragraphs (b)(11)(i) through (iv) of this section. For each 
centrifugal compressor, reciprocating compressor, and storage vessel 
equipped with a cover, you must submit the information in paragraphs 
(b)(11)(i) and (ii) of this section.
    (i) Dates of each inspection required under Sec.  60.5416b(a) and 
(b).
    (ii) Each defect or emissions identified during each inspection and 
the date of repair or the date of anticipated repair if the repair is 
delayed.
    (iii) Date and time of each bypass alarm or each instance the key 
is checked out if you are subject to the bypass requirements of Sec.  
60.5416b(a)(4).
    (iv) You must submit the certification signed by the qualified 
professional engineer or in-house engineer according to Sec.  
60.5411b(c) for each closed vent system routing to a control device or 
process in the reporting year in which the certification is signed.
    (v) If you comply with the emissions standard for your well, 
centrifugal compressor, reciprocating compressor, storage vessel, 
process controller, pump, or process unit equipment affected facility 
with a control device, the information in paragraphs (b)(11)(v)(A) 
through (L) of this section, unless you use an enclosed combustion 
device or flare using an alternative test method approved under Sec.  
60.5412b(d). If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412b(d), the 
information in paragraphs (b)(11)(v)(A) through (C) and (L) through (P) 
of this section.
    (A) Identification of the control device.
    (B) Make, model, and date of installation of the control device.
    (C) Identification of the affected facility controlled by the 
device.
    (D) For each continuous parameter monitoring system used to 
demonstrate compliance for the control device, a unique continuous 
parameter monitoring system identifier and the make, model number, and 
date of last calibration check of the continuous parameter monitoring 
system.

[[Page 17116]]

    (E) For each instance where there is a deviation of the control 
device in accordance with Sec.  60.5417b(g)(1) through (3) or (g)(5) 
through (7) include the date and time the deviation began, the duration 
of the deviation in hours, the type of the deviation (e.g., NHV 
operating limit, lack of pilot or combustion flame, condenser 
efficiency, bypass line flow, visible emissions), and cause of the 
deviation.
    (F) For each instance where there is a deviation of the continuous 
parameter monitoring system in accordance with Sec.  60.5417b(g)(4) 
include the date and time the deviation began, the duration of the 
deviation in hours, and cause of the deviation.
    (G) For each visible emissions test following return to operation 
from a maintenance or repair activity, the date of the visible 
emissions test or observation of the video surveillance output, the 
length of the observation in minutes, and the number of minutes for 
which visible emissions were present.
    (H) If a performance test was conducted on the control device 
during the reporting period, provide the date the performance test was 
conducted. Submit the performance test report following the procedures 
specified in paragraph (b)(12) of this section.
    (I) If a demonstration of the NHV of the inlet gas to the enclosed 
combustion device or flare was conducted during the reporting period in 
accordance with Sec.  60.5417b(d)(8)(iii), an indication of whether 
this is a re-evaluation of vent gas NHV and the reason for the re-
evaluation; the applicable required minimum vent gas NHV; if twice 
daily samples of the vent stream were taken, the number of hourly 
average NHV values that are less than 1.2 times the applicable required 
minimum NHV; if continuous NHV sampling of the vent stream was 
conducted, the number of hourly average NHV values that are less than 
the required minimum vent gas NHV; if continuous combustion efficiency 
monitoring was conducted using an alternative test method approved 
under Sec.  60.5412b(d), the number of values of the combustion 
efficiency that were less than 95.0 percent; the resulting 
determination of whether NHV monitoring is required or not in 
accordance with Sec.  60.5417b(d)(8)(iii)(D) or (H); and an indication 
of whether the enclosed combustion device or flare has the potential to 
receive inert gases, and if so, whether the sampling included periods 
where the highest percentage of inert gases were sent to the enclosed 
combustion device or flare.
    (J) If a demonstration was conducted in accordance with Sec.  
60.5417b(d)(8)(iv) that the maximum potential pressure of units 
manifolded to an enclosed combustion device or flare cannot cause the 
maximum inlet flow rate established in accordance with Sec.  
60.5417b(f)(1) or a flare tip velocity limit of 18.3 meter/second (60 
feet/second) to be exceeded, an indication of whether this is a re-
evaluation of the gas flow and the reason for the re-evaluation; the 
demonstration conducted; and applicable engineering calculations.
    (K) For each periodic sampling event conducted under Sec.  
60.5417b(d)(8)(iii)(G), provide the date of the sampling, the required 
minimum vent gas NHV, and the NHV value for each vent gas sample.
    (L) For each flare and enclosed combustion device, provide the date 
each device is observed with OGI in accordance with Sec.  
60.5415b(f)(x) and whether uncombusted emissions were present. Provide 
the date each device was visibly observed during an AVO inspection in 
accordance with Sec.  60.5415b(f)(x), whether the pilot or combustion 
flame was lit at the time of observation, and whether the device was 
found to be operating properly.
    (M) An identification of the alternative test method used.
    (N) For each instance where there is a deviation of the control 
device in accordance with Sec.  60.5417b(i)(6)(i) or (iii) through (v) 
include the date and time the deviation began, the duration of the 
deviation in hours, the type of the deviation (e.g., NHV<INF>cz</INF> 
operating limit, lack of pilot or combustion flame, visible emissions), 
and cause of the deviation.
    (O) For each instance where there is a deviation of the data 
availability in accordance with Sec.  60.5417b(i)(6)(ii) include the 
date of each operating day when monitoring data are not available for 
at least 75 percent of the operating hours.
    (P) If no deviations occurred under paragraphs (b)(11)(v)(N) or (O) 
of this section, a statement that there were no deviations for the 
control device during the annual report period.
    (Q) Any additional information required to be reported as specified 
by the Administrator as part of the alternative test method approval 
under Sec.  60.5412b(d).
    (12) Within 60 days after the date of completing each performance 
test (see Sec.  60.8) required by this subpart, except testing 
conducted by the manufacturer as specified in Sec.  60.5413b(d), you 
must submit the results of the performance test following the 
procedures specified in paragraph (d) of this section. Data collected 
using test methods that are supported by the EPA's Electronic Reporting 
Tool (ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at 
the time of the test must be submitted in a file format generated using 
the EPA's ERT. Alternatively, you may submit an electronic file 
consistent with the extensible markup language (XML) schema listed on 
the EPA's ERT website. Data collected using test methods that are not 
supported by the EPA's ERT as listed on the EPA's ERT website at the 
time of the test must be included as an attachment in the ERT or 
alternate electronic file.
    (13) For combustion control devices tested by the manufacturer in 
accordance with Sec.  60.5413b(d), an electronic copy of the 
performance test results required by Sec.  60.5413b(d) shall be 
submitted via email to <a href="/cdn-cgi/l/email-protection#e6a98f8ab9878882b9a18795b9b6b2a6a3b6a7c8a1a9b0"><span class="__cf_email__" data-cfemail="f7b89e9ba8969993a8b09684a8a7a3b7b2a7b6d9b0b8a1">[email protected]</span></a> unless the test results 
for that model of combustion control device are posted at the following 
website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
    (14) If you had a super-emitter event during the reporting period, 
the start date of the super-emitter event, the duration of the super-
emitter event in hours, and the affected facility associated with the 
super-emitter event, if applicable.
    (15) You must submit your annual report using the appropriate 
electronic report template on the Compliance and Emissions Data 
Reporting Interface (CEDRI) website for this subpart and following the 
procedure specified in paragraph (d) of this section. If the reporting 
form specific to this subpart is not available on the CEDRI website at 
the time that the report is due, you must submit the report to the 
Administrator at the appropriate address listed in Sec.  60.4. Once the 
form has been available on the CEDRI website for at least 90 calendar 
days, you must begin submitting all subsequent reports via CEDRI. The 
date reporting forms become available will be listed on the CEDRI 
website. Unless the Administrator or delegated state agency or other 
authority has approved a different schedule for submission of reports, 
the report must be submitted by the deadline specified in this subpart, 
regardless of the method in which the report is submitted.
    (c) Recordkeeping requirements. You must maintain the records 
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1) 
through (15) of this section. All records required by this subpart must 
be maintained either onsite or at the nearest local field office for at 
least 5 years. Any records required to be maintained by this subpart 
that are

[[Page 17117]]

submitted electronically via the EPA's CEDRI may be maintained in 
electronic format. This ability to maintain electronic copies does not 
affect the requirement for facilities to make records, data, and 
reports available upon request to a delegated air agency or the EPA as 
part of an on-site compliance evaluation.
    (1) The records for each well affected facility subject to the well 
completion operation standards of Sec.  60.5375b, as specified in 
paragraphs (c)(1)(i) through (vii) of this section, as applicable. For 
each well affected facility subject to the well completion operations 
of Sec.  60.5375b, for which you make a claim that the well affected 
facility is not subject to the requirements for well completions 
pursuant to Sec.  60.5375b(g), you must maintain the record in 
paragraph (c)(1)(vi) of this section, only. For each well affected 
facility which meets the exemption in Sec.  60.5375b(h) for well 
completion operations (i.e., an existing well is hydraulically 
refractured), you must maintain the records in paragraph (c)(1)(viii), 
only. For each well affected facility that routes flowback entirely 
through one or more production separators that are designed to 
accommodate flowback, only records of the United States Well Number, 
the latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983, the Well Completion ID, and the date and time 
of startup of production are required. For periods where salable gas is 
unable to be separated, records of the date and time of onset of 
flowback, the duration and disposition of recovery, the duration of 
combustion and venting (if applicable), reasons for venting (if 
applicable), and deviations are required.
    (i) Records identifying each well completion operation for each 
well affected facility.
    (ii) Records of deviations in cases where well completion 
operations with hydraulic fracturing were not performed in compliance 
with the requirements specified in Sec.  60.5375b, including the date 
and time the deviation began, the duration of the deviation, and a 
description of the deviation.
    (iii) You must maintain the records specified in paragraphs 
(c)(1)(iii)(A) through (C) of this section.
    (A) For each well affected facility required to comply with the 
requirements of Sec.  60.5375b(a), you must record: The latitude and 
longitude of the well in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using North American Datum of 1983; 
the United States Well Number; the date and time of the onset of 
flowback following hydraulic fracturing or refracturing; the date and 
time of each attempt to direct flowback to a separator as required in 
Sec.  60.5375b(a)(1)(ii); the date and time of each occurrence of 
returning to the initial flowback stage under Sec.  60.5375b(a)(1)(i); 
and the date and time that the well was shut in and the flowback 
equipment was permanently disconnected, or the startup of production; 
the duration of flowback; duration of recovery and disposition of 
recovery (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); duration of combustion; duration of venting; and 
specific reasons for venting in lieu of capture or combustion. The 
duration must be specified in hours. In addition, for wells where it is 
technically infeasible to route the recovered gas as specified in Sec.  
60.5375b(a)(1)(ii), you must record the reasons for the claim of 
technical infeasibility with respect to all four options provided in 
Sec.  60.5375b(a)(1)(ii).
    (B) For each well affected facility required to comply with the 
requirements of Sec.  60.5375b(f), you must record: Latitude and 
longitude of the well in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using North American Datum of 1983; 
the United States Well Number; the date and time of the onset of 
flowback following hydraulic fracturing or refracturing; the date and 
time that the well was shut in and the flowback equipment was 
permanently disconnected, or the startup of production; the duration of 
flowback; duration of combustion; duration of venting; and specific 
reasons for venting in lieu combustion. The duration must be specified 
in hours.
    (C) For each well affected facility for which you make a claim that 
it meets the criteria of Sec.  60.5375b(a)(1)(iii)(A), you must 
maintain the following:
    (1) The latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983; the United States Well Number; the date and 
time of the onset of flowback following hydraulic fracturing or 
refracturing; the date and time that the well was shut in and the 
flowback equipment was permanently disconnected, or the startup of 
production; the duration of flowback; duration of recovery and 
disposition of recovery (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); duration of combustion; 
duration of venting; and specific reasons for venting in lieu of 
capture or combustion. The duration must be specified in hours.
    (2) If applicable, records that the conditions of Sec.  
60.5375b(a)(1)(iii)(A) are no longer met and that the well completion 
operation has been stopped and a separator installed. The records shall 
include the date and time the well completion operation was stopped and 
the date and time the separator was installed.
    (3) A record of the claim signed by the certifying official that no 
liquids collection is at the well site. The claim must include a 
certification by a certifying official of truth, accuracy, and 
completeness. This certification shall state that, based on information 
and belief formed after reasonable inquiry, the statements and 
information in the document are true, accurate, and complete.
    (iv) For each well affected facility for which you claim an 
exception under Sec.  60.5375b(a)(2), you must record: The latitude and 
longitude of the well in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using North American Datum of 1983; 
the United States Well Number; the specific exception claimed; the 
starting date and ending date for the period the well operated under 
the exception; and an explanation of why the well meets the claimed 
exception.
    (v) For each well affected facility required to comply with both 
Sec.  60.5375b(a)(1) and (2), if you are using a digital photograph in 
lieu of the records required in paragraphs (c)(1)(i) through (iv) of 
this section, you must retain the records of the digital photograph as 
specified in Sec.  60.5410b(a)(4).
    (vi) For each well affected facility for which you make a claim 
that the well affected facility is not subject to the well completion 
standards according to Sec.  60.5375b(g), you must maintain:
    (A) A record of the analysis that was performed in order the make 
that claim, including but not limited to, GOR values for established 
leases and data from wells in the same basin and field;
    (B) The latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983; the United States Well Number;
    (C) A record of the claim signed by the certifying official. The 
claim must include a certification by a certifying official of truth, 
accuracy, and

[[Page 17118]]

completeness. This certification shall state that, based on information 
and belief formed after reasonable inquiry, the statements and 
information in the document are true, accurate, and complete.
    (vii) For each well affected facility subject to Sec.  60.5375b(f), 
a record of the well type (i.e., wildcat well, delineation well, or low 
pressure well (as defined Sec.  60.5430b)) and supporting inputs and 
calculations, if applicable.
    (viii) For each well affected facility which makes a claim it meets 
the exemption at Sec.  60.5375b(h), a record of the latitude and 
longitude of the well in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using North American Datum of 1983; 
the United States Well Number; the date and time of the onset of 
flowback following hydraulic fracturing or refracturing and a record of 
the claim that the well completion operation requirements of Sec.  
60.5375b(a)(1) through (3) were met.
    (2) For each gas well liquids unloading operation at your well 
affected facility that is subject to Sec.  60.5376b(a)(1) or (2), the 
records of each gas well liquids unloading operation conducted during 
the reporting period, including the information specified in paragraphs 
(c)(2)(i) through (iii) of this section, as applicable.
    (i) For each gas well liquids unloading operation that complies 
with Sec.  60.5376b(a)(1) by performing all liquids unloading events 
without venting of methane and VOC emissions to the atmosphere, comply 
with the recordkeeping requirements specified in paragraphs 
(c)(2)(i)(A) and (B) of this section.
    (A) Identification of each well (i.e., U.S. Well ID or U.S. Well ID 
associated with the well affected facility) that conducts a gas well 
liquids unloading operation during the reporting period without venting 
of methane and VOC emissions and the non-venting methane and VOC gas 
well liquids unloading method used. If more than one non-venting method 
is used, you must maintain records all of the differing non-venting 
liquids unloading methods used at the well affected facility complying 
with Sec.  60.5376b(a)(1).
    (B) Number of events where unplanned emissions are vented to the 
atmosphere during a gas well liquids unloading operation where you 
complied with best management practices to minimize emissions to the 
maximum extent possible.
    (ii) For each gas well liquids unloading operation that complies 
with Sec.  60.5376b(b) and (c) best management practices, maintain 
records documenting information specified in paragraphs (c)(2)(ii)(A) 
through (D) of this section.
    (A) Identification of each well affected facility that conducts 
liquids unloading during the reporting period that employs best 
management practices to minimize emissions to the maximum extent 
possible.
    (B) Documentation of your best management practice plan developed 
under paragraph Sec.  60.5376b(c). You may update your best management 
practice plan to include additional steps which meet the criteria in 
Sec.  60.5376b(c).
    (C) A log of each best management practice plan step taken minimize 
emissions to the maximum extent possible for each gas well liquids 
unloading event.
    (D) Documentation of each gas well liquids unloading event where 
deviations from your best management practice plan steps occurred, the 
date and time the deviation began, the duration of the deviation, 
documentation of best management practice plans steps were not 
followed, and the steps taken in lieu of your best management practice 
plan steps during those events to minimize emissions to the maximum 
extent possible.
    (iii) For each well affected facility that reduces methane and VOC 
emissions from well affected facility gas wells that unload liquids by 
95.0 percent by routing emissions to a control device through closed 
vent system under Sec.  60.5376b(g), you must maintain the records in 
paragraphs (c)(2)(iii)(A) through (E) of this section.
    (A) If you comply with the emission reduction standard with a 
control device, the information for each control device in paragraph 
(c)(11) of this section.
    (B) Records of the closed vent system inspection as specified 
paragraph (c)(8) of this section.
    (C) Records of the cover inspections as specified in paragraph 
(c)(9) of this section.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(10) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(12) of this section.
    (3) For each associated gas well, you must maintain the applicable 
records specified in paragraphs (c)(3)(i) or (ii) and (c)(3)(iv) of 
this section.
    (i) For each associated gas well that complies with the 
requirements of Sec.  60.5377b(a)(1), (2), (3), or (4), you must keep 
the records specified in paragraphs (c)(3)(i)(A) and (B).
    (A) Documentation of the specific method(s) in Sec.  
60.5377b(a)(1), (2), (3), or (4) that is used.
    (B) For instances where you temporarily route the associated gas to 
a flare or control device in accordance with Sec.  60.5377b(d), you 
must keep the records specified in paragraphs (c)(3)(i)(B)(1) through 
(3).
    (1) The reason in Sec.  60.5377b(d)(1), (2), (3), or (4) for each 
incident.
    (2) The date of each incident, along with the times when routing 
the associated gas to the flare or control device started and ended, 
along with the total duration of each incident.
    (3) Documentation that all CVS requirements specified in Sec.  
60.5411b(a) and (c) and all applicable flare or control device 
requirements specified in Sec.  60.5412b are met during each period 
when the associated gas is routed to the flare or control device.
    (ii) For instances where you temporarily vent the associated gas in 
accordance with Sec.  60.5377b(e), you must keep the records specified 
in paragraphs (c)(3)(ii)(A) through (D). These records are required if 
you are routinely complying with Sec.  60.5377b(a) or Sec.  60.5377b(f) 
or temporarily complying with Sec.  60.5377b(d).
    (A) The reason in Sec.  60.5377b(e)(1), (2), or (3) for each 
incident.
    (B) The date of each incident, along with the times when venting 
the associated gas started and ended, along with the total duration of 
each incident.
    (C) The VOC and methane emissions that were emitted during each 
incident.
    (D) The cumulative duration of venting incidents and VOC and 
methane emissions for all incidents in each calendar year.
    (iii) For each associated gas well that complies with the 
requirements of Sec.  60.5377b(f) because it has demonstrated that it 
is not feasible to comply with Sec.  60.5377b(a)(1), (2), (3), and (4) 
due to technical reasons in accordance with Sec.  60.5377b(g), records 
of each annual demonstration and certification of the technical reason 
that it is not feasible to comply with Sec.  60.5377b(a)(1), (2), (3), 
and (4) in accordance with Sec.  60.5377b(g).
    (iv) For each associated gas well that complies with the 
requirements of Sec.  60.5377b(f), meet the recordkeeping requirements 
specified in paragraphs (c)(3)(iv)(A) through (E).
    (A) Identification of each instance when associated gas was vented 
and not routed to a control device that reduces VOC and methane 
emissions by at least 95.0 percent.
    (B) If you comply with the emission reduction standard in Sec.  
60.5380b with a control device, the information for each

[[Page 17119]]

control device in paragraph (c)(11) of this section.
    (C) Records of the closed vent system inspection as specified 
paragraph (c)(8) of this section. If you comply with an alternative GHG 
and VOC standard under Sec.  60.5398b, in lieu of the information 
specified in paragraph (c)(8) of this section, you must maintain 
records of the information specified in Sec.  60.5424b.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(10) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(12) of this section.
    (v) Records of each deviation, the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation.
    (4) For each centrifugal compressor affected facility, you must 
maintain the records specified in paragraphs (c)(4)(i) through (iii) of 
this section.
    (i) For each centrifugal compressor affected facility, you must 
maintain records of deviations in cases where the centrifugal 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5380b, including a description of each deviation, 
the date and time each deviation began and the duration of each 
deviation.
    (ii) For each wet seal compressor complying with the emissions 
reduction standard in Sec.  60.5380b(a)(1), you must maintain the 
records in paragraphs (c)(4)(ii)(A) through (E) of this section. For 
each wet seal compressor complying with the alternative standard in 
Sec.  60.5380b(a)(3) by routing the closed vent system to a process, 
you must maintain the records in paragraphs (c)(4)(ii)(B) through (E) 
of this section.
    (A) If you comply with the emission reduction standard in Sec.  
60.5380b(a)(1) with a control device, the information for each control 
device in paragraph (c)(11) of this section.
    (B) Records of the closed vent system inspection as specified 
paragraph (c)(8) of this section. If you comply with an alternative GHG 
and VOC standard under Sec.  60.5398b, in lieu of the information 
specified in paragraph (c)(8) of this section, you must maintain the 
information specified in Sec.  60.5424b.
    (C) Records of the cover inspections as specified in paragraph 
(c)(9) of this section. If you comply with an alternative GHG and VOC 
standard under Sec.  60.5398b, in lieu of the information specified in 
paragraphs (c)(9) of this section, you must maintain the information 
specified in Sec.  60.5424b.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(10) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(12) of this section.
    (iii) For each centrifugal compressor affected facility using a 
self-contained wet seal compressor, or dry seal compressor complying 
with the standard in Sec.  60.5380b(a)(4) and (5), you must maintain 
the records specified in paragraphs (c)(4)(iii)(A) through (H) of this 
section.
    (A) Records of the cumulative number of hours of operation since 
initial startup, since May 7, 2024, or since the previous volumetric 
flow rate measurement, as applicable.
    (B) A description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable.
    (C) Records for all flow meters, composition analyzers and pressure 
gauges used to measure volumetric flow rates as specified in paragraphs 
(c)(4)(iii)(C)(1) through (6).
    (1) Description of standard method published by a consensus-based 
standards organization or industry standard practice.
    (2) Records of volumetric flow rate emissions calculations 
conducted according to paragraphs Sec.  60.5380b(a)(5), as applicable.
    (3) Records of manufacturer's operating procedures and measurement 
methods.
    (4) Records of manufacturer's recommended procedures or an 
appropriate industry consensus standard method for calibration and 
results of calibration, recalibration, and accuracy checks.
    (5) Records which demonstrate that measurements at the remote 
location(s) can, when appropriate correction factors are applied, 
reliably and accurately represent the actual temperature or total 
pressure at the flow meter under all expected ambient conditions. You 
must include the date of the demonstration, the data from the 
demonstration, the mathematical correlation(s) between the remote 
readings and actual flow meter conditions derived from the data, and 
any supporting engineering calculations. If adjustments were made to 
the mathematical relationships, a record and description of such 
adjustments.
    (6) Record of each initial calibration or a recalibration which 
failed to meet the required accuracy specification and the date of the 
successful recalibration.
    (D) Date when performance-based volumetric flow rate is exceeded.
    (E) The date of successful repair of the compressor seal, including 
follow-up performance-based volumetric flow rate measurement to confirm 
successful repair.
    (F) Identification of each compressor seal placed on delay of 
repair and explanation for each delay of repair.
    (G) For each compressor seal or part needed for repair placed on 
delay of repair because of replacement seal or part unavailability, the 
operator must document: the date the seal or part was added to the 
delay of repair list, the date the replacement seal or part was 
ordered, the anticipated seal or part delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the seal or part.
    (H) Date of planned shutdowns that occur while there are any seals 
or parts that have been placed on delay of repair.
    (5) For each reciprocating compressor affected facility, you must 
maintain the records in paragraphs (c)(5)(i) through (x), and (c)(8), 
(c)(10) and (c)(12) of this section, as applicable. If you comply with 
an alternative GHG and VOC standard under Sec.  60.5398b, in lieu of 
the information specified in paragraph (c)(8) of this section, you must 
provide the information specified in Sec.  60.5424b.
    (i) For each reciprocating compressor affected facility, you must 
maintain records of deviations in cases where the reciprocating 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5385b, including a description of each deviation, 
the date and time each deviation began and the duration of each 
deviation in hours.
    (ii) Records of the date of installation of a rod packing emissions 
collection system and closed vent system as specified in Sec.  
60.5385b(d).
    (iii) Records of the cumulative number of hours of operation since 
initial startup, since May 7, 2024, or since the previous volumetric 
flow rate measurement, as applicable. Alternatively, a record that 
emissions from the rod packing are being routed to a process through a 
closed vent system.
    (iv) A description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable.
    (v) Records for all flow meters, composition analyzers and pressure 
gauges used to measure volumetric flow rates as specified in paragraphs 
(c)(5)(v)(A) through (F).
    (A) Description of standard method published by a consensus-based 
standards organization or industry standard practice.
    (B) Records of volumetric flow rate calculations conducted 
according to paragraphs Sec.  60.5385b(b) or (c), as applicable.

[[Page 17120]]

    (C) Records of manufacturer operating procedures and measurement 
methods.
    (D) Records of manufacturer's recommended procedures or an 
appropriate industry consensus standard method for calibration and 
results of calibration, recalibration, and accuracy checks.
    (E) Records which demonstrate that measurements at the remote 
location(s) can, when appropriate correction factors are applied, 
reliably and accurately represent the actual temperature or total 
pressure at the flow meter under all expected ambient conditions. You 
must include the date of the demonstration, the data from the 
demonstration, the mathematical correlation(s) between the remote 
readings and actual flow meter conditions derived from the data, and 
any supporting engineering calculations. If adjustments were made to 
the mathematical relationships, a record and description of such 
adjustments.
    (F) Record of each initial calibration or a recalibration which 
failed to meet the required accuracy specification and the date of the 
successful recalibration.
    (vi) Date when performance-based volumetric flow rate is exceeded.
    (vii) The date of successful replacement or repair of reciprocating 
compressor rod packing, including follow-up performance-based 
volumetric flow rate measurement to confirm successful repair.
    (viii) Identification of each reciprocating compressor placed on 
delay of repair because of rod packing or part unavailability and 
explanation for each delay of repair.
    (ix) For each reciprocating compressor that is placed on delay of 
repair because of replacement rod packing or part unavailability, the 
operator must document: the date the rod packing or part was added to 
the delay of repair list, the date the replacement rod packing or part 
was ordered, the anticipated rod packing or part delivery date 
(including any estimated shipment or delivery date provided by the 
vendor), and the actual arrival date of the rod packing or part.
    (x) Date of planned shutdowns that occur while there are any 
reciprocating compressors that have been placed on delay of repair due 
to the unavailability of rod packing or parts to conduct repairs.
    (6) For each process controller affected facility, you must 
maintain the records specified in paragraphs (c)(6)(i) through (vii) of 
this section.
    (i) Records identifying each process controller that is driven by 
natural gas and that does not function as an emergency shutdown device.
    (ii) For each process controller affected facility complying with 
Sec.  60.5390b(a), you must maintain records of the information 
specified in paragraphs (c)(6)(ii)(A) and (B) of this section, as 
applicable.
    (A) If you are complying with Sec.  60.5390b(a) by routing process 
controller vapors to a process through a closed vent system, you must 
report the information specified in paragraphs (c)(6)(ii)(A)(1) and (2) 
of this section.
    (1) An identification of all the natural gas-driven process 
controllers in the process controller affected facility for which you 
collect and route vapors to a process through a closed vent system.
    (2) The records specified in paragraphs (c)(8), (10), and (12) of 
this section. If you comply with an alternative GHG and VOC standard 
under Sec.  60.5398b, in lieu of the information specified in paragraph 
(c)(8) of this section, you must provide the information specified in 
Sec.  60.5424b.
    (B) If you are complying with Sec.  60.5390b(a) by using a self-
contained natural gas-driven process controller, you must report the 
information specified in paragraphs (c)(6)(ii)(B)(1) through (3) of 
this section.
    (1) An identification of each process controller complying with 
Sec.  60.5390b(a) by using a self-contained natural gas-driven process 
controller;
    (2) Dates of each inspection required under Sec.  60.5416b(b); and
    (3) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and date of repair 
or date of anticipated repair if repair is delayed.
    (iii) For each process controller affected facility complying with 
the Sec.  60.5390b(b)(1) process controller bleed rate requirements, 
you must maintain records of the information specified in paragraphs 
(c)(6)(iii)(A) and (B) of this section.
    (A) The identification of process controllers designed and operated 
to achieve a bleed rate less than or equal to 6 scfh and records of the 
manufacturer's specifications indicating that the process controller is 
designed with a natural gas bleed rate of less than or equal to 6 scfh.
    (B) Where necessary to meet a functional need, the identification 
of the process controller and demonstration of why it is necessary to 
use a process controller with a natural gas bleed rate greater than 6 
scfh.
    (iv) For each intermittent vent process controller in the affected 
facility complying with the requirements in paragraphs Sec.  
60.5390b(b)(2), you must keep records of the information specified in 
paragraphs (c)(6)(iv)(A) through (C) of this section.
    (A) The identification of each intermittent vent process 
controller.
    (B) Dates and results of the intermittent vent process controller 
monitoring required by Sec.  60.5390b(b)(2)(ii).
    (C) For each instance in which monitoring identifies emissions to 
the atmosphere from an intermittent vent controller during idle 
periods, the date of repair or replacement, or the date of anticipated 
repair or replacement if the repair or replacement is delayed and the 
date and results of the re-survey after repair or replacement.
    (v) For each process controller affected facility complying with 
Sec.  60.5390b(b)(3), you must maintain the records specified in 
paragraphs (c)(6)(v)(A) and (B) of this section.
    (A) An identification of each process controller for which 
emissions are routed to a control device.
    (B) Records specified in paragraphs (c)(8) and (c)(10) through (13) 
of this section. If you comply with an alternative GHG and VOC standard 
under Sec.  60.5398b, in lieu of the information specified in paragraph 
(c)(8) of this section, you must provide the information specified in 
Sec.  60.5424b.
    (vi) Records of each change in compliance method, including 
identification of each natural gas-driven process controller which 
changes its method of compliance, the new method of compliance, and the 
date of the change in compliance method.
    (vii) Records of each deviation, the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation.
    (7) For each storage vessel affected facility, you must maintain 
the records identified in paragraphs (c)(7)(i) through (vii) of this 
section.
    (i) You must maintain records of the identification and location in 
latitude and longitude coordinates in decimal degrees to an accuracy 
and precision of five (5) decimals of a degree using the North American 
Datum of 1983 of each storage vessel affected facility.
    (ii) Records of each methane and VOC emissions determination for 
each storage vessel affected facility made under Sec.  60.5365b(e) 
including identification of the model or calculation methodology used 
to calculate the methane and VOC emission rate.
    (iii) For each instance where the storage vessel was not operated 
in compliance with the requirements specified in Sec.  60.5395b a 
description of the deviation, the date and time each

[[Page 17121]]

deviation began, and the duration of the deviation.
    (iv) If complying with the emissions reduction standard in Sec.  
60.5395b(a)(2), you must maintain the records in paragraphs 
(c)(7)(iv)(A) through (E) of this section.
    (A) If you comply with the emission reduction standard with a 
control device, the information for each control device in paragraph 
(c)(11) of this section.
    (B) Records of the closed vent system inspection as specified 
paragraph (c)(8) of this section. If you comply with an alternative GHG 
and VOC standard under Sec.  60.5398b, in lieu of the information 
specified in paragraph (c)(8) of this section, you must provide the 
information specified in Sec.  60.5424b.
    (C) Records of the cover inspections as specified in paragraph 
(c)(9) of this section. If you comply with an alternative GHG and VOC 
standard under Sec.  60.5398b, in lieu of the information specified in 
paragraphs (c)(9) of this section, you must provide the information 
specified in Sec.  60.5424b.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(10) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(12) of this section.
    (v) For storage vessels that are skid-mounted or permanently 
attached to something that is mobile (such as trucks, railcars, barges 
or ships), records indicating the number of consecutive days that the 
vessel is located at a site in the crude oil and natural gas source 
category. If a storage vessel is removed from a site and, within 30 
days, is either returned to the site or replaced by another storage 
vessel at the site to serve the same or similar function, then the 
entire period since the original storage vessel was first located at 
the site, including the days when the storage vessel was removed, will 
be added to the count towards the number of consecutive days.
    (vi) Records of the date that each storage vessel affected facility 
or portion of a storage vessel affected facility is removed from 
service and returned to service, as applicable.
    (vii) Records of the date that liquids from the well following 
fracturing or refracturing are routed to the storage vessel affected 
facility; or the date that you comply with paragraph Sec.  
60.5395b(a)(2), following a monthly emissions determination which 
indicates that VOC emissions from your storage vessel affected facility 
increase to 4 tpy or greater or methane emissions increase to 14 tpy or 
greater and the increase is not associated with fracturing or 
refracturing of a well feeding the storage vessel affected facility, 
and records of the methane and VOC emissions rate and the model or 
calculation methodology used to calculate the methane and VOC emission 
rate.
    (8) Records of each closed vent system inspection required under 
Sec.  60.5416b(a)(1) and (2) and (b) for your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, storage 
vessel, and process unit equipment affected facility as required in 
paragraphs (c)(8)(i) through (iv) of this section.
    (i) A record of each closed vent system inspection or no 
identifiable emissions monitoring survey. You must include an 
identification number for each closed vent system (or other unique 
identification description selected by you), the date of the 
inspection, and the method used to conduct the inspection (i.e., 
visual, AVO, OGI, Method 21 of appendix A-7 to this part).
    (ii) For each defect or emissions detected during inspections 
required by Sec.  60.5416b(a)(1) and (2), or (b) you must record the 
location of the defect or emissions; a description of the defect; the 
maximum concentration reading obtained if using Method 21 of appendix 
A-7 to this part; the indication of emissions detected by AVO if using 
AVO; the date of detection; the date of each attempt to repair the 
emissions or defect; the corrective action taken during each attempt to 
repair the defect; and the date the repair to correct the defect or 
emissions is completed.
    (iii) If repair of the defect is delayed as described in Sec.  
60.5416b(b)(6), you must record the reason for the delay and the date 
you expect to complete the repair.
    (iv) Parts of the closed vent system designated as unsafe to 
inspect as described in Sec.  60.5416b(b)(7) or difficult to inspect as 
described in Sec.  60.5416b(b)(8), the reason for the designation, and 
written plan for inspection of that part of the closed vent system.
    (9) A record of each cover inspection required under Sec.  
60.5416b(a)(3) for your centrifugal compressor, reciprocating 
compressor, or storage vessel as required in paragraphs (c)(9)(i) 
through (iv) of this section.
    (i) A record of each cover inspection. You must include an 
identification number for each cover (or other unique identification 
description selected by you), the date of the inspection, and the 
method used to conduct the inspection (i.e., AVO, OGI, Method 21 of 
appendix A-7 to this part).
    (ii) For each defect detected during the inspection you must record 
the location of the defect; a description of the defect, the date of 
detection, the maximum concentration reading obtained if using Method 
21 of appendix A-7 to this part; the indication of emissions detected 
by AVO if using AVO; the date of each attempt to repair the defect; the 
corrective action taken during each attempt to repair the defect; and 
the date the repair to correct the defect is completed.
    (iii) If repair of the defect is delayed as described in Sec.  
60.5416b(b)(6), you must record the reason for the delay and the date 
you expect to complete the repair.
    (iv) Parts of the cover designated as unsafe to inspect as 
described in Sec.  60.5416b(b)(7) or difficult to inspect as described 
in Sec.  60.5416b(b)(8), the reason for the designation, and written 
plan for inspection of that part of the cover.
    (10) For each bypass subject to the bypass requirements of Sec.  
60.5416b(a)(4), you must maintain a record of the following, as 
applicable: readings from the flow indicator; each inspection of the 
seal or closure mechanism; the date and time of each instance the key 
is checked out; date and time of each instance the alarm is sounded.
    (11) Records for each control device used to comply with the 
emission reduction standard in Sec.  60.5377b(b) for associated gas 
wells, Sec.  60.5380b(a)(1) for centrifugal compressor affected 
facilities, Sec.  60.5385b(d)(2) for reciprocating compressor affected 
facilities, Sec.  60.5390b(b)(3) for your process controller affected 
facility in Alaska, Sec.  60.5393b(b)(1) for your pump affected 
facility, Sec.  60.5395b(a)(2) for your storage vessel affected 
facility, Sec.  60.5376b(f) for well affected facility gas well liquids 
unloading, or Sec.  60.5400b(f) or 60.5401b(e) for your process 
equipment affected facility, as required in paragraphs (c)(11)(i) 
through (viii) of this section. If you use an enclosed combustion 
device or flare using an alternative test method approved under Sec.  
60.5412b(d), keep records of the information in paragraphs (c)(11)(ix) 
of this section, in lieu of the records required by paragraphs 
(c)(11)(i) through (iv) and (vi) through (viii) of this section.
    (i) For a control device tested under Sec.  60.5413b(d) which meets 
the criteria in Sec.  60.5413b(d)(11) and (e), keep records of the 
information in paragraphs (c)(11)(i)(A) through (E) of this section, in 
addition to the records in paragraphs

[[Page 17122]]

(c)(11)(ii) through (ix) of this section, as applicable.
    (A) Serial number of purchased device and copy of purchase order.
    (B) Location of the affected facility associated with the control 
device in latitude and longitude coordinates in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using the North 
American Datum of 1983.
    (C) Minimum and maximum inlet gas flow rate specified by the 
manufacturer.
    (D) Records of the maintenance and repair log as specified in Sec.  
60.5413b(e)(4), for all inspection, repair, and maintenance activities 
for each control device failing the visible emissions test.
    (E) Records of the manufacturer's written operating instructions, 
procedures, and maintenance schedule to ensure good air pollution 
control practices for minimizing emissions.
    (ii) For all control devices, keep records of the information in 
paragraphs (c)(11)(ii)(A) through (G) of this section, as applicable.
    (A) Make, model, and date of installation of the control device, 
and identification of the affected facility controlled by the device.
    (B) Records of deviations in accordance with Sec.  60.5417b(g)(1) 
through (7), including a description of the deviation, the date and 
time the deviation began, the duration of the deviation, and the cause 
of the deviation.
    (C) The monitoring plan required by Sec.  60.5417b(c)(2).
    (D) Make and model number of each continuous parameter monitoring 
system.
    (E) Records of minimum and maximum operating parameter values, 
continuous parameter monitoring system data (including records that the 
pilot or combustion flame is present at all times), calculated averages 
of continuous parameter monitoring system data, and results of all 
compliance calculations.
    (F) Records of continuous parameter monitoring system equipment 
performance checks, system accuracy audits, performance evaluations, or 
other audit procedures and results of all inspections specified in the 
monitoring plan in accordance with Sec.  60.5417b(c)(2). Records of 
calibration gas cylinders, if applicable.
    (G) Periods of monitoring system malfunctions, repairs associated 
with monitoring system malfunctions and required monitoring system 
quality assurance or quality control activities Records of repairs on 
the monitoring system.
    (iii) For each carbon adsorption system, records of the schedule 
for carbon replacement as determined by the design analysis 
requirements of Sec.  60.5413b(c)(2) and (3) and records of each carbon 
replacement as specified in Sec.  60.5412b(c)(1) and Sec.  
60.5415b(f)(1)(viii).
    (iv) For enclosed combustion devices and flares, records of visible 
emissions observations as specified in paragraph (c)(11)(iv)(A) or (B) 
of this section.
    (A) Records of observations with Method 22 of appendix A-7 to this 
part, including observations required following return to operation 
from a maintenance or repair activity, which include: company, 
location, company representative (name of the person performing the 
observation), sky conditions, process unit (type of control device), 
clock start time, observation period duration (in minutes and seconds), 
accumulated emission time (in minutes and seconds), and clock end time. 
You may create your own form including the above information or use 
Figure 22-1 in Method 22 of appendix A-7 to this part.
    (B) If you monitor visible emissions with a video surveillance 
camera, location of the camera and distance to emission source, records 
of the video surveillance output, and documentation that an operator 
looked at the feed daily, including the date and start time of 
observation, the length of observation, and length of time visible 
emissions were present.
    (v) For enclosed combustion devices and flares, video of the OGI 
inspection conducted in accordance with Sec.  60.5415b(f)(x). Records 
documenting each enclosed combustion device and flare was visibly 
observed during each inspection conducted under Sec.  60.5397b using 
AVO in accordance with Sec.  60.5415b(f)(x).
    (vi) For enclosed combustion devices and flares, records of each 
demonstration of the NHV of the inlet gas to the enclosed combustion 
device or flare conducted in accordance with Sec.  60.5417b(d)(8)(iii). 
For each re-evaluation of the NHV of the inlet gas, records of process 
changes and explanation of the conditions that led to the need to re-
evaluation the NHV of the inlet gas. For each demonstration, record 
information on whether the enclosed combustion device or flare has the 
potential to receive inert gases, and if so, the highest percentage of 
inert gases that can be sent to the enclosed combustion device or flare 
and the highest percent of inert gases sent to the enclosed combustion 
device or flare during the NHV demonstration. Records of periodic 
sampling conducted under Sec.  60.5417b(d)(8)(iii)(G).
    (vii) For enclosed combustion devices and flares, if you use a 
backpressure regulator valve, the make and model of the valve, date of 
installation, and record of inlet flow rating. Maintain records of the 
engineering evaluation and manufacturer specifications that identify 
the pressure set point corresponding to the minimum inlet gas flow 
rate, the annual confirmation that the backpressure regulator valve set 
point is correct and consistent with the engineering evaluation and 
manufacturer specifications, and the annual confirmation that the 
backpressure regulator valve fully closes when not in open position.
    (viii) For enclosed combustion devices and flares, records of each 
demonstration required under Sec.  60.5417b(d)(8)(iv).
    (ix) If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412b(d), keep records 
of the information in paragraphs (c)(11)(ix)(A) through (H) of this 
section, in lieu of the records required by paragraphs (c)(11)(i) 
through (iv) and (c)(11)(vi) through (viii) of this section.
    (A) An identification of the alternative test method used.
    (B) Data recorded at the intervals required by the alternative test 
method.
    (C) Monitoring plan required by Sec.  60.5417(i)(2).
    (D) Quality assurance and quality control activities conducted in 
accordance with the alternative test method.
    (E) If required by Sec.  60.5412b(d)(4) to conduct visible 
emissions observations, records required by paragraph (c)(11)(iv) of 
this section.
    (F) If required by Sec.  60.5412b(d)(5) to conduct pilot or 
combustion flame monitoring, record indicating the presence of a pilot 
or combustion flame and periods when the pilot or combustion flame is 
absent.
    (G) For each instance where there is a deviation of the control 
device in accordance with Sec.  60.5417b(i)(6)(i) through (v), the date 
and time the deviation began, the duration of the deviation in hours, 
and cause of the deviation.
    (H) Any additional information required to be recorded as specified 
by the Administrator as part of the alternative test method approval 
under Sec.  60.5412b(d).
    (12) For each closed vent system routing to a control device or 
process, the records of the assessment conducted according to Sec.  
60.5411b(c):

[[Page 17123]]

    (i) A copy of the assessment conducted according to Sec.  
60.5411b(c)(1); and
    (ii) A copy of the certification according to Sec.  
60.5411b(c)(1)(i) and (ii).
    (13) A copy of each performance test submitted under paragraphs 
(b)(12) or (13) of this section.
    (14) For the fugitive emissions components affected facility, 
maintain the records identified in paragraphs (c)(14)(i) through (viii) 
of this section.
    (i) The date of the startup of production or the date of the first 
day of production after modification for the fugitive emissions 
components affected facility at a well site and the date of startup or 
the date of modification for the fugitive emissions components affected 
facility at a compressor station.
    (ii) For the fugitive emissions components affected facility at a 
well site, you must maintain records specifying what type of well site 
it is (i.e., single wellhead only well site, small wellsite, multi-
wellhead only well site, or a well site with major production and 
processing equipment.)
    (iii) For the fugitive emissions components affected facility at a 
well site where you complete the removal of all major production and 
processing equipment such that the well site contains only one or more 
wellheads, record the date the well site completes the removal of all 
major production and processing equipment from the well site, and, if 
the well site is still producing, record the well ID or separate tank 
battery ID receiving the production from the well site. If major 
production and processing equipment is subsequently added back to the 
well site, record the date that the first piece of major production and 
processing equipment is added back to the well site.
    (iv) The fugitive emissions monitoring plan as required in Sec.  
60.5397b(b), (c), and (d).
    (v) The records of each monitoring survey as specified in 
paragraphs (c)(14)(v)(A) through (I) of this section.
    (A) Date of the survey.
    (B) Beginning and end time of the survey.
    (C) Name of operator(s), training, and experience of the 
operator(s) performing the survey.
    (D) Monitoring instrument or method used.
    (E) Fugitive emissions component identification when Method 21 of 
appendix A-7 to this part is used to perform the monitoring survey.
    (F) Ambient temperature, sky conditions, and maximum wind speed at 
the time of the survey. For compressor stations, operating mode of each 
compressor (i.e., operating, standby pressurized, and not operating-
depressurized modes) at the station at the time of the survey.
    (G) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (H) Records of calibrations for the instrument used during the 
monitoring survey.
    (I) Documentation of each fugitive emission detected during the 
monitoring survey, including the information specified in paragraphs 
(c)(14)(v)(I)(1) through (9) of this section.
    (1) Location of each fugitive emission identified.
    (2) Type of fugitive emissions component, including designation as 
difficult-to-monitor or unsafe-to-monitor, if applicable.
    (3) If Method 21 of appendix A-7 to this part is used for 
detection, record the component ID and instrument reading.
    (4) For each repair that cannot be made during the monitoring 
survey when the fugitive emissions are initially found, a digital 
photograph or video must be taken of that component or the component 
must be tagged for identification purposes. The digital photograph must 
include the date that the photograph was taken and must clearly 
identify the component by location within the site (e.g., the latitude 
and longitude of the component or by other descriptive landmarks 
visible in the picture). The digital photograph or identification 
(e.g., tag) may be removed after the repair is completed, including 
verification of repair with the resurvey.
    (5) The date of first attempt at repair of the fugitive emissions 
component(s).
    (6) The date of successful repair of the fugitive emissions 
component, including the resurvey to verify repair and instrument used 
for the resurvey.
    (7) Identification of each fugitive emission component placed on 
delay of repair and explanation for each delay of repair.
    (8) For each fugitive emission component placed on delay of repair 
for reason of replacement component unavailability, the operator must 
document: the date the component was added to the delay of repair list, 
the date the replacement fugitive component or part thereof was 
ordered, the anticipated component delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the component.
    (9) Date of planned shutdowns that occur while there are any 
components that have been placed on delay of repair.
    (vi) For the fugitive emissions components affected facility 
complying with an alternative means of emissions limitation under Sec.  
60.5399b, you must maintain the records specified by the specific 
alternative fugitive emissions standard for a period of at least 5 
years.
    (vii) For well closure activities, you must maintain the 
information specified in paragraphs (c)(14)(vii)(A) through (G) of this 
section.
    (A) The well closure plan developed in accordance with Sec.  
60.5397b(l) and the date the plan was submitted.
    (B) The notification of the intent to close the well site and the 
date the notification was submitted.
    (C) The date of the cessation of production from all wells at the 
well site.
    (D) The date you began well closure activities at the well site.
    (E) Each status report for the well closure activities reported in 
paragraph (b)(9)(iv)(A) of this section.
    (F) Each OGI survey reported in paragraph (b)(9)(iv)(B) of this 
section including the date, the monitoring instrument used, and the 
results of the survey or resurvey.
    (G) The final OGI survey video demonstrating the closure of all 
wells at the site. The video must include the date that the video was 
taken and must identify the well site location by latitude and 
longitude.
    (viii) If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraphs 
(c)(14)(iv) and (v) of this section, you must maintain the records 
specified in Sec.  60.5424b.
    (15) For each pump affected facility, you must maintain the records 
identified in paragraphs (c)(15)(i) through (ix) of this section.
    (i) Identification of each pump that is driven by natural gas and 
that is in operation 90 days or more per calendar year.
    (ii) If you are complying with Sec.  60.5393b(a) or (b)(1) by 
routing pump vapors to a process through a closed vent system, 
identification of all the pumps in the pump affected facility for which 
you collect and route vapors to a process through a closed vent system 
and the records specified in paragraphs (c)(8), (10), and (12) of this 
section. If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraph 
(c)(8) of this section, you must provide the information specified in 
Sec.  60.5424b.
    (iii) If you are complying with Sec.  60.5393b(b)(1) by routing 
pump vapors to control device achieving a 95.0

[[Page 17124]]

percent reduction in methane and VOC emissions, you must keep the 
records specified in paragraphs (c)(8) and (10) through (c)(13) of this 
section. If you comply with an alternative GHG and VOC standard under 
Sec.  60.5398b, in lieu of the information specified in paragraph 
(c)(8) of this section, you must provide the information specified in 
Sec.  60.5424b.
    (iv) If you are complying with Sec.  60.5393b(b)(3) by routing pump 
vapors to control device achieving less than a 95.0 percent reduction 
in methane and VOC emissions, you must maintain records of the 
certification that there is a control device on site but it does not 
achieve a 95.0 percent emissions reduction and a record of the design 
evaluation or manufacturer's specifications which indicate the 
percentage reduction the control device is designed to achieve.
    (v) If you have less than three natural gas-driven diaphragm pumps 
in the pump affected facility, and you do not have a vapor recovery 
unit or control device installed on site by the compliance date, you 
must retain a record of your certification required under Sec.  
60.5393b(b)(4), certifying that there is no vapor recovery unit or 
control device on site. If you subsequently install a control device or 
vapor recovery unit, you must maintain the records required under 
paragraphs (c)(15)(ii), (iii) or (iv) of this section, as applicable.
    (vi) If you determine, through an engineering assessment, that it 
is technically infeasible to route the pump affected facility emissions 
to a process or control device, you must retain records of your 
demonstration and certification that it is technically infeasible as 
required under Sec.  60.5393b(b)(5).
    (vii) If the pump is routed to a control device that is 
subsequently removed from the location or is no longer available such 
that there is no option to route to a control device, you are required 
to retain records of this change and the records required under 
paragraph (c)(15)(vi) of this section.
    (viii) Records of each change in compliance method, including 
identification of each natural gas-driven pump which changes its method 
of compliance, the new method of compliance, and the date of the change 
in compliance method.
    (ix) Records of each deviation, the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation.
    (d) Electronic reporting. If you are required to submit 
notifications or reports following the procedure specified in this 
paragraph (d), you must submit notifications or reports to the EPA via 
CEDRI, which can be accessed through the EPA's Central Data Exchange 
(CDX) (https://cdx.epa.gov/). The EPA will make all the information 
submitted through CEDRI available to the public without further notice 
to you. Do not use CEDRI to submit information you claim as CBI. 
Although we do not expect persons to assert a claim of CBI, if you wish 
to assert a CBI claim for some of the information in the report or 
notification, you must submit a complete file in the format specified 
in this subpart, including information claimed to be CBI, to the EPA 
following the procedures in paragraphs (g)(1) and (2) of this section. 
Clearly mark the part or all of the information that you claim to be 
CBI. Information not marked as CBI may be authorized for public release 
without prior notice. Information marked as CBI will not be disclosed 
except in accordance with procedures set forth in 40 CFR part 2. All 
CBI claims must be asserted at the time of submission. Anything 
submitted using CEDRI cannot later be claimed CBI. Furthermore, under 
CAA section 114(c), emissions data is not entitled to confidential 
treatment, and the EPA is required to make emissions data available to 
the public. Thus, emissions data will not be protected as CBI and will 
be made publicly available. You must submit the same file submitted to 
the CBI office with the CBI omitted to the EPA via the EPA's CDX as 
described earlier in this paragraph (d).
    (1) The preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol, or 
other online file sharing services. Electronic submissions must be 
transmitted directly to the OAQPS CBI Office at the email address 
<a href="/cdn-cgi/l/email-protection#7b141a0a0b081819123b1e0b1a551c140d"><span class="__cf_email__" data-cfemail="86e9e7f7f6f5e5e4efc6e3f6e7a8e1e9f0">[email protected]</span></a>, and as described above, should include clear CBI 
markings. ERT files should be flagged to the attention of the Group 
Leader, Measurement Policy Group; all other files should be flagged to 
the attention of the Oil and Natural Gas Sector Lead. 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 <a href="/cdn-cgi/l/email-protection#b4dbd5c5c4c7d7d6ddf4d1c4d59ad3dbc2"><span class="__cf_email__" data-cfemail="8de2ecfcfdfeeeefe4cde8fdeca3eae2fb">[email protected]</span></a> to request a file 
transfer link.
    (2) If you cannot transmit the file electronically, you may send 
CBI information through the postal service to the following address: 
U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109 
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should 
be sent to the secondary attention of the Group Leader, Measurement 
Policy Group, and all other files should be sent to the secondary 
attention of the Oil and Natural Gas Sector Lead. The mailed CBI 
material should be double wrapped and clearly marked. Any CBI markings 
should not show through the outer envelope.
    (e) Claims of EPA system outage. If you are required to 
electronically submit a notification or report through CEDRI in the 
EPA's CDX, you may assert a claim of EPA system outage for failure to 
timely comply with that requirement. To assert a claim of EPA system 
outage, you must meet the requirements outlined in paragraphs (e)(1) 
through (7) of this section.
    (1) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (2) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.
    (3) The outage may be planned or unplanned.
    (4) You must submit notification to the Administrator in writing as 
soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (5) You must provide to the Administrator a written description 
identifying:
    (i) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (ii) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (iii) A description of measures taken or to be taken to minimize 
the delay in reporting; and
    (iv) The date by which you propose to report, or if you have 
already met the reporting requirement at the time of the notification, 
the date you reported.
    (6) The decision to accept the claim of EPA system outage and allow 
an extension to the reporting deadline is solely within the discretion 
of the Administrator.
    (7) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (f) Claims of force majeure. If you are required to electronically 
submit a report or notification through CEDRI in the EPA's CDX, you may 
assert a claim of force majeure for failure to timely comply with that 
requirement. To assert a claim of force majeure, you must meet

[[Page 17125]]

the requirements outlined in paragraphs (f)(1) through (5) of this 
section.
    (1) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the affected facility, 
its contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the affected facility (e.g., large scale power outage).
    (2) You must submit notification to the Administrator in writing as 
soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (3) You must provide to the Administrator:
    (i) A written description of the force majeure event;
    (ii) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (iii) A description of measures taken or to be taken to minimize 
the delay in reporting; and
    (iv) The date by which you propose to report, or if you have 
already met the reporting requirement at the time of the notification, 
the date you reported.
    (4) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (5) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.


Sec.  60.5421b   What are my additional recordkeeping requirements for 
process unit equipment affected facilities?

    You must maintain a record of each equipment leak monitoring 
inspection and each leak identified under Sec.  60.5400b and Sec.  
60.5401b as specified in paragraphs (b)(1) through (16) of this 
section. The record must be maintained either onsite or at the nearest 
local field office for at least 5 years. Any records required to be 
maintained that are submitted electronically via the EPA's CEDRI may be 
maintained in electronic format. This ability to maintain electronic 
copies does not affect the requirement for facilities to make records, 
data, and reports available upon request to a delegated air agency or 
the EPA as part of an on-site compliance evaluation.
    (a) You may comply with the recordkeeping requirements for multiple 
process unit equipment affected facilities in one recordkeeping system 
if the system identifies each record by each facility.
    (b) You must maintain the monitoring inspection records specified 
in paragraphs (b)(1) through (16) of this section.
    (1) Equipment Identification. Note that connectors need not be 
individually identified if all connectors in a designated area or 
length of pipe subject to the provisions of this subpart are identified 
as a group, and the number of connectors subject is indicated.
    (2) Date and start and end times of the monitoring inspection.
    (3) Inspector name.
    (4) Leak determination method used for the monitoring inspection 
(i.e., OGI, Method 21, or AVO).
    (5) Monitoring instrument identification (OGI and Method 21 only).
    (6) Type of equipment monitored.
    (7) Process unit identification.
    (8) The records specified in Section 12 of appendix K of this part, 
for each monitoring inspection conducted with OGI.
    (9) The records in paragraph (b)(9)(i) through (vii), for each 
monitoring inspection conducted with Method 21 of appendix A-7 to this 
part.
    (i) Instrument reading.
    (ii) Date and time of instrument calibration and initials of 
operator performing the calibration.
    (iii) Calibration gas cylinder identification, certification date, 
and certified concentration.
    (iv) Instrument scale used.
    (v) A description of any corrective action taken if the meter 
readout could not be adjusted to correspond to the calibration gas 
value in accordance with section 10.1 of Method 21 of appendix A-7 to 
this part.
    (vi) Results of the daily calibration drift assessment.
    (vii) If you make your own calibration gas, a description of the 
procedure used.
    (10) For visual inspections of pumps in light liquid service, keep 
the records specified in paragraphs (b)(10)(i) through (iii), for each 
monitored equipment:
    (i) Date of inspection.
    (ii) Inspector name.
    (iii) Result of inspection (i.e., visual indications of liquids 
dripping from the pump seal or no visual indications of liquids 
dripping from the pump seal).
    (11) For each leak detected, the records specified in paragraphs 
(b)(11)(i) through (v) of this section:
    (i) The instrument and operator identification numbers and the 
process unit and equipment identification numbers. For leaks identified 
via AVO methods, enter the specific sensory method for instrument 
identification number.
    (ii) The date the leak was detected.
    (iii) For each attempt to repair the leak, record:
    (A) The date.
    (B) The repair method applied.
    (C) Indication of whether a leak was still detected following each 
attempt to repair the leak.
    (vi) The date of successful repair of the leak and the method of 
monitoring used to confirm the repair, as specified in paragraph 
(b)(11)(vi)(A) through (C) of this section.
    (A) If Method 21 of appendix A-7 to this part is used to confirm 
the repair, maintain a record of the maximum instrument reading 
measured by Method 21 of appendix A-7 to this part.
    (B) If OGI conducted in accordance with appendix K of this part is 
used to confirm the repair, maintain a record of video footage of the 
repair confirmation.
    (C) If the leak is repaired by eliminating AVO indications of a 
leak, maintain a record of the specific sensory method used to confirm 
that the evidence of the leak is eliminated.
    (v) For each repair delayed beyond 15 calendar days after detection 
of the leak, record:
    (A) ``Repair delayed'' and the reason for the delay.
    (B) The signature of the certifying official who made the decision 
that repair could not be completed without a process shutdown.
    (C) The expected date of successful repair of the leak.
    (D) Dates of process unit shutdowns that occur while the equipment 
is unrepaired.
    (12) A list of identification numbers for equipment that are 
designated for no detectable emissions complying with the provisions of 
Sec.  60.5401b.
    (13) A list of identification numbers for valves, pumps, and 
connectors that are designated as unsafe-to-monitor, an explanation for 
each valve, pump, or connector stating why the valve, pump, or 
connector is unsafe-to-monitor, and the plan for monitoring each valve, 
pump, or connector.
    (14) A list of identification numbers for valves that are 
designated as difficult-to-monitor, an explanation for each valve 
stating why the valve is difficult-to-monitor, and the schedule for 
monitoring each valve.

[[Page 17126]]

    (15) A list of identification numbers for equipment that is in 
vacuum service.
    (16) A list of identification numbers for equipment you designate 
as having the potential to emit methane or VOC less than 300 hr/yr.
    (17) A list of identification numbers for valves where it was 
infeasible to replace leaking valves with low-e valves or repack 
existing valves with low-e packing technology, including the reasoning 
for why it was infeasible.


Sec.  60.5422b   What are my additional reporting requirements for 
process unit equipment affected facilities?

    (a) You must submit semiannual reports using the appropriate 
electronic report template on the CEDRI website for this subpart and 
following the procedure specified in Sec.  60.5420b(d). If the 
reporting form specific to this subpart is not available on the CEDRI 
website at the time that the report is due, submit the report to the 
Administrator at the appropriate address listed in Sec.  60.4. Once the 
form has been available on the CEDRI website for at least 90 calendar 
days, you must begin submitting all subsequent reports via CEDRI. The 
date reporting forms become available will be listed on the CEDRI 
website. Unless the Administrator or delegated state agency or other 
authority has approved a different schedule for submission of reports, 
the report must be submitted within 45 days after the end of the 
semiannual reporting period, regardless of the method in which the 
report is submitted.
    (b) The initial semiannual report must include the following 
information:
    (1) The general information specified in paragraph (c)(1) of this 
section.
    (2) For each process unit:
    (i) Process unit identification.
    (ii) Number of valves subject to the monitoring requirements of 
Sec. Sec.  60.5400b(b) and 60.5401b(f).
    (iii) Number of pumps subject to the monitoring requirements of 
Sec. Sec.  60.5400b(b) and 60.5401b(b).
    (iv) Number of connectors subject to the monitoring requirements of 
Sec. Sec.  60.5400b(b) and 60.5401b(h).
    (v) Number of pressure relief devices subject to the monitoring 
requirements of Sec. Sec.  60.5400b(b) and 60.5401b(c).
    (vi) The information in paragraphs (c)(3) and (4) of this section.
    (c) All subsequent semiannual reports must include the following 
information:
    (1) The general information specified in paragraphs (c)(1)(i) 
through (iii) of this section.
    (i) The company name, facility site name, and address of the 
affected facility.
    (ii) Beginning and ending dates of the reporting period.
    (iii) A certification by a certifying official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete. If 
your report is submitted via CEDRI, the certifier's electronic 
signature during the submission process replaces the requirement in 
this paragraph (c)(1)(iii).
    (2) Process unit identification for each process unit.
    (3) For each month during the semiannual reporting period for each 
process unit report:
    (i) Number of valves for which leaks were detected as described in 
Sec.  60.5400b(b) or Sec.  60.5401b(f).
    (ii) Number of valves for which leaks were not repaired as required 
in Sec.  60.5400b(h) or Sec.  60.5401b(i), the number of instances 
where it was technically infeasible to replace leaking valves with low-
e valves or repack existing valves with low-e packing technology, 
including the reasoning for why it was technically infeasible.
    (iii) Number of pumps for which leaks were detected as described 
Sec.  60.5400b(b) or Sec.  60.5401b(b).
    (iv) Number of pumps for which leaks were not repaired as required 
in Sec.  60.5400b(h) or Sec.  60.5401b(i).
    (v) Number of connectors for which leaks were detected as described 
in Sec.  60.5400b(b) or Sec.  60.5401b(h).
    (vi) Number of connectors for which leaks were not repaired as 
required in Sec.  60.5400b(h) or Sec.  60.5401b(i).
    (vii) Number of pressure relief devices for which leaks were 
detected as described in Sec.  60.5400b(b) or Sec.  60.5401b(c).
    (viii) Number of pressure relief devices for which leaks were not 
repaired as required in Sec.  60.5400b(h) or Sec.  60.5401b(i).
    (ix) Number of open-ended valves or lines for which leaks were 
detected as described in Sec.  60.5400b(e) or Sec.  60.5401b(d).
    (x) Number of open-ended valves or lines for which leaks were not 
repaired as required in Sec.  60.5400b(h) or Sec.  60.5401b(i).
    (xi) Number of pumps, valves, or connectors in heavy liquid service 
or pressure relief device in light liquid or heavy liquid service for 
which leaks were detected as described in Sec.  60.5400b(g) or Sec.  
60.5401b(g).
    (xii) Number of pumps, valves, or connectors in heavy liquid 
service or pressure relief device in light liquid or heavy liquid 
service for which leaks were not repaired as required in Sec.  
60.5400b(h) or Sec.  60.5401b(i).
    (xiii) The facts that explain each delay of repair and, where 
appropriate, why a process unit shutdown was technically infeasible.
    (4) Dates of process unit shutdowns which occurred within the 
semiannual reporting period.
    (5) Revisions to items reported according to paragraph (b) of this 
section if changes have occurred since the initial report or subsequent 
revisions to the initial report.


Sec.  60.5423b   What are my additional recordkeeping and reporting 
requirements for sweetening unit affected facilities?

    (a) You must retain records of the calculations and measurements 
required in Sec. Sec.  60.5405b(a) and (b) and 60.5407b(a) through (g) 
for at least 2 years following the date of the measurements. This 
requirement is included under Sec.  60.7(f) of the General Provisions.
    (b) In your initial annual report submitted in accordance with the 
procedures and schedule in Sec.  60.5420b(b), include the information 
in paragraphs (b)(1) and (2) of this section.
    (1) For each run of the initial performance test required by Sec.  
60.8(b):
    (i) The average sulfur feed rate in Mg/D, determined according to 
Sec.  60.5406b(b).
    (ii) The average volumetric flow rate of acid gas from the 
sweetening unit, in dscm/day.
    (iii) The H<INF>2</INF>S concentration in the acid gas feed from 
the sweetening unit, percent by volume.
    (iv) The emission rate of sulfur in kg/hr.
    (v) The sulfur production rate in kg/hr.
    (vi) The emission reduction efficiency achieved by the sulfur 
recovery technology, determined according to Sec.  60.5406b(c).
    (vii) The required initial SO<INF>2</INF> emission reduction 
efficiency, as determined from table 3 to this subpart based on the 
sulfur feed rate and the sulfur content of the acid gas of the affected 
facility.
    (2) The required minimum SO<INF>2</INF> emission reduction 
efficiency you must achieve on a continuous basis, as determined from 
table 4 to this subpart based on the sulfur feed rate and the sulfur 
content of the acid gas of the affected facility.
    (c) You must submit the performance test report in accordance with 
the requirements of Sec.  60.5420b(b)(12).
    (d) You must submit a report of excess emissions to the 
Administrator in your annual report if you had excess

[[Page 17127]]

emissions during the reporting period. The procedures and schedule for 
submitting annual reports are located in Sec.  60.5420b(b). For the 
purpose of these reports, excess emissions are defined as specified in 
paragraphs (d)(1) and (2) of this section. The report must contain the 
information specified in paragraph (d)(3) of this section.
    (1) Any 24-hour period (at consistent intervals) during which the 
average sulfur emission reduction efficiency (R) is less than the 
minimum required efficiency (Z).
    (2) For any affected facility electing to comply with the 
provisions of Sec.  60.5407b(b)(2), any 24-hour period during which the 
average temperature of the gases leaving the combustion zone of an 
incinerator is less than the appropriate operating temperature as 
determined during the most recent performance test in accordance with 
the provisions of Sec.  60.5407b(b)(3). Each 24-hour period must 
consist of at least 96 temperature measurements equally spaced over the 
24 hours.
    (3) For each period of excess emissions during the reporting 
period, include the following information in your report:
    (i) The date and time of commencement and completion of each period 
of excess emissions;
    (ii) The required minimum efficiency (Z) and the actual average 
sulfur emissions reduction (R) for periods defined in paragraph (d)(1) 
of this section; and
    (iii) The appropriate operating temperature and the actual average 
temperature of the gases leaving the combustion zone for periods 
defined in paragraph (d)(2) of this section.
    (e) To certify that a facility is exempt from the control 
requirements of these standards, for each facility with a design 
capacity less than 2 LT/D of H<INF>2</INF>S in the acid gas (expressed 
as sulfur) you must keep, for the life of the facility, an analysis 
demonstrating that the facility's design capacity is less than 2 LT/D 
of H<INF>2</INF>S expressed as sulfur.
    (f) If you elect to comply with Sec.  60.5407b(e) you must keep, 
for the life of the facility, a record demonstrating that the 
facility's design capacity is less than 150 LT/D of H<INF>2</INF>S 
expressed as sulfur.
    (g) The requirements of paragraph (d) of this section remain in 
force until and unless the EPA, in delegating enforcement authority to 
a state under section 111(c) of the Act, approves reporting 
requirements or an alternative means of compliance surveillance adopted 
by such state. In that event, affected sources within the state will be 
relieved of obligation to comply with paragraph (d) of this section, 
provided they comply with the requirements established by the state. 
Electronic reporting to the EPA cannot be waived, and as such, the 
provisions of this paragraph do not relieve owners or operators of 
affected facilities of the requirement to submit the electronic reports 
required in this section to the EPA.


Sec.  60.5424b   What are my additional recordkeeping and reporting 
requirements if I comply with the alternative GHG and VOC standards for 
fugitive emissions components affected facilities and covers and closed 
vent systems?

    This section provides notification, reporting, and recordkeeping 
requirements for owners and operators who choose to comply with an 
alternative GHG and VOC standard as specified in Sec.  60.5398b for 
fugitive emissions components affected facilities and the alternative 
continuous inspection and monitoring requirements for covers and closed 
vent systems. You must submit an annual report in accordance with the 
schedule in Sec.  60.5420b(b) which includes the information in 
paragraphs (a)(1), (b), and (d) of this section, as applicable. You 
must submit the notification in paragraph (a)(2) of this section and 
maintain the records in paragraphs (c) and (e) of this section, as 
applicable.
    (a) Notifications. If you choose to comply with an alternative GHG 
and VOC standard as specified in Sec.  60.5398b for fugitive emissions 
components affected facilities and the alternative continuous 
inspection and monitoring requirements for covers and closed vent 
systems, you must submit the notification in paragraph (a)(1) of this 
section. If you are required by Sec.  60.5398b(c)(8) to develop a mass 
emission rate reduction plan, you must submit the notification in 
paragraph (a)(2) of this section.
    (1) A notification to the Administrator of adoption of the 
alternative standards in the annual report required by Sec.  
60.5420b(b)(4) through (11).
    (2) A notification, which includes the submittal of the mass 
emission rate reduction plan required by Sec.  60.5398b(c)(8). You must 
submit the mass emission rate reduction plan to the Administrator 
within 60 days of the initial exceedance of the action level.
    (b) Information submittal. If you comply with the periodic 
screening requirements of Sec.  60.5398b(b), you must submit the 
information in paragraphs (b)(1) through (6) of this section in the 
annual report required by Sec.  60.5420b(b)(4) through (11).
    (1) Date of each periodic screening during the reporting period and 
date that results of the periodic screening were received.
    (2) Alternative test method and technology used for each screening 
and the spatial resolution of the technology (i.e., facility-level, 
area-level, or component-level).
    (3) Any deviations from the monitoring plan developed under Sec.  
60.5398b(b)(2) or a statement that there were no deviations from the 
monitoring plan.
    (4) Results from each periodic screening during the reporting 
period. If the results of the periodic screening indicate a confirmed 
detection of emissions from an affected facility, you must submit the 
information in paragraphs (b)(4)(i) through (iv) of this section.
    (i) The date that the monitoring survey of your entire or the 
required portion of your fugitive emissions components affected 
facility was conducted.
    (ii) The date that you completed the instrument inspections of all 
required covers and closed vent systems(s).
    (iii) The date that you conducted the visual inspection for 
emissions of all required covers and closed vent systems.
    (iv) For each fugitive emission from a fugitive emissions 
components affected facility and all emissions or defects of each cover 
and closed vent system, you must submit the information in paragraphs 
(b)(4)(iv)(A) through (D) of this section.
    (A) Number and type of components for which fugitive emissions were 
detected.
    (B) Each emission or defect identified during the inspection for 
each cover and closed vent system.
    (C) Date of repair for each fugitive emission from a fugitive 
emissions components affected facility or each emission or defect for 
each cover and closed vent system.
    (D) Number and type of fugitive emission components and 
identification of each cover or closed vent system placed on delay of 
repair and an explanation for each delay of repair.
    (5) The information in paragraphs (b)(5)(i) through (iv) of this 
section if you are required to conduct OGI surveys in accordance with 
Sec.  60.5398b(b)(1)(i) or if you replace a periodic screening event 
with an OGI survey in accordance with Sec.  60.5398b(b)(1)(iv).
    (i) The date of the OGI survey.
    (ii) Number and type of components for which fugitive emissions 
were detected.
    (iii) Number and type of fugitive emissions components that were 
not repaired as required in Sec.  60.5397b(h).

[[Page 17128]]

    (iv) Number and type of fugitive emission components placed on 
delay of repair and an explanation for each delay of repair.
    (6) Any additional information regarding the performance of the 
periodic screening technology as specified by the Administrator, as 
part of the alternative test method approval described in Sec.  
60.5398b(d).
    (c) Maintain records. If you comply with the periodic screening 
requirements of Sec.  60.5398b(b), you must maintain the records in 
paragraphs (c)(1) through (11) of this section in addition to the 
records as specified in Sec.  60.5420b(c)(3) through (9) and (c)(14) 
and (15).
    (1) The monitoring plan as required in Sec.  60.5398b(b)(2).
    (2) Date of each periodic screening and date that results of the 
periodic screening were received.
    (3) Name of screening operator.
    (4) Alternative test method and technology used for screening, as 
well as the aggregate detection threshold for the technology and the 
spatial resolution of the technology (i.e., facility-level, area-level, 
or component-level).
    (5) Records of calibrations for technology used during the 
screening if calibration is required by the alternative test method 
approved in accordance with Sec.  60.5398b(d).
    (6) Results from periodic screening. If the results of the periodic 
screening indicate a confirmed detection of emissions from an affected 
facility, you must maintain the records in paragraphs (c)(6)(i) through 
(v) of this section.
    (i) The date of the inspection of the fugitive emissions components 
and inspection of covers and closed vent system, as specified in Sec.  
60.5398b(b)(5).
    (ii) Name of operator(s) performing the survey or inspection.
    (iii) For surveys and instrument inspections, identification of the 
monitoring instrument(s) used.
    (iv) Records of calibrations for the instrument(s) used during the 
survey or instrument inspection, as applicable.
    (v) For each fugitive emission from a fugitive emissions components 
affected facility and each leak or defect for each cover and closed 
vent system inspection, you must maintain the records in paragraphs 
(c)(6)(v)(A) through (F) of this section.
    (A) The location of the fugitive emissions identified using a 
unique identifier for the source of the emissions and the type of 
fugitive emissions component.
    (B) The location of the emission or defect from a cover or closed 
vent system using a unique identifier for the source of the emission or 
defect.
    (C) If a defect of a closed vent system, cover, or control device 
is identified, a description of the defect.
    (D) The date of repair for each fugitive emission from a fugitive 
emissions components affected facility or each emission or defect for 
each cover and closed vent system.
    (E) Number and type of fugitive emission components and 
identification of each cover or closed vent system placed on delay of 
repair and an explanation for each delay of repair.
    (F) For each fugitive emission component placed on delay of repair 
for reason of replacement component unavailability, the operator must 
document: the date the component was added to the delay of repair list, 
the date the replacement fugitive component or part thereof was 
ordered, the anticipated component delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the component.
    (7) The date the investigative analysis was initiated, and the 
result of the investigative analysis conducted in accordance with Sec.  
60.5398b(b)(5)(vi) and (vii), as applicable.
    (8) Dates of implementation and completion of action(s) taken as a 
result of the investigative analysis and a description of the action(s) 
taken in accordance with Sec.  60.5398b(b)(5)(vi) and (vii), as 
applicable.
    (9) The information in paragraphs (c)(9)(i) through (vii) of this 
section if you are required to conduct OGI surveys in accordance with 
Sec.  60.5398b(b)(1)(i) or if you replace a periodic screening event 
with an OGI survey in accordance with Sec.  60.5398b(b)(1)(iv).
    (i) The date of the OGI survey.
    (ii) Location of each fugitive emission identified.
    (iii) Type of fugitive emissions component for which fugitive 
emissions were detected.
    (iv) The date of first attempt at repair of the fugitive emissions 
component(s).
    (v) The date of successful repair of the fugitive emissions 
component(s), including the resurvey to verify the repair.
    (vi) Identification of each fugitive emissions component placed on 
delay of repair and an explanation for each delay of repair.
    (vii) For each fugitive emission component placed on delay of 
repair for reason of replacement component unavailability, the operator 
must document: the date the component was added to the delay of repair 
list, the date the replacement fugitive component or part thereof was 
ordered, the anticipated component delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the component.
    (10) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (11) All records required by the alternative approved in accordance 
with Sec.  60.5398b(d).
    (d) Information submittal. If you comply with the continuous 
monitoring system requirements of Sec.  60.5398b(c), you must submit 
the information in paragraphs (d)(1) through (6) of this section in the 
annual report required by Sec.  60.5420b(b)(4) through (11).
    (1) The start date and end date for each period where the emissions 
rate determined in accordance with Sec.  60.5398b(c)(6) exceeded one of 
the action levels determined in accordance with Sec.  60.5398b(c)(4). 
Include which action level was exceeded (the 7-day or 90-day rolling 
average), the numerical value of the action level, and the mass 
emission rate calculated by the continuous monitoring system in the 
report.
    (2) The date the investigative analysis was initiated, and the 
result of the investigative analysis conducted in accordance with Sec.  
60.5398b(c)(7), as applicable.
    (3) Dates of implementation and completion of action(s) taken to 
reduce the mass emission rate and a description of the action(s) taken 
in accordance with Sec.  60.5398b(c)(7), as applicable.
    (4) If there are no instances reported under paragraph (d)(1) of 
this section, report your numerical action levels and the highest 7-day 
rolling average and highest 90-day rolling average determined by your 
continuous monitoring system during the reporting period.
    (5) The start date for each instance where the 12-month rolling 
average operational downtime of the system exceeded 10 percent and the 
value of the 12-month rolling average operational downtime during the 
period. If there were no instances during the reporting period where 
the 12-month rolling average operational downtime of the system 
exceeded 10 percent, report the highest value of the 12-month rolling 
average operational downtime during the reporting period.
    (6) Any additional information regarding the performance of the 
continuous monitoring system as specified by the Administrator, as part 
of the alternative test method approval described in Sec.  60.5398b(d).
    (e) Maintain records. If you comply with the continuous monitoring 
system

[[Page 17129]]

requirements of Sec.  60.5398b(c), you must maintain the records in 
paragraphs (e)(1) through (15) of this section.
    (1) The monitoring plan required by Sec.  60.5398b(c)(2).
    (2) Date of commencement of continuous monitoring with your 
continuous monitoring system.
    (3) The detection threshold of the continuous monitoring system.
    (4) The results of checks for power and function in accordance with 
Sec.  60.5398b(c)(1)(ii).
    (5) The beginning and end of each period of operational downtime 
for the system.
    (6) Each rolling 12-month average operational downtime for the 
system, calculated in accordance with Sec.  60.5398b(c)(1)(ii)(D).
    (7) The 7-day rolling average and 90-day rolling average action 
levels for the site determined in accordance with Sec.  60.5398b(c)(4).
    (8) The information in paragraphs (e)(8)(i) through (v) of this 
section each time you establish site-specific baseline emissions in 
accordance with Sec.  60.5398b(c)(5).
    (i) Records of inspections of fugitive emissions components, 
covers, and closed vent systems required by Sec.  60.5398b(c)(5)(i), 
including the date of inspection, location of each emission or defect 
identified, date of successful repair of each fugitive emissions 
component, cover, or closed vent system.
    (ii) Records of inspections of control devices required by Sec.  
60.5398b(c)(5)(ii), including the date of the inspection and the 
results of the inspection.
    (iii) The start date and time and end date and time of any 
maintenance activities that occurred during the 30 operating day 
period.
    (iv) The site-level emission rate for each day during the 30 
operating day period.
    (v) The calculated site-specific baseline emission rate.
    (9) Each methane mass emission rate reading determined by the 
system.
    (10) Each daily, 7-day, and 90-day average mass emission rate which 
was determined in accordance with Sec.  60.5398b(c)(6). If you exceed 
the 90-day action level, you must also keep records of the 30-day 
average mass emission rate following completion of the initial actions 
to reduce the average mass emission rate, in accordance with Sec.  
60.5398b(c)(8)(i).
    (11) The results of each comparison of the emissions rate 
determined in accordance with Sec.  60.5398b(c)(6) to the action level 
determined in accordance with Sec.  60.5398b(c)(4).
    (12) The date the investigative analysis was initiated, and the 
result of the investigative analysis conducted in accordance with Sec.  
60.5398b(c)(7), as applicable.
    (13) Dates of implementation and completion of action(s) taken to 
reduce the mass emission rate below the action level and a description 
of the action(s) taken in accordance with Sec.  60.5398b(c)(7), as 
applicable.
    (14) Each mass emission rate reduction plan developed in accordance 
with Sec.  60.5398b(c)(8), as applicable. You must keep records of the 
actions taken in accordance with the plan and the date such actions are 
taken.
    (15) Any additional information regarding the performance of the 
continuous monitoring technology as specified by the Administrator, as 
part of the alternative test method approval described in Sec.  
60.5398b(d).


Sec.  60.5425b   What parts of the General Provisions apply to me?

    Table 5 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  60.1 through 60.19 apply to you.


Sec.  60.5430b   What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein shall have 
the meaning given them in the Act or in subpart A of this part; and the 
following terms shall have the specific meanings given them.
    Access to electrical power means commercial line power is available 
onsite, with sufficient capacity to support the required power loading 
of onsite equipment, and which provides reliable and consistent power.
    Acid gas means a gas stream of hydrogen sulfide (H<INF>2</INF>S) 
and carbon dioxide (CO<INF>2</INF>) that has been separated from sour 
natural gas by a sweetening unit.
    Alaskan North Slope means the approximately 69,000 square-mile area 
extending from the Brooks Range to the Arctic Ocean.
    API Gravity means the weight per unit volume of hydrocarbon liquids 
as measured by a system recommended by the American Petroleum Institute 
(API) and is expressed in degrees.
    Artificial lift equipment means mechanical pumps including, but not 
limited to, rod pumps and electric submersible pumps used to flowback 
fluids from a well.
    Associated gas means the natural gas from wells operated primarily 
for oil production that is released from the liquid hydrocarbon during 
the initial stage of separation after the wellhead. Associated gas 
production begins at the startup of production after the flow back 
period ends. Gas from wildcat or delineation wells is not associated 
gas.
    Average aggregate detection threshold means:
    (1) For the purposes of Sec.  60.5398b, the average of all site-
level detection thresholds from a single deployment (e.g., a singular 
flight that surveys multiple well sites, centralized production 
facility, and/or compressor stations) of a technology; and
    (2) For the purposes of Sec.  60.5371b, the average of all site-
level detection thresholds from a single deployment in the same basin 
and field.
    Bleed rate means the rate in standard cubic feet per hour at which 
natural gas is continuously vented (bleeds) from a process controller.
    Capital expenditure means, as an alternative to the definition in 
40 CFR 60.2, an expenditure for a physical or operational change to an 
existing facility that:
    (1) Exceeds P, the product of the facility's replacement cost, R, 
and an adjusted annual asset guideline repair allowance, A, as 
reflected by the following equation: P = R x A, where:
    (i) The adjusted annual asset guideline repair allowance, A, is the 
product of the percent of the replacement cost, Y, and the applicable 
basic annual asset guideline repair allowance, B, divided by 100 as 
reflected by the following equation: A = Y x (B / 100);
    (ii) The percent Y is determined from the following equation: Y = 
(CPI of date of construction/most recently available CPI of date of 
project), where the ``CPI-U, U.S. city average, all items'' must be 
used for each CPI value; and
    (iii) The applicable basic annual asset guideline repair allowance, 
B, is 4.5.
    (2) [Reserved]
    Centralized production facility means one or more storage vessels 
and all equipment at a single surface site used to gather, for the 
purpose of sale or processing to sell, crude oil, condensate, produced 
water, or intermediate hydrocarbon liquid from one or more offsite 
natural gas or oil production wells. This equipment includes, but is 
not limited to, equipment used for storage, separation, treating, 
dehydration, artificial lift, combustion, compression, pumping, 
metering, monitoring, and flowline. Process vessels and process tanks 
are not considered storage vessels or storage tanks. A centralized 
production facility is located upstream of the natural gas processing 
plant or the crude oil pipeline breakout station and is a part of 
producing operations.
    Centrifugal compressor means any machine for raising the pressure 
of a natural gas by drawing in low pressure natural gas and discharging 
significantly

[[Page 17130]]

higher-pressure natural gas by means of mechanical rotating vanes or 
impellers. Screw, sliding vane, and liquid ring compressors are not 
centrifugal compressors for the purposes of this subpart.
    Centrifugal compressor equipped with sour seal oil separator and 
capture system means a wet seal centrifugal compressor system which has 
an intermediate closed process that degasses most of the gas entrained 
in the sour seal oil and sends that gas to either another process or 
combustion device (i.e., degassed emissions are recovered). The de-gas 
emissions are routed back to a process or combustion device directly 
from the intermediate closed degassing process; after the intermediate 
closed process the oil is ultimately recycled for recirculation in the 
seals to the lube oil tank where any small amount of residual gas is 
released through a vent.
    Certifying official means one of the following:
    (1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business 
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized 
representative of such person if the representative is responsible for 
the overall operation of one or more manufacturing, production, or 
operating facilities with an affected facility subject to this subpart 
and either:
    (i) The facilities employ more than 250 persons or have gross 
annual sales or expenditures exceeding $25 million (in second quarter 
1980 dollars); or
    (ii) The Administrator is notified of such delegation of authority 
prior to the exercise of that authority. The Administrator reserves the 
right to evaluate such delegation;
    (2) For a partnership (including but not limited to general 
partnerships, limited partnerships, and limited liability partnerships) 
or sole proprietorship: A general partner or the proprietor, 
respectively. If a general partner is a corporation, the provisions of 
paragraph (1) of this definition apply;
    (3) For a municipality, state, Federal, or other public agency: 
Either a principal executive officer or ranking elected official. For 
the purposes of this part, a principal executive officer of a Federal 
agency includes the chief executive officer having responsibility for 
the overall operations of a principal geographic unit of the agency 
(e.g., a Regional Administrator of EPA); or
    (4) For affected facilities:
    (i) The designated representative in so far as actions, standards, 
requirements, or prohibitions under title IV of the CAA or the 
regulations promulgated thereunder are concerned; or
    (ii) The designated representative for any other purposes under 
this part.
    Closed vent system means a system that is not open to the 
atmosphere and that is composed of hard-piping, ductwork, connections, 
and, if necessary, flow-inducing devices that transport gas or vapor 
from a piece or pieces of equipment to a control device or back to a 
process.
    Coil tubing cleanout means the process where an operator runs a 
string of coil tubing to the packed proppant within a well and jets the 
well to dislodge the proppant and provide sufficient lift energy to 
flow it to the surface. Coil tubing cleanout includes mechanical 
methods to remove solids and/or debris from a wellbore.
    Collection system means any infrastructure that conveys gas or 
liquids from the well site to another location for treatment, storage, 
processing, recycling, disposal or other handling.
    Completion combustion device means any ignition device, installed 
horizontally or vertically, used in exploration and production 
operations to combust otherwise vented emissions from completions. 
Completion combustion devices include pit flares.
    Compressor mode means the operational and pressurized status of a 
compressor. For both centrifugal compressors and reciprocating 
compressors, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
    Compressor station means any permanent combination of one or more 
compressors that move natural gas at increased pressure through 
gathering or transmission pipelines, or into or out of storage. This 
includes but is not limited to gathering and boosting stations and 
transmission compressor stations. The combination of one or more 
compressors located at a well site, centralized production facility, or 
an onshore natural gas processing plant, is not a compressor station 
for purposes of Sec.  60.5365b(e) and Sec.  60.5397b.
    Condensate means hydrocarbon liquid separated from natural gas that 
condenses due to changes in the temperature, pressure, or both, and 
remains liquid at standard conditions.
    Connector means flanged, screwed, or other joined fittings used to 
connect two pipe lines or a pipe line and a piece of process equipment 
or that close an opening in a pipe that could be connected to another 
pipe. Joined fittings welded completely around the circumference of the 
interface are not considered connectors for the purpose of this 
regulation.
    Continuous bleed means a continuous flow of pneumatic supply 
natural gas to a process controller.
    Crude oil and natural gas source category means:
    (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.
    Custody meter means the meter where natural gas or hydrocarbon 
liquids are measured for sales, transfers, and/or royalty 
determination.
    Custody meter assembly means an assembly of fugitive emissions 
components, including the custody meter, valves, flanges, and 
connectors necessary for the proper operation of the custody meter.
    Custody transfer means the transfer of crude oil or natural gas 
after processing and/or treatment in the producing operations, or from 
storage vessels or automatic transfer facilities or other such 
equipment, including product loading racks, to pipelines or any other 
forms of transportation.
    Dehydrator means a device in which an absorbent directly contacts a 
natural gas stream and absorbs water in a contact tower or adsorption 
column (absorber).
    Delineation well means a well drilled in order to determine the 
boundary of a field or producing reservoir.
    Deviation means any instance in which an affected source subject to 
this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, or work practice standard;
    (2) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit; or
    (3) Fails to meet any emission limit, operating limit, or work 
practice standard of this subpart during startup, shutdown, or 
malfunction, regardless of whether or not such failure is permitted by 
this subpart.
    Distance piece means an open or enclosed casing through which the 
piston rod travels, separating the compressor cylinder from the 
crankcase.

[[Page 17131]]

    Double block and bleed system means two block valves connected in 
series with a bleed valve or line that can vent the line between the 
two block valves.
    Duct work means a conveyance system such as those commonly used for 
heating and ventilation systems. It is often made of sheet metal and 
often has sections connected by screw or crimping. Hard-piping is not 
ductwork.
    Emergency shutdown device means a device which functions 
exclusively to protect personnel and/or prevent physical damage to 
equipment by shutting down equipment or gas flow during unsafe 
conditions resulting from an unexpected event, such as a pipe break or 
fire. For the purposes of this subpart, an emergency shutdown device is 
not used for routine control of operating conditions.
    Equipment, as used in the standards and requirements of this 
subpart relative to the process unit equipment affected facility at 
onshore natural gas processing plants, means each pump, pressure relief 
device, open-ended valve or line, valve, and flange or other connector 
that has the potential to emit methane or VOC and any device or system 
required by those same standards and requirements of this subpart.
    Field gas means feedstock gas entering the natural gas processing 
plant.
    Field gas gathering means the system used transport field gas from 
a field to the main pipeline in the area.
    First attempt at repair 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.
    Flare means a thermal oxidation system using an open (without 
enclosure) flame. Completion combustion devices as defined in this 
section are not considered flares.
    Flow line means a pipeline used to transport oil and/or gas to a 
processing facility or a mainline pipeline.
    Flowback means the process of allowing fluids and entrained solids 
to flow from a well following a treatment, either in preparation for a 
subsequent phase of treatment or in preparation for cleanup and 
returning the well to production. The term flowback also means the 
fluids and entrained solids that emerge from a well during the flowback 
process. The flowback period begins when material introduced into the 
well during the treatment returns to the surface following hydraulic 
fracturing or refracturing. The flowback period ends when either the 
well is shut in and permanently disconnected from the flowback 
equipment or at the startup of production. The flowback period includes 
the initial flowback stage and the separation flowback stage. 
Screenouts, coil tubing cleanouts, and plug drill-outs are not 
considered part of the flowback process.
    Fuel gas means gases that are combusted to derive useful work or 
heat.
    Fuel gas system means the offsite and onsite piping and flow and 
pressure control system that gathers gaseous stream(s) generated by 
onsite operations, may blend them with other sources of gas, and 
transports the gaseous stream for use as fuel gas in combustion devices 
or in-process combustion equipment, such as furnaces and gas turbines, 
either singly or in combination.
    Fugitive emissions means, for the purposes of Sec.  60.5397b, any 
indication of emissions observed from a fugitive emissions component 
using AVO, an indication of visible emissions observed from an OGI 
instrument, or an instrument reading of 500 ppmv or greater using 
Method 21 of appendix A-7 to this part.
    Fugitive emissions component means any component that has the 
potential to emit fugitive emissions of methane or VOC at a well site, 
centralized production facility, or compressor station, such as valves 
(including separator dump valves), connectors, pressure relief devices, 
open-ended lines, flanges, covers and closed vent systems not subject 
to Sec.  60.5411b, thief hatches or other openings on a storage vessel 
not subject to Sec.  60.5395b, compressors, instruments, meters, and 
yard piping.
    Gas to oil ratio (GOR) means the ratio of the volume of gas at 
standard temperature and pressure that is produced from a volume of oil 
when depressurized to standard temperature and pressure.
    Hard-piping means pipe or tubing that is manufactured and properly 
installed using good engineering judgment and standards such as ASME 
B31.3, Process Piping (available from the American Society of 
Mechanical Engineers, P.O. Box 2300, Fairfield, NJ 07007-2300).
    Hydraulic fracturing means the process of directing pressurized 
fluids containing any combination of water, proppant, and any added 
chemicals to penetrate tight formations, such as shale or coal 
formations, that subsequently require high rate, extended flowback to 
expel fracture fluids and solids during completions.
    Hydraulic refracturing means conducting a subsequent hydraulic 
fracturing operation at a well that has previously undergone a 
hydraulic fracturing operation.
    In gas/vapor service means that the piece of equipment contains 
process fluid that is in the gaseous state at operating conditions.
    In heavy liquid service means that the piece of equipment is not in 
gas/vapor service or in light liquid service.
    In light liquid service means that the piece of equipment contains 
a liquid that meets the conditions specified in Sec.  60.5402b(d)(2) or 
Sec.  60.5403b.
    In vacuum service means that equipment is operating at an internal 
pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient 
pressure.
    In wet gas service means that a compressor or piece of equipment 
contains or contacts the field gas before the extraction step at a gas 
processing plant process unit.
    Initial calibration value as used in the standards and requirements 
of this subpart relative to the process unit equipment affected 
facility at onshore natural gas processing plants means the 
concentration measured during the initial calibration at the beginning 
of each day required in Sec.  60.5403b, or the most recent calibration 
if the instrument is recalibrated during the day (i.e., the calibration 
is adjusted) after a calibration drift assessment.
    Initial flowback stage means the period during a well completion 
operation which begins at the onset of flowback and ends at the 
separation flowback stage.
    Intermediate hydrocarbon liquid means any naturally occurring, 
unrefined petroleum liquid.
    Intermittent vent natural gas-driven process controller means a 
process controller that is not designed to have a continuous bleed rate 
but is instead designed to only release natural gas to the atmosphere 
as part of the actuation cycle.
    Liquefied natural gas unit means a unit used to cool natural gas to 
the point at which it is condensed into a liquid which is colorless, 
odorless, non-corrosive and non-toxic.
    Liquid collection system means tankage and/or lines at a well site 
to contain liquids from one or more wells or to convey liquids to 
another site.
    Liquids dripping means any visible leakage from the seal, including 
spraying, misting, clouding, and ice formation.
    Liquids unloading means the unloading of liquids that have

[[Page 17132]]

accumulated over time in gas wells, which are impeding or halting 
production. Routine well maintenance activities, including workovers, 
screenouts, coil tubing cleanouts, or any other activity that requires 
a rig or other machinery are not considered liquids unloading.
    Local distribution company (LDC) custody transfer station means a 
metering station where the LDC receives a natural gas supply from an 
upstream supplier, which may be an interstate transmission pipeline or 
a local natural gas producer, for delivery to customers through the 
LDC's intrastate transmission or distribution lines.
    Low-e valve means a valve (including its specific packing assembly) 
for which the manufacturer has issued a written warranty or performance 
guarantee that it will not emit fugitives at greater than 100 ppm in 
the first five years. A valve may qualify as a low-e valve if it is as 
an extension of another valve that has qualified as a low-e valve.
    Low-e packing means a valve packing product for which the 
manufacturer has issued a written warranty or performance guarantee 
that it will not emit fugitives at greater than 100 ppm in the first 
five years. Low-e injectable packing is a type of low-e packing product 
for which the manufacturer has also issued a written warranty or 
performance guarantee and that can be injected into a valve during a 
``drill-and-tap'' repair of the valve.
    Low pressure well means a well that satisfies at least one of the 
following conditions:
    (1) The static pressure at the wellhead following fracturing but 
prior to the onset of flowback is less than the flow line pressure;
    (2) The pressure of flowback fluid immediately before it enters the 
flow line, as determined under Sec.  60.5432b, is less than the flow 
line pressure; or
    (3) Flowback of the fracture fluids will not occur without the use 
of artificial lift equipment.
    Major production and processing equipment means reciprocating or 
centrifugal compressors, glycol dehydrators, heater/treaters, 
separators, control devices, natural gas-driven process controllers, 
natural gas-driven pumps, and storage vessels or tank batteries 
collecting crude oil, condensate, intermediate hydrocarbon liquids, or 
produced water, for the purpose of determining whether a well site is a 
wellhead only well site.
    Maximum average daily throughput means the following:
    (1) The earliest calculation of daily average throughput, 
determined as described in paragraph (2) or (3) of this definition, to 
a tank battery over the days that production is routed to that tank 
battery during the 30-day PTE evaluation period employing generally 
accepted methods specified in Sec.  60.5365b(e)(2).
    (2) If throughput to the tank battery is measured on a daily basis 
(e.g., via level gauge automation or daily manual gauging), the maximum 
average daily throughput is the average of all daily throughputs for 
days on which throughput was routed to the tank battery during the 30-
day evaluation period; or
    (3) If throughput to the tank battery is not measured on a daily 
basis (e.g., via manual gauging at the start and end of loadouts), the 
maximum average daily throughput is the highest, of the average daily 
throughputs, determined for any production period to that tank battery 
during the 30-day evaluation period, as determined by averaging total 
throughput to that tank battery over each production period. A 
production period begins when production begins to be routed to a tank 
battery and ends either when throughput is routed away from that tank 
battery or when a loadout occurs from that tank battery, whichever 
happens first. Regardless of the determination methodology, operators 
must not include days during which throughput is not routed to the tank 
battery when calculating maximum average daily throughput for that tank 
battery.
    Multi-wellhead only well site means a well site that contains two 
or more wellheads and no major production and processing equipment.
    Natural gas-driven diaphragm pump means a positive displacement 
pump powered by pressurized natural gas that uses the reciprocating 
action of flexible diaphragms in conjunction with check valves to pump 
a fluid. A pump in which a fluid is displaced by a piston driven by a 
diaphragm is not considered a diaphragm pump for purposes of this 
subpart. A lean glycol circulation pump that relies on energy exchange 
with the rich glycol from the contactor is not considered a diaphragm 
pump.
    Natural gas-driven piston pump means a positive displacement pump 
powered by pressurized natural gas that moves and pressurizes fluid by 
using one or more reciprocating pistons. A pump in which a fluid is 
displaced by a piston driven by a diaphragm is considered a piston pump 
for purposes of this subpart. A lean glycol circulation pump that 
relies on energy exchange with the rich glycol from the contactor is 
not considered a piston pump.
    Natural gas-driven process controller means a process controller 
powered by pressurized natural gas.
    Natural gas liquids means the hydrocarbons, such as ethane, 
propane, butane, and pentane that are extracted from field gas.
    Natural gas processing plant (gas plant) means any processing site 
engaged in the extraction of natural gas liquids from field gas, 
fractionation of mixed natural gas liquids to natural gas products, or 
both. A Joule-Thompson valve, a dew point depression valve, or an 
isolated or standalone Joule-Thompson skid is not a natural gas 
processing plant.
    Natural gas transmission means the pipelines used for the long-
distance transport of natural gas (excluding processing). Specific 
equipment used in natural gas transmission includes the land, mains, 
valves, meters, boosters, regulators, storage vessels, dehydrators, 
compressors, and their driving units and appurtenances, and equipment 
used for transporting gas from a production plant, delivery point of 
purchased gas, gathering system, storage area, or other wholesale 
source of gas to one or more distribution area(s).
    No detectable emissions means, for the purposes of Sec.  60.5401b 
and Sec.  60.5403b, that the equipment is operating with an instrument 
reading of less than 500 ppmv above background, as determined by Method 
21 of appendix A-7 to this part.
    No identifiable emissions means, for the purposes of covers, closed 
vent systems, and self-contained natural gas-driven process controllers 
and as determined according to the provisions of Sec.  60.5416b, that 
no emissions are detected by AVO means when inspections are conducted 
by AVO; no emissions are imaged with an OGI camera when inspections are 
conducted with OGI; and equipment is operating with an instrument 
reading of less than 500 ppmv above background, as determined by Method 
21 of appendix A-7 to this part when inspections are conducted with 
Method 21.
    Nonfractionating plant means any gas plant that does not 
fractionate mixed natural gas liquids into natural gas products.
    Non-natural gas-driven process controller means an instrument that 
is actuated using other sources of power than pressurized natural gas; 
examples include solar, electric, and instrument air.
    Onshore means all facilities except those that are located in the 
territorial seas or on the outer continental shelf.
    Open-ended valve or line or open-ended vent line means any valves,

[[Page 17133]]

except safety relief valves, having one side of the valve seat in 
contact with process fluid and one side open to the atmosphere, either 
directly or through open piping.
    Plug drill-out means the removal of a plug (or plugs) that was used 
to isolate different sections of the well.
    Process controller means an automated instrument used for 
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
    Pressure release means the emission of materials resulting from 
system pressure being greater than set pressure of the pressure relief 
device.
    Pressure vessel means a storage vessel that is used to store 
liquids or gases and is designed not to vent to the atmosphere as a 
result of compression of the vapor headspace in the pressure vessel 
during filling of the pressure vessel to its design capacity.
    Pressurized mode means when the compressor contains natural gas 
that is maintained at a pressure higher than the atmospheric pressure.
    Process improvement means routine changes made for safety and 
occupational health requirements, for energy savings, for better 
utility, for ease of maintenance and operation, for correction of 
design deficiencies, for bottleneck removal, for changing product 
requirements, or for environmental control.
    Process unit means components assembled for the extraction of 
natural gas liquids from field gas, the fractionation of the liquids 
into natural gas products, or other operations associated with the 
processing of natural gas products. A process unit can operate 
independently if supplied with sufficient feed or raw materials and 
sufficient storage facilities for the products.
    Process unit shutdown means a work practice or operational 
procedure that stops production from a process unit or part of a 
process unit during which it is technically feasible to clear process 
material from a process unit or part of a process unit consistent with 
safety constraints and during which repairs can be accomplished. The 
following are not considered process unit shutdowns:
    (1) An unscheduled work practice or operational procedure that 
stops production from a process unit or part of a process unit for less 
than 24 hours.
    (2) An unscheduled work practice or operational procedure that 
would stop production from a process unit or part of a process unit for 
a shorter period of time than would be required to clear the process 
unit or part of the process unit of materials and start up the unit, 
and would result in greater emissions than delay of repair of leaking 
components until the next scheduled process unit shutdown.
    (3) The use of spare equipment and technically feasible bypassing 
of equipment without stopping production.
    Produced water means water that is extracted from the earth from an 
oil or natural gas production well, or that is separated from crude 
oil, condensate, or natural gas after extraction.
    Qualified Professional Engineer means an individual who is licensed 
by a state as a Professional Engineer to practice one or more 
disciplines of engineering and who is qualified by education, technical 
knowledge, and experience to make the specific technical certifications 
required under this subpart. Professional engineers making these 
certifications must be currently licensed in at least one state in 
which the certifying official is located.
    Quarter means a 3-month period. For purposes of standards for 
process unit equipment affected facilities at onshore natural gas 
processing plants, the first quarter concludes on the last day of the 
last full month during the 180 days following initial startup.
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process gas by positive displacement, employing 
linear movement of the driveshaft.
    Reciprocating compressor rod packing means a series of flexible 
rings in machined metal cups that fit around the reciprocating 
compressor piston rod to create a seal limiting the amount of 
compressed natural gas that escapes to the atmosphere, or other 
mechanism that provides the same function.
    Recovered gas means gas recovered through the separation process 
during flowback.
    Recovered liquids means any crude oil, condensate or produced water 
recovered through the separation process during flowback.
    Reduced emissions completion means a well completion following 
fracturing or refracturing where gas flowback that is otherwise vented 
is captured, cleaned, and 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 other useful purpose that a purchased fuel or 
raw material would serve, with no direct release to the atmosphere.
    Reduced sulfur compounds means H<INF>2</INF>S, carbonyl sulfide 
(COS), and carbon disulfide (CS<INF>2</INF>).
    Removed from service means that a storage vessel affected facility 
has been physically isolated and disconnected from the process for a 
purpose other than maintenance in accordance with Sec.  60.5395b(c)(1).
    Repaired means the following:
    (1) For the purposes of fugitive emissions components affected 
facilities, that fugitive emissions components are adjusted, replaced, 
or otherwise altered, in order to eliminate fugitive emissions and 
resurveyed as specified in Sec.  60.5397b(h)(4) and it is verified that 
emissions from the fugitive emissions components are below the 
applicable fugitive emissions definition.
    (2) For the purposes of process unit equipment affected facilities, 
that equipment is adjusted, or otherwise altered, in order to eliminate 
a leak as defined in Sec. Sec.  60.5400b and 60.5401b and is re-
monitored as specified in Sec.  60.5400b(b) introductory text and 
(b)(1) or Sec.  60.5403b, respectively, to verify that emissions from 
the equipment are below the applicable leak definition. Pumps in light 
liquid service subject to Sec.  60.5400b(c)(2) or Sec.  
60.5401b(b)(1)(ii) are not subject to re-monitoring.
    Replacement cost means the capital needed to purchase all the 
depreciable components in a facility.
    Returned to service means that a storage vessel affected facility 
that was removed from service has been:
    (1) Reconnected to the original source of liquids or has been used 
to replace any storage vessel affected facility; or
    (2) Installed in any location covered by this subpart and 
introduced with crude oil, condensate, intermediate hydrocarbon liquids 
or produced water.
    Routed to a process or route to a process means the emissions are 
conveyed via a closed vent system to any 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 and/or transformed by chemical reaction into 
materials that are not regulated materials and/or incorporated into a 
product; and/or recovered.
    Salable quality gas means natural gas that meets the flow line or 
collection system operator specifications, regardless of whether such 
gas is sold.
    Screenout means an attempt to clear proppant from the wellbore to 
dislodge the proppant out of the well.
    Self-contained process controller means a natural gas-driven 
process controller that releases gas into the downstream piping and not 
to the atmosphere, resulting in zero methane and VOC emissions.

[[Page 17134]]

    Self-contained wet seal centrifugal compressor means:
    (1) A wet seal centrifugal 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) or 
which has an intermediate closed process that degasses most of the gas 
entrained in the seal oil and sends that gas to another process. The 
de-gas emissions are routed back to suction or process directly from 
the closed or intermediate closed degassing process; after the closed 
or intermediate closed degassing process the oil is ultimately recycled 
for recirculation in the seals to the lube oil tank where any small 
amount of residual gas is released through a vent.
    (2) A wet seal centrifugal compressor equipped with mechanical wet 
seals, where
    (i) A differential pressure is maintained on the system and there 
is no off gassing of the lube oil, and
    (ii) The mechanical seal is integrated into the compressor housing.
    Sensor means a device that measures a physical quantity or the 
change in a physical quantity such as temperature, pressure, flow rate, 
pH, or liquid level.
    Separation flowback stage means the period during a well completion 
operation when it is technically feasible for a separator to function. 
The separation flowback stage ends either at the startup of production, 
or when the well is shut in and permanently disconnected from the 
flowback equipment.
    Separator dump valve means, for purposes of the fugitive emission 
standards in Sec. Sec.  60.5397b and 60.5398b, a liquid-control valve 
in a separator that controls the liquid level within the separator 
vessel.
    Single wellhead only well site means a wellhead only well site that 
contains only one wellhead and no major production and processing 
equipment.
    Small well site means, for purposes of the fugitive emissions 
standards in Sec. Sec.  60.5397b and 60.5398b, 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. Small well sites cannot include any controlled storage vessels 
(or controlled tank batteries), control devices, natural gas-driven 
process controllers, or natural gas-driven pumps.
    Startup of production means the beginning of initial flow following 
the end of flowback when there is continuous recovery of salable 
quality gas and separation and recovery of any crude oil, condensate, 
or produced water, except as otherwise provided in this definition. For 
the purposes of the fugitive monitoring requirements of Sec.  60.5397b, 
startup of production means the beginning of the continuous recovery of 
salable quality gas and separation and recovery of any crude oil, 
condensate, or produced water.
    Storage vessel means a tank or other vessel that contains an 
accumulation of crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water, and that is constructed primarily of 
nonearthen materials (such as wood, concrete, steel, fiberglass, or 
plastic) which provide structural support. A well completion vessel 
that receives recovered liquids from a well after startup of production 
following flowback for a period which exceeds 60 days is considered a 
storage vessel under this subpart. A tank or other vessel shall not be 
considered a storage vessel if it has been removed from service in 
accordance with the requirements of Sec.  60.5395b(c)(1) until such 
time as such tank or other vessel has been returned to service. For the 
purposes of this subpart, the following are not considered storage 
vessels:
    (1) Vessels that are skid-mounted or permanently attached to 
something that is mobile (such as trucks, railcars, barges or ships), 
and are intended to be located at a site for less than 180 consecutive 
days. If you do not keep or are not able to produce records, as 
required by Sec.  60.5420b(c)(5)(iv), showing that the vessel has been 
located at a site for less than 180 consecutive days, the vessel 
described herein is considered to be a storage vessel from the date the 
original vessel was first located at the site. This exclusion does not 
apply to a well completion vessel as described above.
    (2) Process vessels such as surge control vessels, bottoms 
receivers or knockout vessels.
    (3) Pressure vessels designed to operate in excess of 204.9 
kilopascals and without emissions to the atmosphere.
    Sulfur production rate means the rate of liquid sulfur accumulation 
from the sulfur recovery unit.
    Sulfur recovery unit means a process device that recovers element 
sulfur from acid gas.
    Surface site means any combination of one or more graded pad sites, 
gravel pad sites, foundations, platforms, or the immediate physical 
location upon which equipment is physically affixed.
    Sweetening unit means a process device that removes hydrogen 
sulfide and/or carbon dioxide from the sour natural gas stream.
    Tank battery means a group of all storage vessels that are 
manifolded together for liquid transfer. A tank battery may consist of 
a single storage vessel if only one storage vessel is present.
    Total Reduced Sulfur (TRS) means the sum of the sulfur compounds 
hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl 
disulfide as measured by Method 16 of appendix A-6 to this part.
    Total SO<INF>2</INF> equivalents means the sum of volumetric or 
mass concentrations of the sulfur compounds obtained by adding the 
quantity existing as SO<INF>2</INF> to the quantity of SO<INF>2</INF> 
that would be obtained if all reduced sulfur compounds were converted 
to SO<INF>2</INF> (ppmv or kg/dscm (lb/dscf)).
    UIC Class I oilfield disposal well means a well with a UIC Class I 
permit that meets the definition in 40 CFR 144.6(a)(2) and receives 
eligible fluids from oil and natural gas exploration and production 
operations.
    UIC Class II oilfield disposal well means a well with a UIC Class 
II permit where wastewater resulting from oil and natural gas 
production operations is injected into underground porous rock 
formations not productive of oil or gas, and sealed above and below by 
unbroken, impermeable strata.
    Underground storage vessel means a storage vessel stored below 
ground.
    Well means a hole drilled for the purpose of producing oil or 
natural gas, or a well into which fluids are injected.
    Well completion means the process that allows for the flowback of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and tests the reservoir flow characteristics, which 
may vent produced hydrocarbons to the atmosphere via an open pit or 
tank.
    Well completion operation means any well completion with hydraulic 
fracturing or refracturing occurring at a well completion affected 
facility.
    Well completion vessel means a vessel that contains flowback during 
a well completion operation following hydraulic fracturing or 
refracturing. A well completion vessel may be a lined earthen pit, a 
tank or other vessel that is skid-mounted or portable. A well 
completion vessel that receives recovered liquids from a well after 
startup of production following flowback for a period which exceeds 60 
days is considered a storage vessel under this subpart.
    Well site means one or more surface sites that are constructed for 
the drilling and subsequent operation of any oil well, natural gas 
well, or injection well. For the purposes of the fugitive

[[Page 17135]]

emissions standards at Sec.  60.5397b, a well site does not include:
    (1) UIC Class II oilfield disposal wells and disposal facilities;
    (2) UIC Class I oilfield disposal wells; and
    (3) The flange immediately upstream of the custody meter assembly 
and equipment, including fugitive emissions components, located 
downstream of this flange.
    Wellhead means the piping, casing, tubing and connected valves 
protruding above the earth's surface for an oil and/or natural gas 
well. The wellhead ends where the flow line connects to a wellhead 
valve. The wellhead does not include other equipment at the well site 
except for any conveyance through which gas is vented to the 
atmosphere.
    Wellhead only well site means, for the purposes of the fugitive 
emissions standards at Sec.  60.5397b and the standards in Sec.  
60.5398b, a well site that contains one or more wellheads and no major 
production and processing equipment.
    Wildcat well means a well outside known fields or the first well 
drilled in an oil or gas field where no other oil and gas production 
exists.
    Yard piping means hard-piping at a well site, centralized 
production facility, or compressor station that is not part of a closed 
vent system.


Sec.  60.5432b   How do I determine whether a well is a low pressure 
well using the low pressure well equation?

    (a) To determine that your well is a low pressure well subject to 
Sec.  60.5375b(f), you must determine whether the characteristics of 
the well are such that the well meets the definition of low pressure 
well in Sec.  60.5430b. To determine that the well meets the definition 
of low pressure well in Sec.  60.5430b, you must use the low pressure 
well equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.011

Where:

(1) PL is the pressure of flowback fluid immediately before it 
enters the flow line, expressed in pounds force per square inch 
(psia), and is to be calculated using the equation above;
(2) PR is the pressure of the reservoir containing oil, gas, and 
water at the well site, expressed in psia;
(3) L is the true vertical depth of the well, expressed in feet 
(ft);
(4) qo is the flow rate of oil in the well, expressed in cubic feet/
second (cu ft/sec);
(5) qg is the flow rate of gas in the well, expressed in cu ft/sec;
(6) qw is the flow rate of water in the well, expressed in cu ft/
sec;
(7) ro is the density of oil in the well, expressed in pounds mass 
per cubic feet (lbm/cu ft).

    (b) You must determine the four values in paragraphs (a)(4) through 
(7) of this section, using the calculations in paragraphs (b)(1) 
through (15) of this section.
    (1) Determine the value of the bottom hole pressure, PBH (psia), 
based on available information at the well site, or by calculating it 
using the reservoir pressure, PR (psia), in the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.012

    (2) Determine the value of the bottom hole temperature, TBH (F), 
based on available information at the well site, or by calculating it 
using the true vertical depth of the well, L (ft), in the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.013

    (3) Calculate the value of the applicable natural gas specific 
gravity that would result from a separator pressure of 100 psig, 
[gamma]gs, using the following equation with: Separator at standard 
conditions (pressure, p = 14.7 (psia), temperature, T = 60 (F)); the 
oil API gravity at the well site, [gamma]<INF>0</INF>; and the gas 
specific gravity at the separator under standard conditions, [gamma]gp 
= 0.75:
[GRAPHIC] [TIFF OMITTED] TR08MR24.014


[[Page 17136]]


    (4) Calculate the value of the applicable dissolved GOR, Rs (scf/
STBO), using the following equation with: The bottom hole pressure, PBH 
(psia), determined in (b)(1) of this section; the bottom hole 
temperature, TBH (F), determined in (b)(2) of this section; the gas 
gravity at separator pressure of 100 psig, [gamma]gs, calculated in 
(b)(3) of this section; the oil API gravity, [gamma]o, at the well 
site; and the constants, C1, C2, and C3, found in Table 1 to this 
paragraph(b)(4):
[GRAPHIC] [TIFF OMITTED] TR08MR24.015


  Table 1 to Paragraph (b)(4)--Coefficients for the Correlation for Rs
------------------------------------------------------------------------
                                           [gamma] <= 30   [gamma] > 30
                Constant
------------------------------------------------------------------------
C1......................................          0.0362          0.0178
C2......................................          1.0937          1.1870
C3......................................         25.7240          23.931
------------------------------------------------------------------------

    (5) Calculate the value of the oil formation volume factor, Bo 
(bbl/STBO), using the following equation with: The bottom hole 
temperature, TBH (F), determined in paragraph (b)(2) of this section; 
the gas gravity at separator pressure of 100 psig, [gamma]gs, 
calculated in paragraph (b)(3) of this section; the dissolved GOR, Rs 
(scf/STBO), calculated in paragraph (b)(4) of this section; the oil API 
gravity, [gamma]o, at the well site; and the constants, C1, C2, and C3, 
found in Table 2 to this paragraph (b)(5):
[GRAPHIC] [TIFF OMITTED] TR08MR24.016


   Table 2 to Paragraph (b)(5)--Coefficients for the Correlation for B
------------------------------------------------------------------------
                                          [gamma] <= 30    [gamma] > 30
                Constant
------------------------------------------------------------------------
C1.....................................     4.677 x 10-4    4.670 x 10-4
C2.....................................     1.751 x 10-5    1.100 x 10-5
C3.....................................    -1.811 x 10-8    1.337 x 10-9
------------------------------------------------------------------------

    (6) Calculate the density of oil at the wellhead,
    [GRAPHIC] [TIFF OMITTED] TR08MR24.017
    

using the following equation with the value of the oil API gravity, 
[gamma]o, at the well site:
[GRAPHIC] [TIFF OMITTED] TR08MR24.018

    (7) Calculate the density of oil at bottom hole conditions,
    [GRAPHIC] [TIFF OMITTED] TR08MR24.019
    

using the following equation with: the dissolved GOR, Rs (scf/STBO), 
calculated in paragraph (b)(4) of this section; the oil formation 
volume factor, Bo (bbl/STBO), calculated in paragraph (b)(5) of this 
section; the oil density at the wellhead,
[GRAPHIC] [TIFF OMITTED] TR08MR24.020


calculated in paragraph (b)(6) of this section; and the dissolved gas 
gravity, [gamma]<INF>gd</INF> = 0.77:
[GRAPHIC] [TIFF OMITTED] TR08MR24.021

    (8) Calculate the density of oil in the well,
    [GRAPHIC] [TIFF OMITTED] TR08MR24.022
    

using the following equation with the density of oil at the wellhead,
[GRAPHIC] [TIFF OMITTED] TR08MR24.023


calculated in paragraph (b)(6) of this section; and the density of oil 
at bottom hole conditions,
[GRAPHIC] [TIFF OMITTED] TR08MR24.024


calculated in paragraph (b)(7) of this section:

[[Page 17137]]

[GRAPHIC] [TIFF OMITTED] TR08MR24.025

    (9) Calculate the oil flow rate, q<INF>o</INF> (cu ft/sec,) using 
the following equation with: the oil formation volume factor, Bo (bbl/
STBO), as calculated in paragraph (b)(5) of this section; and the 
estimated oil production rate at the well head, Qo (STBO/day):
[GRAPHIC] [TIFF OMITTED] TR08MR24.026

    (10) Calculate the critical pressure, P<INF>c</INF> (psia), and 
critical temperature, T<INF>c</INF> (R), using the equations below 
with: Gas gravity at standard conditions (pressure, P = 14.7 (psia), 
temperature, T = 60 (F)), [gamma] = 0.75; and where the mole fractions 
of nitrogen, carbon dioxide and hydrogen sulfide in the gas are 
XN<INF>2</INF> = 0.168225, XCO<INF>2</INF> = 0.013163, and 
XH<INF>2</INF>S = 0.013680, respectively:

Pc(psia) = 678 - 50 [middot] ([gamma]g -0.5) - 206.7 [middot] 
XN<INF>2</INF> + 440 [middot] XCO<INF>2</INF> + 606.7 [middot] 
XH<INF>2</INF>S

Tc(R) = 326 + 315.7 [middot] ([gamma]g - 0.5) - 240 [middot] 
XN<INF>2</INF> - 88.3 [middot] XCO<INF>2</INF> + 133.3 [middot] 
XH<INF>2</INF>S

    (11) Calculate reduced pressure, P<INF>r</INF>, and reduced 
temperature, T<INF>r</INF>, using the following equations with: the 
bottom hole pressure, PBH, as determined in paragraph (b)(1) of this 
section; the bottom hole temperature, TBH (F), as determined in 
paragraph (b)(2) of this section in the following equations:
[GRAPHIC] [TIFF OMITTED] TR08MR24.027

    (12)(i) Calculate the gas compressibility factor, Z, using the 
following equation with the reduced pressure, P<INF>r</INF>, calculated 
in paragraph (b)(11) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.028

    (ii) The values for A, B, C, D in the above equation, are 
calculated using the following equations with the reduced pressure, 
P<INF>r</INF>, and reduced temperature, T<INF>r</INF>, calculated in 
paragraph (b)(11) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.029


[[Page 17138]]


    (13) Calculate the gas formation volume factor,
    [GRAPHIC] [TIFF OMITTED] TR08MR24.030
    

using the bottom hole pressure, PBH (psia), as determined in paragraph 
(b)(1) of this section; and the bottom hole temperature, TBH (F), as 
determined in paragraph (b)(2) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.031

    (14) Calculate the gas flow rate,
    [GRAPHIC] [TIFF OMITTED] TR08MR24.032
    

using the following equation with: the value of gas formation volume 
factor,
[GRAPHIC] [TIFF OMITTED] TR08MR24.033


calculated in paragraph (b)(13) of this section; the estimated gas 
production rate, Qg (scf/day); the estimated oil production rate, Qo 
(STBO/day); and the dissolved GOR, Rs (scf/STBO), as calculated in 
paragraph (b)(4) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.034

    (15) Calculate the flow rate of water in the well, qw (cu ft/sec), 
using the following equation with the water production rate Qw (bbl/
day) at the well site:
[GRAPHIC] [TIFF OMITTED] TR08MR24.035

Sec.  Sec.  60.5433b  -60.5439b [Reserved]

  Table 1 to Subpart OOOOb of Part 60--Alternative Technology Periodic
  Screening Frequency at Well Sites, Centralized Production Facilities,
and Compressor Stations Subject to AVO Inspections With Quarterly OGI or
                        EPA Method 21 Monitoring
------------------------------------------------------------------------
                                             Minimum detection threshold
        Minimum screening frequency            of screening technology *
                                                       (kg/hr)
------------------------------------------------------------------------
Quarterly..................................                          <=1
Bimonthly..................................                          <=2
Bimonthly + Annual OGI.....................                         <=10
Monthly....................................                          <=5

[[Page 17139]]

 
Monthly + Annual OGI.......................                         <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%.


  Table 2 to Subpart OOOOb of Part 60--Alternative Technology Periodic
 Screening Frequency at Well Sites and Centralized Production Facilities
    Subject to AVO Inspections and/or Semiannual OGI or EPA Method 21
                               Monitoring
------------------------------------------------------------------------
                                             Minimum detection threshold
        Minimum screening frequency           of screening technology *
                                                       (kg/hr)
------------------------------------------------------------------------
Semiannual.................................                          <=1
Triannual..................................                          <=2
Triannual + Annual OGI.....................                         <=10
Quarterly..................................                          <=5
Quarterly + Annual OGI.....................                         <=15
Bimonthly..................................                         <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%


      Table 3 to Subpart OOOOb of Part 60--Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)
----------------------------------------------------------------------------------------------------------------
                                                              Sulfur feed rate (X), LT/D
   H2S content of acid gas (Y), %   ----------------------------------------------------------------------------
                                      2.0 < X < 5.0        5.0 < X < 15.0         15.0 < X < 300.0    X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50.............................            79.0     88.51X\0.0101\Y\0.0125\ or 99.9, whichever is smaller.
                                                    ------------------------------------------------------------
20 < Y < 50........................            79.0   88.51X\0.0101\Y\0.0125\ or 97.9, whichever is         97.9
                                                                         smaller
                                                    ------------------------------------------------------------
10 < Y < 20........................            79.0  88.51X\0.0101\Y\0.0125\ or                93.5         93.5
                                                      93.5, whichever is
                                                      smaller.
Y < 10.............................            79.0  79.0......................                79.0         79.0
----------------------------------------------------------------------------------------------------------------


          Table 4 to Subpart OOOOb of Part 60--Required Minimum SO2 Emission Reduction Efficiency (Zc)
----------------------------------------------------------------------------------------------------------------
                                                              Sulfur feed rate (X), LT/D
   H2S content of acid gas (Y), %   ----------------------------------------------------------------------------
                                      2.0 < X < 5.0        5.0 < X < 15.0         15.0 < X < 300.0    X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50.............................            74.0     85.35X\0.0144\Y\0.0128\ or 99.9, whichever is smaller.
                                                    ------------------------------------------------------------
20 < Y < 50........................            74.0   85.35X\0.0144\Y\0.0128\ or 97.5, whichever is         97.5
                                                                         smaller
                                                    ----------------------------
10 < Y < 20........................            74.0  85.35X\0.0144\Y\0.0128\ or                90.8         90.8
                                                      90.8, whichever is
                                                      smaller.
Y < 10.............................            74.0  74.0......................                74.0         74.0
----------------------------------------------------------------------------------------------------------------

X = The sulfur feed rate from the sweetening unit (i.e., the 
H<INF>2</INF>S in the acid gas), expressed as sulfur, Mg/D(LT/D), 
rounded to one decimal place.
Y = The sulfur content of the acid gas from the sweetening unit, 
expressed as mole percent H<INF>2</INF>S (dry basis) rounded to one 
decimal place.
Z = The minimum required sulfur dioxide (SO<INF>2</INF>) emission 
reduction efficiency, expressed as percent carried to one decimal 
place. Z<INF>i</INF> refers to the reduction efficiency required at 
the initial performance test. Z<INF>c</INF> refers to the reduction 
efficiency required on a continuous basis after compliance with 
Z<INF>i</INF> has been demonstrated.

            Table 5 to Subpart OOOOb of Part 60--Applicability of General Provisions to Subpart OOOOb
----------------------------------------------------------------------------------------------------------------
    General provisions citation       Subject of citation     Applies to  subpart?            Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1........................  General applicability  Yes.....................
                                      of the General
                                      Provisions.
Sec.   60.2........................  Definitions..........  Yes.....................  Additional terms defined
                                                                                       in Sec.   60.5430b.
Sec.   60.3........................  Units and              Yes.....................
                                      abbreviations.
Sec.   60.4........................  Address..............  Yes.....................

[[Page 17140]]

 
Sec.   60.5........................  Determination of       Yes.....................
                                      construction or
                                      modification.
Sec.   60.6........................  Review of plans......  Yes.....................
Sec.   60.7........................  Notification and       Yes.....................  Except that Sec.   60.7
                                      record keeping.                                  only applies as specified
                                                                                       in Sec.  Sec.
                                                                                       60.5417b(c) and
                                                                                       60.5420b(a).
Sec.   60.8........................  Performance tests....  Yes.....................  Except that the format and
                                                                                       submittal of performance
                                                                                       test reports is described
                                                                                       in Sec.   60.5420b(b) and
                                                                                       (d). Performance testing
                                                                                       is required for control
                                                                                       devices used on storage
                                                                                       vessels, centrifugal
                                                                                       compressors, process
                                                                                       controllers, and pumps
                                                                                       complying with Sec.
                                                                                       60.5393b(b)(1), except
                                                                                       that performance testing
                                                                                       is not required for a
                                                                                       control device used
                                                                                       solely on pump(s).
Sec.   60.9........................  Availability of        Yes.....................
                                      information.
Sec.   60.10.......................  State authority......  Yes.....................
Sec.   60.11.......................  Compliance with        No......................  Requirements are specified
                                      standards and                                    in subpart OOOOb.
                                      maintenance
                                      requirements.
Sec.   60.12.......................  Circumvention........  Yes.....................
Sec.   60.13.......................  Monitoring             Yes.....................
                                      requirements.
Sec.   60.14.......................  Modification.........  Yes.....................  To the extent any
                                                                                       provision in Sec.   60.14
                                                                                       conflicts with specific
                                                                                       provisions in subpart
                                                                                       OOOOb, it is superseded
                                                                                       by subpart OOOOb
                                                                                       provisions.
Sec.   60.15.......................  Reconstruction.......  Yes.....................  Except that Sec.
                                                                                       60.15(d) does not apply
                                                                                       to wells (i.e., well
                                                                                       completions, well liquids
                                                                                       unloading, associated gas
                                                                                       wells), process
                                                                                       controllers, pumps,
                                                                                       centrifugal compressors,
                                                                                       reciprocating
                                                                                       compressors, storage
                                                                                       vessels, or fugitive
                                                                                       emissions components
                                                                                       affected facilities.
Sec.   60.16.......................  Priority list........  Yes.....................
Sec.   60.17.......................  Incorporations by      Yes.....................
                                      reference.
Sec.   60.18.......................  General control        Yes.....................
                                      device and work
                                      practice
                                      requirements.
Sec.   60.19.......................  General notification   Yes.....................
                                      and reporting
                                      requirement.
----------------------------------------------------------------------------------------------------------------


0
33. Add subpart OOOOc to part 60 to read as follows:

Subpart OOOOc--Emissions Guidelines for Greenhouse Gas Emissions 
From Existing Crude Oil and Natural Gas Facilities

Introduction

60.5360c What is the purpose of this subpart?
60.5361c Which pollutants are regulated by this subpart?
60.5362c Am I affected by this subpart?
60.5363c What must I include in my state or Tribal plan?
60.5364c How do I apply to use my state standards as part of my 
state or Tribal plan submission?
60.5365c How do I apply for a less stringent standard taking into 
consideration the remaining useful life of a designated facility and 
other factors?
60.5366c [Reserved]
60.5367c Is there an approval process for my state or Tribal plan?
60.5368c What if my state or Tribal plan is not approvable?
60.5369c Is there an approval process for a negative declaration 
letter?
60.5370c What compliance schedule must I include in my state or 
Tribal plan?
60.5371c What requirements apply to revisions to my state or Tribal 
plan?
60.5372c In lieu of a state or Tribal plan submittal, are there 
other acceptable option(s) for a state to meet its Clean Air Act 
section 111(d) obligations?
60.5373c What authorities will not be delegated to state, local, or 
Tribal agencies?
60.5374c Does this subpart directly affect designated facility 
owners and operators in my state?

Applicability of State or Tribal Plans

60.5375c What designated facilities must I address in my state or 
Tribal plan?

Use of Model Rule

60.5376c What is the ``model rule'' in this subpart?
60.5377c How does the model rule relate to the required elements of 
my state or Tribal plan?
60.5378c What are the principal components of the model rule?

Model Rule--Increments of Progress

60.5379c What are my requirements for meeting increments of progress 
and achieving final compliance?
60.5380c What if I do not meet the final control plan increment of 
progress compliance date?
60.5381c How do I comply with the increment of progress for 
submittal of a final compliance control plan?

Model Rule--Applicability

60.5385c What is the purpose of this subpart?
60.5386c Am I subject to this subpart?
60.5387c When must I comply with this subpart?

Model Rule--Emission and Work Practice Standards

60.5388c What standards apply to super-emitter events?
60.5390c What GHG standards apply to gas well liquids unloading 
operations at well designated facilities?
60.5391c What GHG standards apply to associated gas wells at well 
designated facilities?
60.5392c What GHG standards apply to centrifugal compressor 
designated facilities?
60.5393c What GHG standards apply to reciprocating compressor 
designated facilities?
60.5394c What GHG standards apply to process controller designated 
facilities?
60.5395c What GHG standards apply to pump designated facilities?
60.5396c What GHG standards apply to storage vessel designated 
facilities?
60.5397c What GHG standards apply to fugitive emissions components 
designated facilities?
60.5398c What alternative GHG standards apply to fugitive emissions 
components designated facilities and what monitoring and inspection 
requirements apply to covers and closed vent systems when using an 
alternative technology?
60.5400c What GHG standards apply to process unit equipment 
designated facilities?
60.5401c What are the alternative GHG standards for process unit 
equipment designated facilities?

[[Page 17141]]

60.5402c What are the exceptions to the GHG standards for process 
unit equipment designated facilities?

Model Rule--Test Methods and Performance Testing

60.5405c What test methods and procedures must I use for my 
centrifugal compressor and reciprocating compressor designated 
facilities?
60.5406c What test methods and procedures must I use for my process 
unit equipment designated facilities?

Model Rule--Initial Compliance Requirements

60.5410c How do I demonstrate initial compliance with the standards 
for each of my designated facilities?
60.5411c What additional requirements must I meet to determine 
initial compliance for my covers and closed vent systems?
60.5412c What additional requirements must I meet for determining 
initial compliance of my control devices?
60.5413c What are the performance testing procedures for control 
devices?

Model Rule--Continuous Compliance Requirements

60.5415c How do I demonstrate continuous compliance with the 
standards for each of my designated facilities?
60.5416c What are the initial and continuous cover and closed vent 
system inspection and monitoring requirements?
60.5417c What are the continuous monitoring requirements for my 
control devices?

Model Rule--Recordkeeping and Reporting

60.5420c What are my notification, reporting, and recordkeeping 
requirements?
60.5421c What are my additional recordkeeping requirements for 
process unit equipment designated facilities?
60.5422c What are my additional reporting requirements for process 
unit equipment designated facilities?
60.5424c What are my additional recordkeeping and reporting 
requirements if I comply with the alternative GHG standards for 
fugitive emissions components designated facilities and covers and 
closed vent systems?
60.5425c What parts of the General Provisions apply to me?

Model Rule--Definitions

60.5430c What definitions apply to this subpart?
60.5431c-60.5439c [Reserved]
Table 1 to Subpart OOOOc of Part 60--Designated Facility Presumptive 
Standards and Regulated Entity Compliance Dates
Table 2 to Subpart OOOOc of Part 60--Alternative Technology Periodic 
Screening Frequency at Well Sites, Centralized Production 
Facilities, and Compressor Stations Subject to AVO Inspections With 
Quarterly OGI or EPA Method 21 Monitoring
Table 3 to Subpart OOOOc of Part 60--Alternative Technology Periodic 
Screening Frequency at Well Sites and Centralized Production 
Facilities Subject to AVO Inspections and/or Semiannual OGI or EPA 
Method 21 Monitoring
Table 4 to Subpart OOOOc of Part 60--Applicability of General 
Provisions to Subpart OOOOc

Introduction


Sec.  60.5360c  What is the purpose of this subpart?

    This subpart establishes emission guidelines and compliance 
schedules for the control of greenhouse gas (GHG) emissions from 
designated facilities in the crude oil and natural gas source category 
as defined in the Model Rule at Sec.  60.5430c, in accordance with 
section 111(d) of the Clean Air Act and subpart Ba of this part. The 
designated facilities, standards section reference and compliance dates 
are listed in table 1 to this subpart. To the extent any requirement of 
this subpart is inconsistent with the requirements of subpart A or Ba 
of this part, the requirements of this subpart will apply.


Sec.  60.5361c  Which pollutants are regulated by this subpart?

    (a) Scope. The pollutants regulated by this subpart are greenhouse 
gases (GHG). The greenhouse gas standards in this subpart are in the 
form of a limitation on emissions of methane from designated facilities 
in the crude oil and natural gas source category that commenced 
construction, modification, or reconstruction on or before December 6, 
2022.
    (b) PSD and title V Thresholds for Greenhouse Gases. (1) For the 
purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions 
from facilities, the ``pollutant that is subject to any standard 
promulgated under section 111 of the Act'' shall be considered to be 
the pollutant that otherwise is subject to regulation under the Act as 
defined in 40 CFR 51.166(b)(48) and in any State Implementation Plan 
(SIP) approved by the EPA that is interpreted to incorporate, or 
specifically incorporates, 40 CFR 51.166(b)(48).
    (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to 
GHG emissions from facilities regulated in the plan, the ``pollutant 
that is subject to any standard promulgated under section 111 of the 
Act'' shall be considered to be the pollutant that otherwise is subject 
to regulation under the Act as defined in 40 CFR 52.21(b)(49).
    (3) For the purposes of 40 CFR 70.2, with respect to GHG emissions 
from facilities regulated in the plan, the ``pollutant that is subject 
to any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 70.2.
    (4) For the purposes of 40 CFR 71.2, with respect to GHG emissions 
from facilities regulated in the plan, the ``pollutant that is subject 
to any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 71.2 40 CFR.


Sec.  60.5362c  Am I affected by this subpart?

    (a) If you are the Administrator of an air pollution control agency 
in a state or United States protectorate with one or more designated 
facilities that commenced construction, modification, or reconstruction 
on or before December 6, 2022, you must submit a state or Tribal plan 
to the U.S. Environmental Protection Agency (EPA) that implements the 
emission guidelines contained in this subpart. The submission of such 
plan shall be made in electronic format according to subpart Ba of this 
part.
    (b) If you are the Administrator of an air pollution control agency 
in a state or United States protectorate with no designated facilities 
for which construction commenced on or before December 6, 2022, you 
must submit a negative declaration letter in place of the state or 
Tribal plan. The submission of such negative declaration letter shall 
be made in electronic format according to subpart Ba of this part.
    (c) You must submit the state or Tribal plan or negative 
declaration letter to EPA by the date March 9, 2026.


Sec.  60.5363c  What must I include in my state or Tribal plan?

    (a) You must include the ten items described in paragraphs (a)(1) 
through (10) of this section in your state or Tribal plan.
    (1) Inventory of designated facilities. For purposes of this 
subpart, Sec.  60.25a(a) does not apply.
    (2) Inventory of emissions from designated facilities in your 
state. For purposes of this subpart, Sec.  60.25a(a) does not apply.
    (3) Compliance schedules for each designated facility or logical 
grouping of designated facilities.
    (4) Standards of performance for designated facilities that are at 
least as stringent as the emission guidelines contained in this 
subpart, unless otherwise provided for under Sec.  60.5365c. Standards 
for performance for designated facilities must apply at all times, 
including periods of startup, shutdown, and malfunction.

[[Page 17142]]

    (5) Performance testing, monitoring, recordkeeping, and reporting 
requirements.
    (6) Documentation of meaningful engagement on such plan or plan 
revisions as specified in Sec.  60.23a(i).
    (7) Certification that the required hearing on the state or Tribal 
plan was held, a list of witnesses and their organizational 
affiliations, if any, appearing at the hearing, and a brief written 
summary of each presentation or written submission as specified in 
Sec.  60.23a(c) through (e).
    (8) Provision for state progress reports to EPA.
    (9) Identification of enforceable state mechanisms that you 
selected for implementing the emission guidelines of this subpart.
    (10) Demonstration of your state's legal authority to carry out the 
Clean Air Act section 111(d) state or Tribal plan.
    (b) Unless superseded by this subpart, you must follow the 
requirements of subpart Ba of this part (Adoption and Submittal of 
State Plans for Designated Facilities) in your state or Tribal plan.


Sec.  60.5364c  How do I apply to use my state standards as part of my 
state or Tribal plan submission?

    In order for you to apply to use your state standards as part of 
your state or Tribal plan submission your state requirements for 
designated facilities must meet the standards of performance criteria 
specified in paragraph (a) of this section and you must provide the 
supporting documentation that you met those criteria as specified in 
paragraph (b) of this section.
    (a) You must demonstrate that the state standards of performance 
established for a designated facility in your state or Tribal plan meet 
the equivalency criteria specified in paragraphs (a)(1) through (6) of 
this section when compared to the designated facility presumptive 
standards specified in EG OOOOc.
    (1) Designated facility,
    (2) Designated pollutant,
    (3) Standard type/format of standard,
    (4) Emission reductions (considering applicability thresholds and 
exemptions) unless relying on Sec.  60.5365c,
    (5) Compliance determination method, and
    (6) Ongoing compliance assurance requirements (e.g., monitoring, 
recordkeeping and reporting requirements).
    (b) You must provide the supporting documentation that you met the 
equivalency criteria specified in paragraph (a) of this section as 
specified in paragraphs (b)(1) through (3) of this section.
    (1) Your state or Tribal plan should identify the designated 
facility requirements of your state program that you are submitting for 
approval to become federally enforceable requirements under the plan.
    (2) You must include a detailed explanation and analysis of how the 
relied upon state standards are at least as stringent as the 
requirements of the final EG based on each of the criteria specified in 
paragraph (a) of this section, or comply with Sec.  60.5365c for 
paragraph (a)(4) of this section.
    (3) You must include a copy of the actual state law/regulation or 
document submitted for approval and incorporation into the state or 
Tribal plan.


Sec.  60.5365c  How do I apply for a less stringent standard taking 
into consideration the remaining useful life of a designated facility 
and other factors?

    You may apply a standard of performance to a designated facility 
that is less stringent than otherwise required by the emission 
guidelines, provided you meet the requirements specified in Sec.  
60.24a.


Sec.  60.5366c  [Reserved.]


Sec.  60.5367c  Is there an approval process for my state or Tribal 
plan?

    Yes. The EPA will review your state or Tribal plan according to 
Sec.  60.27a.
    (a) The EPA will determine the completeness of your plan submission 
according Sec.  60.27a(g).
    (b) The EPA will act on your plan submission according to Sec.  
60.27a.


Sec.  60.5368c  What if my state or Tribal plan is not approvable?

    If you do not submit a state or Tribal plan (or a negative 
declaration letter) by March 9, 2026, or if EPA disapproves your state 
plan, EPA will develop a Federal plan according to Sec.  60.27a(c) 
through (f) to implement the emission guidelines contained in this 
subpart.


Sec.  60.5369c  Is there an approval process for a negative declaration 
letter?

    No. The EPA has no formal review process for negative declaration 
letters. Once your negative declaration letter has been received, the 
EPA will place a copy in the public docket and publish a notice in the 
Federal Register. If, at a later date, a designated facility for which 
construction commenced on or before December 6, 2022, is found in your 
state, that designated facility must be subject to a state, Tribal, or 
Federal plan in accordance with the requirements of this subpart and 
subpart Ba.


Sec.  60.5370c  What compliance schedule must I include in my state or 
Tribal plan?

    (a) For designated facilities that commenced construction, 
modification or reconstruction on or before December 6, 2022, your 
state or Tribal plan must include compliance schedules that require 
designated facilities to achieve final compliance as expeditiously as 
practicable after approval of the state or Tribal plan but not later 
than the dates specified in Sec.  60.5360c of this subpart, as 
applicable to each designated facility.
    (b) The plan must include legally enforceable increments of 
progress to achieve compliance for each designated facility or category 
of facilities, as specified in Sec. Sec.  60.5380c through 60.5382c.


Sec.  60.5371c  What requirements apply to revisions to my state or 
Tribal plan?

    (a) Any significant revision to a state or Tribal plan shall be 
adopted and submitted as specified in Sec.  60.28a.
    (b) A revision of a plan, or any portion thereof, shall not be 
considered part of an applicable plan until approved by the 
Administrator in accordance with this subpart and subpart Ba of this 
part.


Sec.  60.5372c  In lieu of a state or Tribal plan submittal, are there 
other acceptable option(s) for a state to meet its Clean Air Act 
section 111(d) obligations?

    Yes, a state may meet its Clean Air Act section 111(d) obligations 
by submitting an acceptable written request for delegation of an 
applicable Federal plan that meets the requirements of this section. 
This is the only other option for a state to meet its section 111(d) 
obligations.
    (a) An acceptable Federal plan delegation request must include the 
following:
    (1) A demonstration of adequate resources and legal authority to 
administer and enforce the Federal plan.
    (2) The items under Sec.  60.5363c(a)(1), (a)(2), and (a)(8) of 
this subpart.
    (3) Certification that the hearing on the state delegation request, 
similar to the hearing for a state or Tribal plan submittal, was held, 
a list of witnesses and their organizational affiliations, if any, 
appearing at the hearing, and a brief written summary of each 
presentation or written submission.
    (4) A commitment to enter into a Memorandum of Agreement with the 
Regional Administrator that sets forth the terms, conditions, and 
effective date of the delegation and that serves as the mechanism for 
the transfer of authority. Additional guidance and information is given 
in EPA's Delegation Manual, Item 7-139, Implementation and Enforcement 
of 111(d)(2) and 111(d)/(2)/129 (b)(3) Federal plans.

[[Page 17143]]

    (b) A state with an already approved oil and natural gas designated 
facility Clean Air Act section 111(d) state or Tribal plan is not 
precluded from receiving the EPA's approval of a delegation request for 
any revised Federal plan, provided the requirements of paragraph (a) of 
this section are met, and at the time of the delegation request, the 
state also requests withdrawal of the EPA's previous state or Tribal 
plan approval.
    (c) A state's Clean Air Act section 111(d) obligations are separate 
from its obligations under title V of the Clean Air Act.


Sec.  60.5373c  What authorities will not be delegated to state, local, 
or Tribal agencies?

    The authorities that will not be delegated to state, local, or 
Tribal agencies are specified in paragraphs (a) through (h) of this 
section.
    (a) Approval of alternatives to the emission limits and standards 
in tables 1, 2, and 3 to this subpart and operating limits established 
under Sec.  60.5412c, Sec.  60.5415c, or Sec.  60.5417c.
    (b) Approval of major alternatives to test methods.
    (c) Approval of major alternatives to monitoring.
    (d) Approval of major alternatives to recordkeeping and reporting.
    (e) Approval of an alternative to any electronic reporting required 
by this subpart.
    (f) [Reserved.]
    (g) [Reserved.]
    (h) Performance test and data reduction waivers under Sec.  
60.8(b).


Sec.  60.5374c  Does this subpart directly affect designated facility 
owners and operators in my state?

    (a) No. This subpart does not directly affect designated facility 
owners and operators in your state. However, designated facility owners 
and operators must comply with the state or Tribal plan you develop to 
implement the emission guidelines contained in this subpart. States may 
choose to incorporate the model rule text directly in their state or 
Tribal plan.
    (b) If you do not submit a plan to implement and enforce the 
guidelines contained in this subpart by the date 24 months after 
promulgation of this subpart, or if EPA disapproves your plan, the EPA 
will implement and enforce a Federal plan, as provided in Sec.  
60.5367c of this subpart, to ensure that each designated facility 
within your state that commenced construction, modification or 
reconstruction on or before December 6, 2022, reaches compliance with 
all the provisions of this subpart by the dates specified in Sec.  
60.5360c of this subpart.

Applicability of State or Tribal Plans


Sec.  60.5375c  What designated facilities must I address in my state 
or Tribal plan?

    (a) Your state or Tribal plan must address designated facilities 
that meet all three criteria described in paragraphs (a)(1) through (3) 
of this section.
    (1) Designated facilities in your state that commenced 
construction, modification, or reconstruction on or before December 6, 
2022.
    (2) Designated facilities that are listed in table 1 to this 
subpart.
    (3) Designated facilities not exempt under Sec.  60.14c.
    (b) If the owner or operator of a designated facility makes changes 
that meet the definition of modification after December 6, 2022, the 
designated facility becomes subject to subpart OOOOb of this part, and 
the state or Tribal plan no longer applies to that facility.
    (c) If the owner or operator of a designated facility makes 
physical or operational changes to a designated facility for which 
construction commenced on or before September 9, 2024, primarily to 
comply with your state or Tribal plan, subpart OOOOb of this part, does 
not apply to that designated facility. Such changes do not qualify as 
modifications under subpart OOOOb of this part.

Use of Model Rule


Sec.  60.5376c  What is the ``model rule'' in this subpart?

    (a) The model rule is the portion of these emission guidelines 
(Sec. Sec.  60.5385c through 60.5430c of this subpart) that includes 
the presumptive standards for designated facilities as well as 
associated measures to assure compliance including monitoring, 
recordkeeping, and reporting. The model rule is organized in regulation 
format. You must develop a state or Tribal plan that is at least as 
protective as the model rule, or comply with Sec.  60.5365c. You may 
use the model rule language as part of your state or Tribal plan. 
Alternative language may be used in your state or Tribal plan if you 
demonstrate that the alternative language is at least as protective as 
the model rule contained in this subpart, or comply with Sec.  
60.5365c.
    (b) In the model rule of Sec. Sec.  60.5385c through 60.5430c, 
``Administrator'' has the meaning specified in Sec.  60.2.


Sec.  60.5377c  How does the model rule relate to the required elements 
of my state or Tribal plan?

    You may use the model rule to satisfy the state or Tribal plan 
requirements specified in Sec.  60.5363c(a)(3) through (a)(5).


Sec.  60.5378c  What are the principal components of the model rule?

    The model rule contains the nine major components listed in 
paragraphs (a) through (i) of this section.
    (a) Increments of progress toward compliance.
    (b) Operator training and qualification.
    (c) Emission limits, emission standards, and operating limits.
    (d) Initial compliance requirements.
    (e) Continuous compliance requirements.
    (f) Performance testing, monitoring, and calibration requirements.
    (g) Recordkeeping and reporting.
    (h) Definitions.
    (i) Tables.

Model Rule--Increments of Progress


Sec.  60.5379c  What are my requirements for meeting increments of 
progress and achieving final compliance?

    You must meet one increment of progress as specified in paragraph 
(a) of this section and you must submit the Notification of Compliance 
report as specified in paragraph (b) of this section.
    (a) Submit a final compliance control plan on or before 28 months 
after the state plan submittal deadline specified in Sec.  60.5362c(c).
    (b) Submit a Notification of Compliance report on or before 60 days 
after the state plan compliance date as specified in Sec.  60.5420c.


Sec.  60.5380c  What if I do not meet the final control plan increment 
of progress compliance date?

    If you fail to meet the final compliance control plan increment of 
progress report compliance date, you must submit a notification to the 
Administrator postmarked within 10 business days after the required 
submittal date for that increment of progress. You must inform the 
Administrator that you did not meet the increment, and you must 
continue to submit reports each subsequent calendar month until the 
increment of progress is met.


Sec.  60.5381c  How do I comply with the increment of progress for 
submittal of a final compliance control plan?

    For your final compliance control plan increment of progress 
report, you must satisfy the requirements specified

[[Page 17144]]

in paragraphs (a) through (c) of this section.
    (a) Your final control plan must include the information specified 
paragraphs (a)(1) and (2) of this section.
    (1) A description of the designated facilities covered under your 
plan.
    (2) The emissions control methods that you plan to implement for 
each designated facility covered under your plan.
    (b) A company is allowed to submit one plan that covers all of the 
company's designated facilities in a state in lieu of submitting a plan 
for each designated facility.
    (c) Maintain an onsite copy of the final control plan.

Model Rule--Applicability


Sec.  60.5385c   What is the purpose of this subpart?

    (a) Scope. This subpart establishes emission standards and 
compliance schedules for the control of the pollutant greenhouse gases 
(GHG). The greenhouse gas standard in this subpart is in the form of a 
limitation on emissions of methane from designated facilities in the 
crude oil and natural gas source category that commence construction, 
modification, or reconstruction on or before December 6, 2022.
    (b) Prevention of Significant Deterioration (PSD) and title V 
thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR 
51.166(b)(49)(ii), with respect to GHG emissions from designated 
facilities, the ``pollutant that is subject to the standard promulgated 
under section 111 of the Act'' shall be considered the pollutant that 
otherwise is subject to regulation under the Act as defined in 40 CFR 
51.166(b)(48) and in any State Implementation Plan (SIP) approved by 
the EPA that is interpreted to incorporate, or specifically 
incorporates, 40 CFR 51.166(b)(48).
    (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to 
GHG emissions from designated facilities, the ``pollutant that is 
subject to the standard promulgated under section 111 of the Act'' 
shall be considered the pollutant that otherwise is subject to 
regulation under the Clean Air Act as defined in 40 CFR 52.21(b)(49).
    (3) For the purposes of 40 CFR 70.2, with respect to GHG emissions 
from designated facilities, the ``pollutant that is subject to any 
standard promulgated under section 111 of the Act'' shall be considered 
the pollutant that otherwise is ``subject to regulation'' as defined in 
40 CFR 70.2.
    (4) For the purposes of 40 CFR 71.2, with respect to GHG emissions 
from designated facilities, the ``pollutant that is subject to any 
standard promulgated under section 111 of the Act'' shall be considered 
the pollutant that otherwise is ``subject to regulation'' as defined in 
40 CFR 71.2.
    (c) Exemption. You are exempt from the obligation to obtain a 
permit under 40 CFR part 70 or 40 CFR part 71, provided you are not 
otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 
CFR 71.3(a). Notwithstanding the previous sentence, you must continue 
to comply with the provisions of this subpart.


Sec.  60.5386c   Am I subject to this subpart?

    You are subject to the applicable provisions of this subpart if you 
are the owner or operator of one or more of the onshore designated 
facilities listed in paragraphs (a) through (h) of this section, that 
is located within the Crude Oil and Natural Gas source category, as 
defined in Sec.  60.5430c, for which you commence construction, 
modification, or reconstruction on or before December 6, 2022. 
Facilities located inside and including the Local Distribution Company 
(LDC) custody transfer station are not subject to this subpart.
    (a) Each well designated facility, which is a single well drilled 
for the purpose of producing oil or natural gas.
    (b) Each centrifugal compressor designated facility, which is a 
single centrifugal compressor. A centrifugal compressor located at a 
well site is not a designated facility under this subpart. A 
centrifugal compressor located at a centralized production facility is 
a designated facility under this subpart.
    (c) Each reciprocating compressor designated facility, 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.
    (d) Each process controller designated facility, which is the 
collection of natural gas-driven process controllers at a well site, 
centralized production facility, onshore natural gas processing plant, 
or a compressor station. Natural gas-driven process controllers that 
function as emergency shutdown devices and process controllers that are 
not driven by natural gas are exempt from the designated facility.
    (e)(1) Each storage vessel designated facility, which is a tank 
battery that has the potential for methane emissions equal to or 
greater than 20 tpy as specified in paragraph (e)(2) of this section. A 
tank battery with the potential for methane emissions below 20 tpy is 
not a storage vessel designated facility provided the owner or operator 
keeps records of the potential for emissions calculation for the life 
of the storage vessel or until such time the tank battery becomes a 
storage vessel designated facility because the potential for methane 
emissions meets or exceeds 20 tpy.
    (2) The potential for methane emissions must be calculated as the 
cumulative emissions from all storage vessels within the tank battery 
as specified by the applicable requirements in paragraphs (e)(2)(i) 
through (iii) of this section. The determination may take into account 
requirements under a legally and practicably enforceable limit in an 
operating permit or other requirement established under a Federal, 
state, local, or Tribal authority.
    (i) For purposes of determining the applicability of a storage 
vessel tank battery as a designated facility, a legally and practicably 
enforceable limit must include the elements provided in paragraphs 
(e)(2)(i)(A) through (F) of this section.
    (A) A quantitative production limit and quantitative operational 
limit(s) for the equipment, or quantitative operational limits for the 
equipment;
    (B) An averaging time period for the production limit in 
(e)(2)(i)(A), if a production-based limit is used, that is equal to or 
less than 30 days;
    (C) Established parametric limits for the production and/or 
operational limit(s) in (e)(1)(i)(A), and where a control device is 
used to achieve an operational limit, an initial compliance 
demonstration (i.e., performance test) for the control device that 
establishes the parametric limits;
    (D) Ongoing monitoring of the parametric limits in (e)(2)(i)(C) 
that demonstrates continuous compliance with the production and/or 
operational limit(s) in (e)(2)(i)(A);
    (E) Recordkeeping by the owner or operator that demonstrates 
continuous compliance with the limit(s) in (e)(2)(i)(A) through (D); 
and
    (F) Periodic reporting that demonstrates continuous compliance.
    (ii) For each tank battery located at a well site or centralized 
production facility, you must determine the potential for methane 
emissions within 60 days after the effective date of the approved state 
or Tribal plan, except as provided in paragraph (e)(4)(iv) of this 
section. The potential for methane emissions must be calculated using a 
generally accepted model or calculation methodology that accounts for 
flashing, working, and breathing losses, based on the maximum average 
daily throughput

[[Page 17145]]

to the tank battery determined for a 30-day period of production.
    (iii) For each tank battery not located at a well site or 
centralized production facility, including each tank battery located at 
a compressor station or onshore natural gas processing plant, you must 
determine the potential for methane emissions within 60 days after the 
effective date of the approved state or Tribal plan, using either 
method described in paragraph (e)(2)(iii)(A) or (B) of this section.
    (A) Determine the potential for methane emissions using a generally 
accepted model or calculation methodology that accounts for flashing, 
working, and breathing losses, and based on the throughput to the tank 
battery established in a legally and practicably enforceable limit in 
an operating permit or other requirement established under a Federal, 
state, local, or Tribal authority; or
    (B) Determine the potential for methane emissions using a generally 
accepted model or calculation methodology that accounts for flashing, 
working and breathing losses, based on projected maximum average daily 
throughput. Maximum average daily throughput is determined using a 
generally accepted engineering model (e.g., volumetric condensate rates 
from the tank battery based on the maximum gas throughput capacity of 
each producing facility) to project the maximum average daily 
throughput for the tank battery.
    (3) A storage vessel designated facility that subsequently has its 
potential for methane emissions decrease to less than 20 tpy shall 
remain a designated facility under this subpart.
    (4) For storage vessels not subject to a legally and practicably 
enforceable limit in an operating permit or other requirement 
established under Federal, state, local, or Tribal authority, any vapor 
from the storage vessel that is recovered and routed to a process 
through a vapor recovery unit designed and operated as specified in 
this section is not required to be included in the determination of 
potential for methane emissions for purposes of determining designated 
facility status, provided you comply with the requirements of 
paragraphs (e)(4)(i) through (iv) of this section.
    (i) You meet the cover requirements specified in Sec.  60.5411c(b).
    (ii) You meet the closed vent system requirements specified in 
Sec.  60.5411c(a)(2) through (4) and (c).
    (iii) You must maintain records that document compliance with 
paragraphs (e)(4)(i) and (ii) of this section.
    (iv) In the event of removal of apparatus that recovers and routes 
vapor to a process, or operation that is inconsistent with the 
conditions specified in paragraphs (e)(4)(i) and (ii) of this section, 
you must determine the storage vessel's potential for methane emissions 
according to this section within 30 days of such removal or operation.
    (5) The requirements of this paragraph (e)(5) apply to each storage 
vessel designated facility immediately upon return to service. A 
storage vessel designated facility or portion of a storage vessel 
designated facility that is reconnected to the original source of 
liquids remains a storage vessel designated facility subject to the 
same requirements that applied before being removed from service. Any 
storage vessel that is used to replace a storage vessel designated 
facility or portion of a storage vessel designated facility, or used to 
expand a storage vessel designated facility assumes the designated 
facility status of the storage vessel designated facility being 
replaced or expanded.
    (6) A storage vessel with a capacity greater than 100,000 gallons 
used to recycle water that has been passed through two stage separation 
is not a storage vessel designated facility.
    (f) Each process unit equipment designated facility, which is the 
group of all equipment within a process unit at an onshore natural gas 
processing plant is a designated facility. Equipment associated with a 
compressor station, dehydration unit, sweetening unit, underground 
storage vessel, field gas gathering system, or liquefied natural gas 
unit is covered by Sec. Sec.  60.5400c, 60.5401c, 60.5402c, 60.5421c, 
and 60.5422c if it is located at an onshore natural gas processing 
plant. Equipment not located at the onshore natural gas processing 
plant site is exempt from the provisions of Sec. Sec.  60.5400c, 
60.5401c, 60.5402c, 60.5421c, and 60.5422c.
    (g) Each pump designated facility, which is the collection of 
natural gas-driven diaphragm and piston pumps at a well site, 
centralized production facility, onshore natural gas processing plant, 
or a compressor station. Pumps that are not driven by natural gas and 
that are not in operation 90 days or more per calendar year are not 
included in the pump designated facility.
    (h) Each fugitive emissions components designated facility, which 
is the collection of fugitive emissions components at a well site, 
centralized production facility, or a compressor station.


Sec.  60.5387c   When must I comply with this subpart?

    Table 1 of this subpart specifies the final compliance date.

Model Rule--Emission and Work Practice Standards


Sec.  60.5388c   What standards apply to super-emitter events?

    This section applies to super-emitter events. For purposes of this 
section, a super-emitter event is defined as any emissions event that 
is located at an oil and natural gas facility (e.g., individual well 
site, centralized production facility, natural gas processing plant, or 
compressor station) and that is detected using remote detection methods 
and has a quantified emission rate of 100 kg/hr of methane or greater. 
Upon receiving a notification of a super emitter event issued by the 
EPA under Sec.  60.5371b(c) in subpart OOOOb of this part, owners or 
operators must take the actions listed in paragraphs (a) and (b) of 
this section. Within 5 calendar days of receiving a notification from 
the EPA of a super-emitter event, the owner or operator of an oil and 
natural gas facility (e.g., a well site, centralized production 
facility, natural gas processing plant, or compressor station) must 
initiate a super-emitter event investigation.
    (a) Identification of super-emitter events. (1) If you do not own 
or operate an oil and natural gas facility within 50 meters from the 
latitude and longitude provided in the notification subject to the 
regulation under this subpart, report this result to the EPA under 
paragraph (e) of this section. Your super-emitter event investigation 
is deemed complete under this subpart.
    (2) If you own or operate an oil and natural gas facility within 50 
meters from the latitude and longitude provided in the notification, 
and there is a designated facility or associated equipment subject to 
this subpart onsite, you must investigate to determine the source of 
the super-emitter event in accordance with this paragraph (a) and 
report the results in accordance with paragraph (b) of this section.
    (3) The investigation required by paragraph (a)(2) of this section 
may include but is not limited to the actions specified below in 
paragraphs (a)(2)(i) through (v) of this section.
    (i) Review any maintenance activities (e.g., liquids unloading) or 
process activities from the designated facilities subject to regulation 
under this subpart, starting from the date of detection of the super-
emitter event as identified in the notification, until the date of 
investigation, to determine if the activities indicate any potential

[[Page 17146]]

source(s) of the super-emitter event emissions.
    (ii) Review all monitoring data from control devices (e.g., flares) 
from the designated facilities subject to regulation under this subpart 
from the initial date of detection of the super-emitter event as 
identified in the notification, until the date of receiving the 
notification from the EPA to identify malfunctions of control devices 
or periods when the control devices were not in compliance with 
applicable requirements and that indicate a potential source of the 
super-emitter event emissions.
    (iii) If you conducted a fugitive emissions survey or periodic 
screening event in accordance with Sec.  60.5397c or Sec.  60.5398c(b) 
between the initial date of detection of the super-emitter event as 
identified in the notification and the date the notification from the 
EPA was received, review the results of the survey to identify any 
potential source(s) of the super-emitter event emissions.
    (iv) If you use conduct continuous monitoring with advanced methane 
detection technology in accordance with Sec.  60.5398c(c), review the 
monitoring data collected on or after the initial date of detection of 
the super-emitter event as identified in the notification, until the 
date of receiving the notification from the EPA.
    (v) Screen the entire well site, centralized production facility, 
or compressor station with OGI, Method 21 of appendix A-7 to this part, 
or an alternative test method(s) approved per Sec.  60.5398c(d), to 
determine if a super-emitter event is present.
    (4) If the source of the super-emitter event was found to be from 
fugitive emission components at a well site, centralized production 
facility, or compressor station subject to this subpart, you must 
comply with the repair requirements under Sec.  60.5397c and the 
associated recordkeeping and reporting requirements under Sec.  
60.5420c(b)(8) and Sec.  60.5420c(c)(13).
    (b) Super-emitter event report. You must submit the results of the 
super-emitter event investigation conducted under paragraph (a) of this 
section to the EPA in accordance with paragraph (b)(1) of this section. 
If the super-emitter event (i.e., emission at 100 kg/hr of methane or 
more) is ongoing at the time of the initial report, submit the 
additional information in accordance with paragraph (b)(2) of this 
section. You must attest to the information included in the report as 
specified in paragraph (b)(3) of this section.
    (1) Within 15 days of receiving a notification from the EPA under 
Sec.  60.5371b(c), you must submit a report of the super-emitter event 
investigation conducted under paragraph (a) of this section through the 
Super-Emitter Program Portal, at www.epa.gov/super-emitter. You must 
include the applicable information in paragraphs (b)(1)(i) through 
(viii) of this section in the report. If you have identified a 
demonstrable error in the notification, the report may include a 
statement of the demonstrable error.
    (i) Notification Report ID of the super-emitter event notification.
    (ii) Identification of whether you are the owner or operator of an 
oil and natural gas facility that is located within 50 meters from the 
latitude and longitude provided in the EPA notification. If you do not 
own or operate an oil and natural gas facility within 50 meters from 
the latitude and longitude provided in the EPA notification, you are 
not required to report the information in paragraphs (b)(1)(iii) 
through (viii) of this section.
    (iii) General identification information for the facility, 
including, facility name, the physical address, applicable ID Number 
(e.g., EPA ID Number, API Well ID Number), the owner or operator or 
responsible official (where applicable) and their email address.
    (iv) Identification of whether there is a designated facility or 
associated equipment subject to regulation under this subpart at this 
oil and natural gas facility.
    (v) Indication of whether you were able to identify the source of 
the super-emitter event. If you indicate you were unable to identify 
the source of the super-emitter event, you must certify that all 
applicable investigations specified in paragraphs (a)(3)(i) through (v) 
of this section have been conducted for all designated facilities and 
associated equipment subject to regulation under this subpart that are 
at this oil and natural gas facility, and you have determined that the 
designated facilities and associated equipment are not the source of 
the super-emitter event. If you indicate that you were not able to 
identify the source of the super-emitter event, you are not required to 
report the information in paragraphs (b)(1)(vi) through (viii) of this 
section.
    (vi) The source(s) of the super-emitter event.
    (vii) Identification of whether the source of the super-emitter 
event is a designated facility or associated equipment subject to 
regulation under of this subpart. If the source of the super-emitter 
event is a designated facility or associated equipment subject to 
regulation under this subpart, identify the applicable regulation(s) 
under this subpart.
    (viii) Indication of whether the super-emitter event is ongoing at 
the time of the initial report submittal (i.e., emission at 100 kg/hr 
of methane or more).
    (A) If the super-emitter event is not ongoing at the time of the 
initial report submittal, provide the actual (or if not known, 
estimated) date and time the super-emitter event ended.
    (B) If the super-emitter event is ongoing at the time of the 
initial report submittal, provide a short narrative of your plan to end 
the super-emitter event, including the targeted end date for the 
efforts to be completed and the super-emitter event ended.
    (2) If the super-emitter event is ongoing at the time of the 
initial report submittal, within 5 business days of the date the super-
emitter event ends you must update your initial report through the 
Super-Emitter Program Portal to provide the end date and time of the 
super-emitter event.
    (3) You must sign the following attestation when submitting data 
into the Super-Emitter Program Portal: ``I certify that the information 
provided in this report regarding the specified super-emitter event was 
prepared under my direction or supervision. I further certify that the 
investigations were conducted, and this report was prepared pursuant to 
the requirements of Sec.  60.5371c (a) and (b). Based on my 
professional knowledge and experience, and inquiry of personnel 
involved in the assessment, the certification submitted herein is true, 
accurate, and complete. I am aware that knowingly false statements may 
be punishable by fine or imprisonment.''


Sec.  60.5390c   What GHG standards apply to gas well liquids unloading 
operations at well designated facilities?

    (a) General requirements. You must comply with the requirements of 
this section for each gas well liquids unloading operation at your gas 
well designated facility as specified by paragraphs (a)(1) and (2) of 
this section. You have a general duty to safely maximize resource 
recovery and minimize releases to the atmosphere during gas well 
liquids unloading operations.
    (1) If a gas well liquids unloading operation technology or 
technique employed does not result in venting of methane emissions to 
the atmosphere, you must comply with the requirements specified in 
paragraphs (a)(1)(A) and (B) of this section. If an unplanned venting 
event occurs, you must meet the

[[Page 17147]]

requirements specified in paragraphs (c) through (f) of this section.
    (A) Comply with the recordkeeping requirements specified in Sec.  
60.5420c(c)(1)(i).
    (B) Submit the information specified in Sec.  60.5420c(b)(1) and 
(2)(i) in the annual report.
    (2) If a gas well liquids unloading operation technology or 
technique vents methane emissions to the atmosphere, you must comply 
with the requirements specified in paragraphs (b) and (c), or paragraph 
(g) of this section.
    (b) Work Practice Standards. If a gas well liquids unloading 
operation employs a technology or technique that vents methane 
emissions to the atmosphere, you must comply with the requirements in 
paragraphs (b)(1) through (3) and paragraphs (c) through (f) of this 
section.
    (1) Employ best management practices to minimize venting of methane 
emissions as specified in paragraph (c) of this section for each gas 
well liquids unloading operation.
    (2) Comply with the recordkeeping requirements specified in Sec.  
60.5420c(c)(1)(ii).
    (3) Submit the information specified in Sec.  60.5420c(b)(1) and 
(2)(ii) in the annual report.
    (c) Best management practice requirements. For each gas well 
liquids unloading operation complying with paragraphs (a)(2) and (b) of 
this section, you must develop, maintain, and follow a best management 
practice plan to minimize venting of methane emissions to the maximum 
extent possible from each gas well liquids unloading operation. This 
best management practice plan must meet the minimum criteria specified 
in paragraphs (c)(1) through (4) of this section.
    (1) Include steps that create a differential pressure to minimize 
the need to vent a well to unload liquids,
    (2) Include steps to reduce wellbore pressure as much as possible 
prior to opening the well to the atmosphere,
    (3) Unload liquids through the separator where feasible, and
    (4) Close all wellhead vents to the atmosphere and return the well 
to production as soon as practicable.
    (d) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to well liquids unloading operations at 
your well designated facilities as required by Sec.  60.5410c(a).
    (e) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to well liquids unloading 
operations at your well designated facilities as required by Sec.  
60.5415c(a).
    (f) Recordkeeping and recording. You must perform the required 
notification, recordkeeping and reporting requirements as specified in 
Sec.  60.5420c(b)(2) and (c)(1).
    (g) Other compliance options. Reduce methane emissions from well 
designated facilities gas wells that unload liquids by 95.0 percent by 
complying with the requirements specified in paragraphs (g)(1) and (2) 
of this section and meeting the initial and continuous compliance and 
recordkeeping and reporting requirements specified in paragraphs (g)(3) 
through (5) of this section.
    (1) You must route emissions through a closed vent system to a 
control device that meets the conditions specified in Sec.  60.5412c.
    (2) You must route emissions through a closed vent system that 
meets the requirements of Sec.  60.5411c(a) and (c).
    (3) You must demonstrate initial compliance with standards that 
apply to well designated facility gas well liquids unloading as 
required by Sec.  60.5410c(b).
    (4) You must demonstrate continuous compliance with standards that 
apply to well designated facility gas well liquids unloading as 
required by Sec.  60.5415c(b).
    (5) You must perform the reporting as required by Sec.  
60.5420c(b)(1), (2), and (10) through (12), as applicable; and the 
recordkeeping as required by Sec.  60.5420c(c)(1), (7), and (9) through 
(12), as applicable.


Sec.  60.5391c   What GHG standards apply to associated gas wells at 
well designated facilities?

    (a) You must comply with either paragraph (a)(1), (2), (3), or (4) 
of this section for each associated gas well, except as provided in 
paragraphs (b), (c), and (d) of this section. You must also comply with 
paragraphs (f), (g), and (h) of this section.
    (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.
    (4) Recover the associated gas from the separator and reinject the 
recovered gas into the well or inject the recovered gas into another 
well.
    (b) If you meet one of the conditions in paragraphs (b)(1) or (2) 
of this section, you may route the associated gas to a control device 
that reduces methane emissions by at least 95.0 percent instead of 
complying with paragraph (a) of this section. The associated gas must 
be routed through a closed vent system that meets the requirements of 
Sec.  60.5411c(a) and (c) and the control device must meet the 
conditions specified in Sec.  60.5412c(a), (b), and (c).
    (1) If the annual methane contained in the associated gas from your 
oil well is 40 tons per year or less at the initial compliance date, 
determined in accordance with paragraph (e) of this section.
    (2) If you demonstrate and certify that it is not feasible to 
comply with paragraph (a)(1), (2), (3), and (4) of this section due to 
technical reasons by providing a detailed analysis documenting and 
certifying the technical reasons for this infeasibility in accordance 
with paragraphs (b)(2)(i) through (iv) of this section.
    (i) In order to demonstrate that it is not feasible to comply with 
paragraph (a)(1), (2), (3), and (4) of this section, you must provide a 
detailed analysis documenting and certifying the technical reasons for 
this infeasibility. The demonstration must address the technical 
infeasibility for all options identified in (a)(1), (2), (3), and (4) 
of this section. Documentation of these demonstrations must be 
maintained in accordance with Sec.  60.5420c(c)(2)(ii).
    (ii) This demonstration must be certified by a professional 
engineer or another qualified individual with expertise in the uses of 
associated gas. The following certification, signed and dated by the 
qualified professional engineer or other qualified individual shall 
state: ``I certify that the assessment of technical and safety 
infeasibility was prepared under my direction or supervision. I further 
certify that the assessment was conducted, and this report was prepared 
pursuant to the requirements of Sec.  60.5391c(b)(1). Based on my 
professional knowledge and experience, and inquiry of personnel 
involved in the assessment, the certification submitted herein is true, 
accurate, and complete.''
    (iii) This demonstration and certification are valid for no more 
than 12 months. You must re-analyze the feasibility of complying with 
paragraphs (a)(1), (2), (3), and (4) of this section and finalize a new 
demonstration and certification each year.
    (iv) Documentation of these demonstrations, along with the 
certifications, must be maintained in accordance with Sec.  
60.5420c(c)(3)(ii) and submitted in annual reports in accordance with 
Sec.  60.5420c(b)(3).
    (c) If you are complying with paragraph (a) of this section, you 
may

[[Page 17148]]

temporarily route the associated gas to a flare or control device in 
the situations and for the durations identified in paragraphs (c)(1), 
(2), (3), or (4) of this section. The associated gas must be routed 
through a closed vent system that meets the requirements of Sec.  
60.5411c(a) and (c) and the control device must meet the conditions 
specified in Sec.  60.5412c(a), (b) and (c). If you are routing to a 
flare, you must demonstrate that the Sec.  60.18 flare requirements are 
met during the period when the associated gas is routed to the flare. 
Records must be kept of all temporary flaring instances in accordance 
with Sec.  60.5420c(c)(3) and reported in the annual report in 
accordance with Sec.  60.5420c(b)(3).
    (1) For equal to or less than 24 hours during a deviation caused by 
malfunction causing the need to flare.
    (2) For equal to or less than 24 hours during repair, maintenance 
including blow downs, a bradenhead test, a packer leakage test, a 
production test, or commissioning.
    (3) For (a)(1) and (b)(1) of this section, through the duration of 
a temporary interruption in service from the gathering or pipeline 
system, or 30 days, whichever is less.
    (4) For 72 hours from the time that the associated gas does not 
meet pipeline specifications, or until the associated gas meets 
pipeline specifications, whichever is less.
    (d) If you are complying with paragraph (a), (b), or (c) of this 
section, you may vent the associated gas in the situations and for the 
durations identified in paragraphs (d)(1), (2), or (3) of this section. 
Records must be kept of all venting instances in accordance with Sec.  
60.5420c(c)(3) and reported in the annual report in accordance with 
Sec.  60.5420c(b)(3).
    (1) For up to 12 hours to protect the safety of personnel.
    (2) For up to 30 minutes during bradenhead monitoring.
    (3) For up to 30 minutes during a packer leakage test.
    (e) Calculate the methane content in associated gas as specified in 
paragraph (e)(1) of this section and comply with paragraphs (e)(2) and 
(e)(3) of this section.
    (1) Calculate the methane content in associated gas from your oil 
well using the following equation
[GRAPHIC] [TIFF OMITTED] TR08MR24.036

Where:

AG<INF>methane</INF> = Amount of methane in associated gas from the 
oil well, tons methane per year
GOR = Gas to oil ratio for the well in standard cubic feet of gas 
per barrel of oil; oil here refers to hydrocarbon liquids produced 
of all API gravities. GOR is to be determined for the well using 
available data, an appropriate standard method published by a 
consensus-based standards organization which include, but are not 
limited to, the following: ASTM International, the American National 
Standards Institute (ANSI), the American Gas Association (AGA), the 
American Society of Mechanical Engineers (ASME), the American 
Petroleum Institute (API), and the North American Energy Standards 
Board (NAESB), or in industry standard practice.
V = Volume of oil produced in the calendar year preceding the 
initial compliance date, in barrels per year.
M<INF>methane</INF> = mole fraction of methane in the associated 
gas.
0.0192 = density of methane gas at 60 [deg]F and 14.7 psia in 
kilograms per cubic foot
907.2 = conversion of kilograms to tons, kilograms per ton

    (2) You must maintain records of the calculation of the methane in 
associated gas from your oil well results in accordance with Sec.  
60.5410c(c)(3), and submit the information, as well as the background 
information, in the next annual report in accordance with Sec.  
60.5410c(b)(3).
    (3) If a process change occurs that could increase the methane 
content in the associated gas, you must recalculate the methane content 
in accordance with paragraph (a)(d)(1) of this section.
    (f) You must demonstrate initial compliance with the standards that 
apply to associated gas wells at well designated facilities as required 
by Sec.  60.5410c(b).
    (g) You must demonstrate continuous compliance with the standards 
that apply to associated gas wells at well designated facilities as 
required by Sec.  60.5415c(b)(3).
    (h) You must perform the required recordkeeping and reporting as 
required by Sec.  60.5420c(b)(3), (10) and (11), as applicable, and 
Sec.  60.5420c(c)(2) and (7) and (9) through (12), as applicable.


Sec.  60.5392c   What GHG standards apply to centrifugal compressor 
designated facilities?

    Each centrifugal compressor designated facility must comply with 
the GHG standards in paragraphs (a) through (d) of this section.
    (a) Each centrifugal compressor designated facility that is a wet 
seal centrifugal compressor, each self-contained wet seal centrifugal 
compressor, and each Alaska North Slope centrifugal compressor equipped 
with sour seal oil separator and capture system, must comply with the 
GHG standards, using volumetric flow rate as a surrogate, as specified 
in paragraphs (a)(1) and (2) of this section. Each centrifugal 
compressor designated facility that is a dry seal centrifugal 
compressor must comply with the GHG standards, using volumetric flow 
rate as a surrogate, as specified in paragraphs (a)(1) and (2) of this 
section, and either paragraph (a)(4) or (5) of this section. 
Alternatively, you have the option of complying with the GHG standards 
for your wet seal and dry seal centrifugal compressor by meeting the 
requirements specified in paragraph (a)(3), and either paragraph (a)(4) 
or (5) of this section.
    (1) If you utilize a centrifugal compressor, you must comply with 
the GHG standards in paragraph (a)(1)(i) through (iii) of this section, 
and the seal repair requirements of paragraph (a)(1)(iv) of this 
section.
    (i) You must conduct volumetric flow rate measurements from each 
wet seal centrifugal compressor (including each self-contained wet seal 
centrifugal compressor) vent using the methods specified in paragraph 
(a)(2) of this section and in accordance with the schedule specified in 
paragraphs (a)(1)(i)(A) and (B) of this section. The volumetric flow 
rate, measured in accordance with paragraph (a)(2) of this section, 
must not exceed 3 standard cubic feet per minute (scfm) per seal. If 
the individual seals are manifolded to a single open-vented line, the 
volumetric flow rate must not exceed the sum of the individual seals 
multiplied by 3 scfm. If the volumetric flow rate exceeds 3 scfm 
multiplied by the number of seals connected to the vent, the seals 
connected to the measured vent must be repaired as provided in 
paragraph (a)(1)(iv) of this section.

[[Page 17149]]

    (A) You must conduct your first volumetric flow rate measurement 
from your wet seal centrifugal compressor (including self-contained wet 
seal centrifugal compressors) vents on or before 8,760 hours of 
operation 36 months after the state plan submittal deadline (as 
specified in Sec.  60.5362c(c)), or on or before 8,760 hours of 
operation after startup, whichever date is later.
    (B) You must conduct subsequent volumetric flow rate measurements 
from your wet seal centrifugal compressor (including self-contained wet 
seal centrifugal compressor) vents on or before 8,760 hours of 
operation after the previous measurement.
    (ii) You must conduct volumetric flow rate measurements from each 
Alaska North Slope centrifugal compressor equipped with sour seal oil 
separator and capture system using the methods specified in paragraph 
(a)(2) of this section and in accordance with the schedule specified in 
paragraphs (a)(1)(ii)(A) and (B) of this section. The volumetric flow 
rate, measured in accordance with paragraph (a)(2) of this section, 
must not exceed 9 standard cubic feet per minute (scfm) per seal. If 
the individual seals are manifolded to a single open-vented line, the 
volumetric flow rate must not exceed the sum of the individual seals 
multiplied by 9 scfm. If the volumetric flow rate exceeds 9 scfm 
multiplied by the number of seals connected to the vent, the seals 
connected to the measured vent must be repaired as provided in 
paragraph (a)(1)(iv) of this section.
    (A) You must conduct your first volumetric flow rate measurement 
from your centrifugal compressor equipped with sour seal oil separator 
and capture system utilized in Alaska wet seal vent on or before 8,760 
hours of operation 36 months after the state plan submittal deadline 
(as specified in Sec.  60.5362c(c)), or on or before 8,760 hours of 
operation after startup, whichever date is later.
    (B) You must conduct subsequent volumetric flow rate measurements 
from your centrifugal compressor wet seal vents on or before 8,760 
hours of operation after the previous measurement.
    (iii) You must conduct volumetric flow rate vent measurements from 
each centrifugal compressor equipped with dry seals using the methods 
specified in paragraph (a)(2) of this section and in accordance with 
the schedule specified in paragraphs (a)(1)(iii)(A) and (B) of this 
section. The volumetric flow rate, measured in accordance with 
paragraph (a)(2) of this section, must not exceed 10 standard cubic 
feet per minute (scfm) per seal. If the individual seals are manifolded 
to a single open-vented line, the volumetric flow rate must not exceed 
the sum of the individual seals multiplied by 10 scfm. If the 
volumetric flow rate exceeds 10 scfm multiplied by the number of seals 
connected to the vent, the seals connected to the measured vent must be 
repaired as provided in paragraph (a)(1)(iv) of this section.
    (A) You must conduct your first volumetric flow rate vent 
measurement from your centrifugal compressor equipped with a dry seal 
on or before 8,760 hours of operation 36 months after the state plan 
submittal deadline (as specified in Sec.  60.5362c(c)), or on or before 
8,760 hours of operation after startup, whichever date is later.
    (B) You must conduct subsequent volumetric flow rate vent 
measurements from your centrifugal compressor equipped with a dry seal 
on or before 8,760 hours of operation after the previous measurement.
    (iv) The seal must be repaired within 90 calendar days after the 
date of the volumetric emissions measurement that exceeds the 
applicable required flow rate per seal. You must conduct follow-up 
volumetric flow rate measurements from seal vents using the methods 
specified in paragraph (a)(2) of this section within 15 days after the 
repair to document that the rate has been reduced to less than the 
applicable required flow rate per seal. If the individual seals are 
manifolded to a single open-ended line or vent, the volumetric flow 
rate must be reduced to less than the sum of the individual seals 
multiplied by the applicable required flow rate per seal specified in 
paragraph (a)(1)(i) through (iii) of this section, as applicable. Delay 
of repair will be allowed if the conditions in paragraphs (a)(1)(iv)(A) 
or (B) of this section are met.
    (A) If the repair of the wet or dry seal is technically infeasible, 
would require a vent blowdown, a compressor station shutdown, or would 
be unsafe to repair during operation of the unit, the repair must be 
completed during the next scheduled compressor station shutdown for 
maintenance, after a scheduled vent blowdown, or within 2 years of the 
date of the volumetric emissions measurement that exceeds the 
applicable required flow rate per seal, whichever is earliest. A vent 
blowdown is the opening of one or more blowdown valves to depressurize 
major production and processing equipment, other than a storage vessel.
    (B) If the repair requires replacement of the compressor seal or a 
part thereof, but the replacement seal or part cannot be acquired and 
installed within the repair timelines specified under this section due 
to the condition specified in paragraph (a)(1)(iv)(B)(1) of this 
section, the repair must be completed in accordance with paragraph 
(a)(1)(iv)(B)(2) of this section and documented in accordance with 
Sec.  60.5420c(c)(3)(iii)(F) through (H).
    (1) Seal or part thereof supplies had been sufficiently stocked but 
are depleted at the time of the required repair.
    (2) The required replacement seal or part must be ordered no later 
than 10 calendar days after the centrifugal compressor is added to the 
delay of repair list due to parts unavailability. The repair must be 
completed as soon as practicable, but no later than 30 calendar days 
after receipt of the replacement seal or part, unless the repair 
requires a compressor station shutdown. If the repair requires a 
compressor station shutdown, the repair must be completed in accordance 
with the timeframe specified in paragraph (a)(1)(iv)(A) of this 
section.
    (2) You must determine the volumetric flow rates from your 
centrifugal compressor dry or wet seal vents as specified in paragraph 
(a)(2)(i) or (ii) of this section.
    (i) For each dry or wet seal centrifugal compressor in operating-
mode or in standby-pressurized-mode, determine volumetric flow rate at 
standard conditions from each dry or wet seal vent using one of the 
methods specified in paragraphs (a)(2)(i)(A) through (C) of this 
section.
    (A) You may choose to use any of the methods set forth in Sec.  
60.5405c(a) to screen for leaks/emissions. For the purposes of this 
paragraph, when using any of the methods in Sec.  60.5405c(a), 
emissions are detected whenever a leak is detected according to the 
method. If emissions are detected using the methods set forth in Sec.  
60.5405c(a), then you must use one of the methods specified in 
paragraph (a)(2)(i)(B) or (C) of this section to determine the 
volumetric flow rate. If emissions are not detected using the methods 
in Sec.  60.5405c(a), then you may assume that the volumetric flow rate 
is zero.
    (B) Use a temporary or permanent flow meter according to methods 
set forth in Sec.  60.5405c(b).
    (C) Use a high-volume sampler according to the methods set forth in 
Sec.  60.5405c(c).
    (ii) For conducting measurements on manifolded groups of dry or wet 
seal centrifugal compressors, you must determine the volumetric flow 
rate from the compressor dry or wet seal as specified in paragraph 
(a)(2)(ii)(A) or (B) of this section.

[[Page 17150]]

    (A) Measure at a single point in the manifold downstream of all dry 
or wet seal compressor inputs and, if practical, prior to comingling 
with other non-compressor emission sources.
    (B) Determine the volumetric flow rate at standard conditions from 
the common stack using one of the methods specified in paragraph 
(a)(2)(i)(A) through (C) of this section.
    (3) As an alternative to meeting the requirements of paragraphs 
(a)(1) and (2) of this section for compressors with wet seals and dry 
seals, you have the option of reducing methane emissions from each 
centrifugal compressor wet seal fluid degassing system by 95.0 percent 
by meeting the requirements of paragraph (a)(4) of this section, or the 
option of routing the emissions from each centrifugal compressor wet 
seal fluid degassing system or dry seal system to a process by meeting 
the requirements of paragraph (a)(5) of this section.
    (4) If you use a control device to reduce methane emissions by 95.0 
percent, you must equip the wet seal fluid degassing system with a 
cover that meets the requirements of Sec.  60.5411c(b). The cover must 
be connected through a closed vent system that meets the requirements 
of Sec.  60.5411c(a) and (c) and the closed vent system must be routed 
to a control device that meets the conditions specified in Sec.  
60.5412c.
    (5) If you route the emissions to a process, you must equip the wet 
seal fluid degassing system or dry seal system with a cover that meets 
the requirements of Sec.  60.5411c(b). The cover must be connected 
through a closed vent system that meets the requirements of Sec.  
60.5411c(a) and (c).
    (b) You must demonstrate initial compliance with the standards that 
apply to centrifugal compressor designated facilities as required by 
Sec.  60.5410c(c).
    (c) You must demonstrate continuous compliance with the standards 
that apply to centrifugal compressor designated facilities as required 
by Sec.  60.5415c(c).
    (d) You must perform the reporting as required by Sec.  
60.5420c(b)(1) and (4) and (b)(10) through (12), as applicable; and the 
recordkeeping as required by Sec.  60.5420c(c)(3) and (c)(7) through 
(12), as applicable.


Sec.  60.5393c   What GHG standards apply to reciprocating compressor 
designated facilities?

    Each reciprocating compressor designated facility must comply with 
the GHG standards, using volumetric flow rate as a surrogate, in 
paragraphs (a) through (c) of this section, or the GHG standards in 
paragraph (d) of this section. You must also comply with the 
requirements in paragraphs (e) through (g) of this section.
    (a) The volumetric flow rate of each cylinder, measured in 
accordance with paragraph (b) or (c) of this section, must not exceed 2 
scfm per individual cylinder. If the individual cylinders are 
manifolded to a single open-ended vent line, the volumetric flow rate 
must not exceed the sum of the individual cylinders multiplied by 2 
scfm. You must conduct measurements of the volumetric flow rate in 
accordance with the schedule specified in paragraphs (a)(1) and (2) of 
this section and determine the volumetric flow rate per cylinder in 
accordance with paragraph (b) or (c) of this section. If the volumetric 
flow rate, measured in accordance with paragraph (b) or (c) of this 
section, for a cylinder exceeds 2 scfm per cylinder (or a combined 
volumetric flow rate greater than the number of compression cylinders 
multiplied by 2 scfm), the rod packing or packings must be repaired or 
replaced as provided in paragraph (a)(3) of this section.
    (1) You must conduct your first volumetric flow rate measurements 
from your reciprocating compressor rod packing vent on or before 8,760 
hours of operation after the effective date of an approved state or 
Tribal plan, on or before 8,760 hours of operation after last rod 
packing replacement, or on or before 8,760 hours of operation after 
startup, whichever date is later.
    (2) You must conduct subsequent volumetric flow rate measurements 
from your reciprocating compressor rod packing vent on or before 8,760 
hours of operation after the previous measurement which demonstrates 
compliance with the applicable volumetric flow rate of 2 scfm per 
cylinder (or a combined cylinder volumetric flow rate greater than the 
number of compression cylinders multiplied by 2 scfm), or on or before 
8,760 hours of operation after last rod packing replacement, whichever 
date is later.
    (3) The rod packing must be repaired or replaced within 90 calendar 
days after the date of the volumetric emissions measurement that 
exceeded 2 scfm per cylinder. You must conduct follow-up volumetric 
flow rate measurements from compressor vents using the methods 
specified in paragraph (b) of this section within 15 days after the 
repair (or rod packing replacement) to document that the rate has been 
reduced to less than 2 scfm per cylinder. Delay of repair will be 
allowed if the conditions in paragraphs (a)(3)(i) or (ii) of this 
section are met.
    (i) If the repair (or rod packing replacement) is technically 
infeasible, would require a vent blowdown, a compressor station 
shutdown, or would be unsafe to repair during operation of the unit, 
the repair (or rod packing replacement) must be completed during the 
next scheduled compressor station shutdown for maintenance, after a 
scheduled vent blowdown, or within 2 years of the date of the 
volumetric emissions measurement that exceeds the applicable required 
flow rate per cylinder, whichever is earliest. A vent blowdown is the 
opening of one or more blowdown valves to depressurize major production 
and processing equipment, other than a storage vessel.
    (ii) If the repair requires replacement of the rod packing or a 
part, but the replacement cannot be acquired and installed within the 
repair timelines specified under this section due to the condition 
specified in paragraph (a)(3)(ii)(A) of this section, the repair must 
be completed in accordance with paragraph (a)(3)(ii)(B) of this section 
and documented in accordance with Sec.  60.5420c(c)(4)(viii) through 
(x).
    (A) Rod packing or part supplies had been sufficiently stocked but 
are depleted at the time of the required repair.
    (B) The required rod packing or part replacement must be ordered no 
later than 10 calendar days after the reciprocating compressor is added 
to the delay of repair list due to parts unavailability. The repair 
must be completed as soon as practicable, but no later than 30 calendar 
days after receipt of the replacement rod packing or part, unless the 
repair requires a compressor station shutdown. If the repair requires a 
compressor station shutdown, the repair must be completed in accordance 
with the timeframe specified in paragraph (a)(3)(i) of this section.
    (b) You must determine the volumetric flow rate per cylinder from 
your reciprocating compressor as specified in paragraph (b)(1) or (2) 
of this section.
    (1) For reciprocating compressor rod packing equipped with an open-
ended vent line on compressors in operating or standby pressurized 
mode, determine the volumetric flow rate of the rod packing using one 
of the methods specified in paragraphs (b)(1)(i) through (iii) of this 
section.
    (i) Determine the volumetric flow rate at standard conditions from 
the open-ended vent line using a high-volume sampler according to 
methods set forth in Sec.  60.5405c(c).

[[Page 17151]]

    (ii) Determine the volumetric flow rate at standard conditions from 
the open-ended vent line using a temporary or permanent meter, 
according to methods set forth in Sec.  60.5405c(b).
    (iii) Any of the methods set forth in Sec.  60.5405c(a) to screen 
for leaks and emissions. For the purposes of this paragraph, emissions 
are detected whenever a leak is detected according to any of the 
methods in Sec.  60.5405c(a). If emissions are detected using the 
methods set forth in Sec.  60.5405c(a), then you must use one of the 
methods specified in paragraph (b)(1)(i) and (ii) of this section to 
determine the volumetric flow rate per cylinder. If emissions are not 
detected using the methods in Sec.  60.5405c(a), then you may assume 
that the volumetric flow rate is zero.
    (2) For reciprocating compressor rod packing not equipped with an 
open-ended vent line on compressors in operating or standby pressurized 
mode, you must determine the volumetric flow rate of the rod packing 
using the methods specified in paragraphs (b)(2)(i) and (ii) of this 
section.
    (i) You must use the methods described in Sec.  60.5405c(a) to 
conduct leak detection of emissions from the rod packing case into an 
open distance piece, or, for compressors with a closed distance piece, 
you must conduct annual leak detection of emissions from the rod 
packing vent, distance piece vent, compressor crank case breather cap, 
or other vent emitting gas from the rod packing.
    (ii) You must measure emissions found in paragraph (b)(2)(i) of 
this section using a meter or high-volume sampler according to methods 
set forth in Sec.  60.5405c(b) or (c).
    (c) For conducting measurements on manifolded groups of 
reciprocating compressor designated facilities, you must determine the 
volumetric flow rate from reciprocating compressor rod packing vent as 
specified in paragraph (c)(1) and (2) of this section.
    (1) Measure at a single point in the manifold downstream of all 
compressor vent inputs and, if practical, prior to comingling with 
other non-compressor emission sources.
    (2) Determine the volumetric flow rate per cylinder at standard 
conditions from the common stack using one of the methods specified in 
paragraph (c)(2)(i) through (iv) of this section.
    (i) A temporary or permanent flow meter according to the methods 
set forth in Sec.  60.5405c(b).
    (ii) A high-volume sampler according to methods set forth Sec.  
60.5405c(c).
    (iii) An alternative method, as set forth in Sec.  60.5405c(d).
    (iv) Any of the methods set forth in Sec.  60.5405c(a) to screen 
for emissions. For the purposes of this paragraph, emissions are 
detected whenever a leak is detected when using any of the methods in 
Sec.  60.5405c(a). If emissions are detected using the methods set 
forth in Sec.  60.5405c(a), then you must use one of the methods 
specified in paragraph (c)(2)(i) through (iii) of this section to 
determine the volumetric flow rate per cylinder. If emissions are not 
detected using the methods in Sec.  60.5405c(a), then you may assume 
that the volumetric flow rate is zero.
    (d) As an alternative to complying with the GHG standards in 
paragraphs (a) through (c) of this section, owners or operators can 
meet the requirements specified in paragraph (d)(1), (2), or (3) of 
this section.
    (1) Collect the methane emissions from your reciprocating 
compressor rod packing using a rod packing emissions collection system 
that is operated to route the rod packing emissions to a process. In 
order to comply with this option, you must equip the reciprocating 
compressor with a cover that meets the requirements of Sec.  
60.5411c(b). The cover must be connected through a closed vent system 
that meets the requirements of Sec.  60.5411c(a) and (c).
    (2) Reduce methane emissions from each rod packing emissions 
collection system by using a control device that reduces methane 
emissions by 95.0 percent. In order to comply with this option, you 
must equip the reciprocating compressor with a cover that meets the 
requirements of Sec.  60.5411c(b). The cover must be connected through 
a closed vent system that meets the requirements of Sec.  60.5411c(a) 
and (c) and the closed vent system must be routed to a control device 
that meets the conditions specified in Sec.  60.5412c.
    (3) As an alternative to conducting the required volumetric flow 
rate measurements under paragraph (a) of this section, an owner or 
operator can choose to comply by replacing the rod packing on or before 
8,760 hours of operation after the effective date of the final rule, on 
or before 8,760 hours of operation after the previous flow rate 
measurement, or on or before 8,760 hours of operation after the date of 
the most recent compressor rod packing replacement, whichever date is 
later.
    (e) You must demonstrate initial compliance with standards that 
apply to reciprocating compressor designated facilities as required by 
Sec.  60.5410c(d).
    (f) You must demonstrate continuous compliance with standards that 
apply to reciprocating compressor designated facilities as required by 
Sec.  60.5415c(f).
    (g) You must perform the reporting requirements as specified in 
Sec.  60.5420c(b)(1), (5), (10), and (11), as applicable; and the 
recordkeeping requirements as specified in Sec.  60.5420c(c)(4) and (7) 
through (11), as applicable.


Sec.  60.5394c   What GHG standards apply to process controller 
designated facilities?

    Each process controller designated facility must comply with the 
GHG standards in this section.
    (a) You must design and operate each process controller designated 
facility with zero methane emissions to the atmosphere, except as 
provided in paragraph (b) of this section.
    (1) If you comply by routing the emissions to a process, emissions 
must be routed to a process through a closed vent system.
    (2) If you comply by using a self-contained natural gas-driven 
process controller, you must design and operate each self-contained 
natural gas-driven process controller with no identifiable emissions, 
as demonstrated by Sec.  60.5416c(b).
    (b) For each process controller designated facility located at a 
site in Alaska that does not have access to electrical power, you may 
comply with either paragraphs (b)(1) and (2) of this section or with 
paragraph (b)(3) of this section, instead of complying with paragraph 
(a) of this section.
    (1) With the exception of natural gas-driven continuous bleed 
controllers that meet the condition in paragraph (b)(1)(i) of this 
section and that comply with paragraph (b)(1)(ii) of this section, each 
natural gas-driven continuous bleed process controller in the process 
controller designated facility must have a bleed rate less than or 
equal to 6 standard cubic feet per hour (scfh).
    (i) A natural gas-driven continuous bleed process controller with a 
bleed rate higher than 6 scfh may be used if the requirements of 
paragraph (b)(1)(ii) of this section are met.
    (ii) You demonstrate that a natural gas-driven continuous bleed 
controller with a bleed rate higher than 6 scfh is required. The 
demonstration must be based on the specific functional need, including 
but not limited to response time, safety, or positive actuation.
    (2) Each natural gas-driven intermittent vent process controller in 
the process controller designated facility must comply with the 
requirements in paragraphs (b)(2)(i) and (ii) of this section.
    (i) Each natural gas-driven intermittent vent process controller

[[Page 17152]]

must not emit to the atmosphere during idle periods.
    (ii) You must monitor each natural gas-driven intermittent vent 
process controller to ensure that it is not emitting to the atmosphere 
during idle periods, as specified in paragraphs (b)(2)(ii)(A) through 
(C) of this section.
    (A) Monitoring must be conducted at the same frequency as specified 
for fugitive emissions components designated facilities located at the 
same type of site, as specified in Sec.  60.5397c(g).
    (B) You must include the monitoring of each natural gas-driven 
intermittent vent process controller in the monitoring plan required in 
Sec.  60.5397c(b).
    (C) When monitoring identifies emissions to the atmosphere from a 
natural gas-driven intermittent vent controller during idle periods, 
you must take corrective action by repairing or replacing the natural 
gas-driven intermittent vent process controller within 5 calendar days 
of the date the emissions to the atmosphere were detected. After the 
repair or replacement of a natural gas-driven intermittent vent process 
controller, you must re-survey the natural gas-driven intermittent vent 
process controller within five days to verify that it is not venting 
emissions during idle periods.
    (3) You must reduce methane emissions from all controllers in the 
process controller designated facility by 95.0 percent. You must route 
emissions through a closed vent system to a control device through a 
closed vent system that meets the conditions specified in Sec.  
60.5412c.
    (c) If you route process controller emissions to a process or a 
control device, you must route the process controller designated 
facility emissions through a closed vent system that meets the 
requirements of Sec.  60.5411c(a) and (c).
    (d) You must demonstrate initial compliance with standards that 
apply to process controller designated facilities as required by Sec.  
60.5410c(e).
    (e) You must demonstrate continuous compliance with standards that 
apply to process controller designated facilities as required by Sec.  
60.5415c(g).
    (f) You must perform the reporting as required by Sec.  
60.5420c(b)(1), (6) and (10) through (12), as applicable, and the 
recordkeeping as required by Sec.  60.5420c(c)(5), (7), and (9) through 
(12), as applicable.


Sec.  60.5395c   What GHG standards apply to pump designated 
facilities?

    Each pump designated facility, you must comply with the GHG 
standards in this section.
    (a) For each pump designated facility meeting the criteria 
specified in paragraphs (a)(1) or (2) of this section, you must design 
and operate the pump designated facility with zero methane emissions to 
the atmosphere. If you comply by routing the pump designated facility 
emissions to a process, the emissions must be routed to the process 
through a closed vent system.
    (1) The pump designated facility is located at a site that has 
access to electrical power.
    (2) The pump designated facility is located at a site that does not 
have access to electrical power and also has three or more natural gas-
driven diaphragm pumps.
    (b)(1) For each pump designated facility located at a site that 
does not have access to electrical power and that also has fewer than 
three natural gas-driven diaphragm pumps, you must comply with 
paragraph (b)(2) or (3) of this section, except as provided in 
paragraphs (b)(4) through (8) of this section.
    (2) Emissions from the pump designated facility must be routed 
through a closed vent system to a process if a vapor recovery unit is 
onsite.
    (3) If a vapor recovery unit is not onsite, you must reduce methane 
emissions from the pump designated facility by 95.0 percent. You must 
route designated pump facility emissions through a closed vent system 
to a control device meeting the conditions specified in Sec.  60.5412c.
    (4) You are not required to install an emissions control device or 
a vapor recovery unit, if such a unit is necessary to enable emissions 
to be routed to a process, solely for the purpose of complying with the 
requirements of paragraphs (b)(2) or (3) of this section. If no control 
device capable of achieving a 95.0 percent emissions reduction and no 
vapor recovery unit is present on site, you must comply with paragraph 
(b)(5) or (6) of this section, as applicable. For the purposes of this 
section, boilers and process heaters are not considered to be control 
devices.
    (5) If an emissions control device is on site but is unable to 
achieve a 95.0 percent emissions reduction, you must route the pump 
designated facility emissions through a closed vent system to that 
control device. You must certify that there is no vapor recovery unit 
on site and that there is no control device capable of achieving a 95.0 
percent emissions reduction on site.
    (6) If there is no vapor recovery unit on site and no emission 
control device is on site, you must certify that there is no vapor 
recovery unit or emissions control device on site. If you subsequently 
install a control device or vapor recovery unit, you must meet the 
requirements of paragraphs (b)(6)(i) and (ii) of this section.
    (i) You must be in compliance with the requirements of paragraphs 
(b)(1) through (3) of this section, as applicable, within 30 days of 
startup of the control device or vapor recovery unit.
    (ii) You must maintain the records in Sec.  60.5420c(c)(14)(ii) and 
(v), as applicable. You are no longer required to maintain the records 
in Sec.  60.5420c(c)(14)(vi).
    (7) If an owner or operator complying with paragraph (b)(1) of this 
section determines, through an engineering assessment, that routing the 
pump designated facility emissions to a control device or to a process 
is technically infeasible, the requirements specified in paragraphs 
(b)(7)(i) through (iii) of this section must be met.
    (i) The owner or operator must conduct the assessment of technical 
infeasibility in accordance with the criteria in paragraph (b)(7)(ii) 
of this section and have it certified by either a qualified 
professional engineer or an in-house engineer with expertise on the 
design and operation of the pump designated facility and the control 
device or processes at the site in accordance with paragraph 
(b)(7)(iii) of this section.
    (ii) The assessment of technical infeasibility to route emissions 
from the pump designated facility to an existing control device or 
process must include, but is not limited to, safety considerations, 
distance from the control device or process, pressure losses and 
differentials in the closed vent system, and the ability of the control 
device or process to handle the pump designated facility emissions 
which are routed to them. The assessment of technical infeasibility 
must be prepared under the direction or supervision of the qualified 
professional engineer or in-house engineer who signs the certification 
in accordance with paragraph (b)(7)(iii) of this section.
    (iii) The following certification, signed and dated by the 
qualified professional engineer or in-house engineer, must state: ``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

[[Page 17153]]

requirements of Sec.  60.5395c(b)(5)(ii). Based on my professional 
knowledge and experience, and inquiry of personnel involved in the 
assessment, the certification submitted herein is true, accurate, and 
complete.''
    (8) If the pump designated facility emissions are routed to a 
control device or process and the control device or process is 
subsequently removed from the location or is no longer available such 
that there is no option to route to a control device or process, you 
are no longer required to be in compliance with the requirements of 
paragraph (b)(2) or (3) of this section, and instead must comply with 
paragraph (b)(6) of this section.
    (c) If you use a control device or route to a process to reduce 
emissions, you must route the pump designated facility emissions 
through a closed vent system that meets the requirements of Sec.  
60.5411c(a) and (c).
    (d) You must demonstrate initial compliance with standards that 
apply to pump designated facilities as required by Sec.  60.5410c(f).
    (e) You must demonstrate continuous compliance with the standards 
that apply to pump designated facilities as required by Sec.  
60.5415c(d).
    (f) You must perform the reporting as required by Sec.  
60.5420c(b)(1), (9), and (b)(10) through (12), as applicable, and the 
recordkeeping as required by Sec.  60.5420c(c)(7), (c)(9) through (12), 
and (14), as applicable.


Sec.  60.5396c   What GHG standards apply to storage vessel designated 
facilities?

    Each storage vessel designated facility must comply with the GHG 
standards in this section, except as provided in paragraph (e) of this 
section.
    (a) General requirements. You must comply with the requirements of 
paragraphs (a)(1) and (2) of this section. After 12 consecutive months 
of compliance with paragraph (a)(2) of this section, you may continue 
to comply with paragraph (a)(2) of this section, or you may comply with 
paragraph (a)(3) of this section, if applicable. If you choose to meet 
the requirements of paragraph (a)(3) of this section, you are not 
required to comply with the requirements of paragraph (a)(2) of this 
section except as provided in paragraphs (a)(3)(i) and (ii) of this 
section.
    (1) Determine the potential for methane emissions in accordance 
with Sec.  60.5386c(e)(2).
    (2) Reduce methane emissions by 95.0 percent.
    (3) Maintain the uncontrolled actual methane emissions from the 
storage vessel designated facility at less than 14 tpy without 
considering control in accordance with paragraphs (a)(3)(i) through 
(iii) of this section. Prior to using the uncontrolled actual methane 
emission rates for compliance purposes, you must demonstrate that the 
uncontrolled actual methane emissions have remained less than 14 tpy as 
determined monthly for 12 consecutive months. After such demonstration, 
you must determine the uncontrolled actual rolling 12-month 
determination methane emissions rates each month. The uncontrolled 
actual methane emissions must be calculated using a generally accepted 
model or calculation methodology which account for flashing, working, 
and breathing losses, and the calculations must be based on the actual 
average throughput, temperature, and separator pressure for the month. 
You may no longer comply with this paragraph and must instead comply 
with paragraph (a)(2) of this section if your storage vessel designated 
facility meets the conditions specified in paragraphs (a)(3)(i) or (ii) 
of this section.
    (i) If a well feeding the storage vessel designated facility 
undergoes fracturing or refracturing, you must comply with paragraph 
(a)(2) of this section as soon as liquids from the well following 
fracturing or refracturing are routed to the storage vessel designated 
facility.
    (ii) If the rolling 12-month emissions determination required in 
this section indicates that methane emissions increase to 14 tpy or 
greater from your storage vessel designated facility and the increase 
is not associated with fracturing or refracturing of a well feeding the 
storage vessel designated facility, you must comply with paragraph 
(a)(2) of this section within 30 days of the monthly determination.
    (b) Control requirements. (1) Except as required in paragraph 
(b)(2) of this section, if you use a control device to reduce methane 
emissions from your storage vessel designated facility, you must meet 
all of the design and operational criteria specified in paragraphs 
(b)(1)(i) through (iv) of this section.
    (i) Each storage vessel in the tank battery must be equipped with a 
cover that meets the requirements of Sec.  60.5411c(b);
    (ii) The storage vessels must be manifolded together with piping 
such that all vapors are shared among the headspaces of the storage 
vessels in the tank battery;
    (iii) The tank battery must be equipped with one or more closed 
vent system that meets the requirements of Sec.  60.5411c(a) and (c); 
and
    (iv) The vapors collected in paragraphs (b)(1)(ii) and (iii) of 
this section must be routed to a control device that meets the 
conditions specified in Sec.  60.5412c. As an alternative to routing 
the closed vent system to a control device, you may route the closed 
vent system to a process.
    (2) For storage vessel designated facilities that do not have 
flashing emissions and that are not located at well sites or 
centralized production facilities, you may use a floating roof to 
reduce emissions. If you use a floating roof to reduce emissions, you 
must meet the requirements of Sec.  60.112b(a)(1) or (2) and the 
relevant monitoring, inspection, recordkeeping, and reporting 
requirements in subpart Kb of this part. You must submit a statement 
that you are complying with Sec.  60.112b(a)(1) or (2) with the initial 
annual report specified in Sec.  60.5420c(b)(1) and (7).
    (c) Requirements for storage vessel designated facilities that are 
removed from service or returned to service. If you remove a storage 
vessel designated facility from service or remove a portion of a 
storage vessel designated facility from service, you must comply with 
the applicable paragraphs (c)(1) through (4) of this section. A storage 
vessel is not a designated facility under this subpart for the period 
that it is removed from service.
    (1) For a storage vessel designated facility to be removed from 
service, you must comply with the requirements of paragraphs (c)(1)(i) 
and (ii) of this section.
    (i) You must completely empty and degas each storage vessel, such 
that each storage vessel no longer contains crude oil, condensate, 
produced water or intermediate hydrocarbon liquids. A storage vessel 
where liquid is left on walls, as bottom clingage or in pools due to 
floor irregularity is considered to be completely empty.
    (ii) You must submit a notification as required in Sec.  
60.5420c(b)(7)(viii) in your next annual report, identifying each 
storage vessel designated facility removed from service during the 
reporting period and the date of its removal from service.
    (2) For a portion of a storage vessel designated facility to be 
removed from service, you must comply with the requirements of 
paragraphs (c)(2)(i) through (iv) of this section.
    (i) You must completely empty and degas the storage vessel(s), such 
that the storage vessel(s) no longer contains crude oil, condensate, 
produced water or intermediate hydrocarbon liquids. A storage vessel 
where liquid is left on walls, as bottom clingage or in pools

[[Page 17154]]

due to floor irregularity is considered to be completely empty.
    (ii) You must disconnect the storage vessel(s) from the tank 
battery by isolating the storage vessel(s) from the tank battery such 
that the storage vessel(s) is no longer manifolded to the tank battery 
by liquid or vapor transfer.
    (iii) You must submit a notification as required in Sec.  
60.5420c(b)(7)(viii) in your next annual report, identifying each 
storage vessel removed from service during the reporting period, the 
impacted storage vessel designated facility, and the date of its 
removal from service.
    (iv) The remaining storage vessel(s) in the tank battery remain a 
storage vessel designated facility and must continue to comply with the 
applicable requirements of paragraphs (a) and (b) of this section.
    (3) If a storage vessel identified in paragraph (c)(1)(ii) or 
(c)(2)(iii) of this section is returned to service, you must determine 
its designated facility status as provided in Sec.  60.5386c(e)(5).
    (4) For each storage vessel designated facility or portion of a 
storage vessel designated facility returned to service during the 
reporting period, you must submit a notification in your next annual 
report as required in Sec.  60.5420c(b)(7)(ix), identifying each 
storage vessel designated facility or portion of a storage vessel 
designated facility and the date of its return to service.
    (d) Compliance, notification, recordkeeping, and reporting. You 
must comply with paragraphs (d)(1) through (3) of this section.
    (1) You must demonstrate initial compliance with standards as 
required by Sec.  60.5410c(h).
    (2) You must demonstrate continuous compliance with standards as 
required by Sec.  60.5415c(h).
    (3) You must perform the required reporting as required by Sec.  
60.5420c(b)(1) and (7) and (b)(10) through (12), as applicable and the 
recordkeeping as required by Sec.  60.5420c(c)(6) and (c)(7) through 
(12), as applicable.
    (e) Exemptions. This subpart does not apply to storage vessels 
subject to and controlled in accordance with the requirements for 
storage vessels in subpart Kb of this part, and 40 CFR part 63, 
subparts G, CC, HH, or WW.


Sec.  60.5397c   What GHG standards apply to fugitive emissions 
components designated facilities?

    This section applies to fugitive emissions components designated 
facilities. You must comply with the requirements of paragraphs (a) 
through (l) of this section to reduce fugitive emissions of methane. 
The requirements of this section are independent of the cover and 
closed vent system requirements of Sec.  60.5411c.
    (a) General requirements. You must monitor all fugitive emissions 
components in accordance with paragraphs (b) through (g) of this 
section. You must repair all sources of fugitive emissions in 
accordance with paragraph (h) of this section. You must demonstrate 
initial compliance in accordance with paragraph (i) of this section. 
You must keep records in accordance with paragraph (j) of this section 
and report in accordance with paragraph (k) of this section. You must 
meet the requirements for well closures in accordance with paragraph 
(l) of this section.
    (b) Develop fugitive emissions monitoring plan. You must develop a 
fugitive emissions monitoring plan that covers all fugitive emissions 
components designated facilities within each company-defined area in 
accordance with paragraphs (c) and (d) of this section.
    (c) Fugitive emissions monitoring plan. Your fugitive emissions 
monitoring plan must include the elements specified in paragraphs 
(c)(1) through (8) of this section, at a minimum.
    (1) Frequency for conducting surveys. Surveys must be conducted at 
least as frequently as required by paragraphs (f) and (g) of this 
section.
    (2) Technique for determining fugitive emissions (i.e., AVO or 
other detection methods, Method 21 of appendix A-7 to this part; and/or 
OGI and meeting the requirements of paragraphs (c)(7)(i) through (vii) 
of this section).
    (3) Manufacturer and model number of fugitive emissions detection 
equipment to be used, if applicable.
    (4) Procedures and timeframes for identifying and repairing 
fugitive emissions components from which fugitive emissions are 
detected, including timeframes for fugitive emission components that 
are unsafe to repair. Your repair schedule must meet the requirements 
of paragraph (h) of this section at a minimum.
    (5) Procedures and timeframes for verifying fugitive emission 
component repairs.
    (6) Records that will be kept and the length of time records will 
be kept.
    (7) If you are using OGI, your plan must also include the elements 
specified in paragraphs (c)(7)(i) through (vii) of this section.
    (i) Verification that your OGI equipment meets the specifications 
of paragraphs (c)(7)(i)(A) and (B) of this section. This verification 
is an initial verification, and may either be performed by the 
facility, by the manufacturer, or by a third party. For the purposes of 
complying with the fugitive emissions monitoring program with OGI, 
fugitive emissions are defined as any visible emissions observed using 
OGI.
    (A) Your OGI equipment must be capable of imaging gases in the 
spectral range for the compound of highest concentration in the 
potential fugitive emissions.
    (B) Your OGI equipment must be capable of imaging a gas that is 
half methane, half propane at a concentration of 10,000 ppm at a flow 
rate of <=60 g/hr from a quarter inch diameter orifice.
    (ii) Procedure for a daily verification check.
    (iii) Procedure for determining the operator's maximum viewing 
distance from the equipment and how the operator will ensure that this 
distance is maintained.
    (iv) Procedure for determining maximum wind speed during which 
monitoring can be performed and how the operator will ensure monitoring 
occurs only at wind speeds below this threshold.
    (v) Procedures for conducting surveys, including the items 
specified in paragraphs (c)(7)(v)(A) through (C) of this section.
    (A) How the operator will ensure an adequate thermal background is 
present in order to view potential fugitive emissions.
    (B) How the operator will deal with adverse monitoring conditions, 
such as wind.
    (C) How the operator will deal with interferences (e.g., steam).
    (vi) Training and experience needed prior to performing surveys.
    (vii) Procedures for calibration and maintenance. At a minimum, 
procedures must comply with those recommended by the manufacturer.
    (8) If you are using Method 21 of appendix A-7 to this part, your 
plan must also include the elements specified in paragraphs (c)(8)(i) 
through (iv) of this section. For the purposes of complying with the 
fugitive emissions monitoring program using Method 21 of appendix A-7 
to this part, a fugitive emission is defined as an instrument reading 
of 500 ppmv or greater.
    (i) Verification that your monitoring equipment meets the 
requirements specified in Section 6.0 of Method 21 of appendix A-7 to 
this part. For purposes of instrument capability, the fugitive 
emissions definition shall be 500 ppmv or greater methane using a FID-
based instrument. If you wish to use an

[[Page 17155]]

analyzer other than a FID-based instrument, you must develop a site-
specific fugitive emission definition that would be equivalent to 500 
ppmv methane using a FID-based instrument (e.g., 10.6 eV PID with a 
specified isobutylene concentration as the fugitive emission definition 
would provide equivalent response to your compound of interest).
    (ii) Procedures for conducting surveys. At a minimum, the 
procedures shall ensure that the surveys comply with the relevant 
sections of Method 21 of appendix A-7 to this part, including Section 
8.3.1.
    (iii) Procedures for calibration. The instrument must be calibrated 
before use each day of its use by the procedures specified in Method 21 
of appendix A-7 to this part. At a minimum, you must also conduct 
precision tests at the interval specified in Method 21 of appendix A-7 
to this part, Section 8.1.2, and a calibration drift assessment at the 
end of each monitoring day. The calibration drift assessment must be 
conducted as specified in paragraph (c)(8)(iii)(A) of this section. 
Corrective action for drift assessments is specified in paragraphs 
(c)(8)(iii)(B) and (C) of this section.
    (A) Check the instrument using the same calibration gas that was 
used to calibrate the instrument before use. Follow the procedures 
specified in Method 21 of appendix A-7 to this part, Section 10.1, 
except do not adjust the meter readout to correspond to the calibration 
gas value. If multiple scales are used, record the instrument reading 
for each scale used. Divide the arithmetic difference of the initial 
and post-test calibration response by the corresponding calibration gas 
value for each scale and multiply by 100 to express the calibration 
drift as a percentage.
    (B) If a calibration drift assessment shows a negative drift of 
more than 10 percent, then all equipment with instrument readings 
between the fugitive emission definition multiplied by (100 minus the 
percent of negative drift) divided by 100 and the fugitive emission 
definition that was monitored since the last calibration must be re-
monitored.
    (C) If any calibration drift assessment shows a positive drift of 
more than 10 percent from the initial calibration value, then, at the 
owner/operator's discretion, all equipment with instrument readings 
above the fugitive emission definition and below the fugitive emission 
definition multiplied by (100 plus the percent of positive drift) 
divided by 100 monitored since the last calibration may be re-
monitored.
    (iv) Procedures for monitoring yard piping (other than buried yard 
piping). At a minimum, place the probe inlet at the surface of the yard 
piping and run the probe down the length of the piping. Connection 
points on the piping must be monitored following the procedures 
specified in Method 21 of appendix A-7 to this part.
    (d) Additional elements of fugitive emissions monitoring plan. Each 
fugitive emissions monitoring plan must include the elements specified 
in paragraphs (d)(1) and (2) of this section, at a minimum, as 
applicable.
    (1) If you are using OGI, your plan must include procedures to 
ensure that all fugitive emissions components, except buried yard 
piping and associated components (e.g., connectors), are monitored 
during each survey. Example procedures include, but are not limited to, 
a sitemap with an observation path, a written narrative of where the 
fugitive emissions components are located and how they will be 
monitored, or an inventory of fugitive emissions components.
    (2) If you are using Method 21 of appendix A-7 to this part, your 
plan must include a list of fugitive emissions components to be 
monitored and method for determining the location of fugitive emissions 
components to be monitored in the field (e.g., tagging, identification 
on a process and instrumentation diagram, etc.). Your fugitive 
emissions monitoring plan must include the written plan developed for 
all of the fugitive emissions components designated as difficult-to-
monitor in accordance with paragraph (g)(2) of this section, and the 
written plan for fugitive emissions components designated as unsafe-to-
monitor in accordance with paragraph (g)(3) of this section.
    (e) Monitoring of fugitive emissions components. Each fugitive 
emissions component, except buried yard piping and associated 
components (e.g., connectors), shall be observed or monitored for 
fugitive emissions during each monitoring survey.
    (f) Initial monitoring survey. You must conduct initial monitoring 
surveys according to the requirements specified in paragraphs (f)(1) 
through (3) of this section.
    (1) At single wellhead only sites and small sites, you must conduct 
an initial monitoring survey using audible, visual, and olfactory 
(AVO), or any other detection methods (e.g., OGI), within 90 days of 
the startup of production, for each fugitive emissions components 
designated facility or by 90 days after the state plan submittal 
deadline (as specified in Sec.  60.5362c(c)), whichever date is later.
    (2) For multi-wellhead only well sites, well sites or centralized 
production facilities that contain the major production and processing 
equipment specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of 
this section, and compressor station sites, you must conduct an initial 
monitoring survey using OGI or Method 21 to appendix A-7 to this part 
within 90 days of the effective date of your state or Tribal plan, for 
each fugitive emissions components designated facility, or by 36 months 
after the state plan submittal deadline (as specified in Sec.  
60.5362c(c)), whichever date is later.
    (3) Notwithstanding the deadlines, specified in paragraphs (f)(1) 
through (3) of this section for each fugitive emissions components 
designated facility located on the Alaskan North Slope, that would be 
subject to monitoring between September and March, you must conduct an 
initial monitoring survey within 6 months, or by the following June 30, 
whichever date is latest.
    (g) Monitoring frequency. A monitoring survey of each fugitive 
emissions components designated facility must be performed as specified 
in paragraph (g)(1) of this section, with the exceptions noted in 
paragraphs (g)(2) through (4) of this section. Monitoring for fugitive 
emissions components designated facilities located at well sites and 
centralized production facilities that have wells located onsite must 
continue at the specified frequencies in paragraphs (g)(1)(i), (ii), 
(iii), (iv) and (vi) of this section until the well closure 
requirements of paragraph (l) of this section are completed.
    (1) A monitoring survey of the fugitive emissions components 
designated facilities must be conducted using the methods and at the 
frequencies specified in paragraphs (g)(1)(i) through (vi) of this 
section.
    (i) A monitoring survey of the fugitive emissions component 
designated facilities located at single wellhead only well sites must 
be conducted at least quarterly using AVO, or any other detection 
method after the initial survey, except as specified in paragraph 
(g)(1)(vi) of this section. Any indications of fugitive emissions using 
these methods are considered fugitive emissions that must be repaired 
in accordance with paragraph (h) of this section.
    (ii) A monitoring survey of the fugitive emissions component 
designated facilities located at small well sites must be conducted at 
least quarterly using AVO, or any other detection method, after the 
initial survey except as specified in paragraph

[[Page 17156]]

(g)(1)(vi) of this section. Any indications of fugitive emissions using 
these methods are considered fugitive emissions that must be repaired 
in accordance with paragraph (h) of this section. At small well sites 
with an uncontrolled storage vessel, a visual inspection of all thief 
hatches and other openings on the storage vessel that are fugitive 
emissions components must be conducted in conjunction with the 
monitoring survey to ensure that they are kept closed and sealed at all 
times except during times of adding or removing material, inspecting or 
sampling material, or during required maintenance operations. If 
evidence of a deviation from this requirement is found, you must take 
corrective action. At small well sites with a separator, a visual 
inspection of all separator dump valves to ensure the dump valve is 
free of debris and not stuck in an open position must be conducted in 
conjunction with the monitoring survey. Any dump valve not operating as 
designed must be repaired.
    (iii) A monitoring survey of the fugitive emissions components 
designated facilities located at multi-wellhead only well sites must be 
conducted in accordance with paragraphs (g)(1)(iii)(A) and (B) of this 
section, except as specified in paragraph (g)(1)(vi) of this section.
    (A) A monitoring survey must be conducted at least quarterly using 
AVO, or any other detection method after the initial survey. Any 
indications of fugitive emissions using these methods are considered 
fugitive emissions that must be repaired in accordance with paragraph 
(h) of this section.
    (B) A monitoring survey must be conducted at least semiannually 
using OGI or Method 21 of appendix A-7 to this part after the initial 
survey. Consecutive semiannual surveys must be conducted at least 4 
months apart and no more than 7 months apart.
    (iv) A monitoring survey of the fugitive emissions components 
designated facilities located at well sites or centralized production 
facilities that contain the major production and processing equipment 
specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of this section 
must be conducted at the frequencies in paragraphs (g)(1)(iv)(E) and 
(F) of this section, except as specified in paragraph (g)(1)(vi) of 
this section.
    (A) One or more controlled storage vessels or tank batteries.
    (B) One or more control devices.
    (C) One or more natural gas-driven process controllers or pumps.
    (D) Two or more pieces of major production and processing equipment 
not specified in paragraphs (g)(1)(iv)(A) through (C) of this section.
    (E) A monitoring survey must be conducted at least bimonthly using 
AVO, or any other detection method after the initial survey. Any 
indications of fugitive emissions using these methods are considered 
fugitive emissions that must be repaired in accordance with paragraph 
(h) of this section. A visual inspection of all thief hatches and other 
openings on storage vessels (or tank batteries) that are fugitive 
emissions components must be conducted in conjunction with the 
monitoring survey to ensure that they are kept closed and sealed at all 
times except during times of adding or removing material, inspecting or 
sampling material, or during required maintenance operations. If 
evidence of a deviation from this requirement is found, you must take 
corrective action. A visual inspection must be conducted of all 
separator dump valves to ensure the dump valve is free of debris and 
not stuck in an open position must be conducted in conjunction with the 
monitoring survey. Any dump valve not operating as designed must be 
repaired.
    (F) A monitoring survey must be conducted at least quarterly using 
OGI or Method 21 of appendix A-7 to this part after the initial survey. 
Consecutive quarterly monitoring surveys must be conducted at least 60 
calendar days apart.
    (v) A monitoring survey of the fugitive emissions components 
designated facility located at a compressor station must be conducted 
at the frequencies in paragraphs (g)(1)(v)(A) and (B) of this section, 
except as specified in paragraph (g)(1)(vi) of this section.
    (A) A monitoring survey must be conducted at least monthly using 
AVO, or any other detection method after the initial survey. Any 
indications of fugitive emissions using these methods are considered 
fugitive emissions that must be repaired in accordance with paragraph 
(h) of this section.
    (B) A monitoring survey must be conducted at least quarterly using 
OGI or Method 21 of appendix A-7 to this part after the initial survey. 
Consecutive quarterly monitoring surveys must be conducted at least 60 
calendar days apart.
    (vi) A monitoring survey of the fugitive emissions components 
designated facility located on the Alaska North Slope must be conducted 
using OGI of this part or Method 21 to appendix A-7 to this part at 
least annually. Consecutive annual monitoring surveys must be conducted 
at least 9 months apart and no more than 13 months apart.
    (2) If you are using Method 21 of appendix A-7 to this part, 
fugitive emissions components that cannot be monitored without 
elevating the monitoring personnel more than 2 meters above the surface 
may be designated as difficult-to-monitor. Fugitive emissions 
components that are designated difficult-to-monitor must meet the 
specifications of paragraphs (g)(2)(i) through (iv) of this section.
    (i) A written plan must be developed for all the fugitive emissions 
components designated difficult-to-monitor. This written plan must be 
incorporated into the fugitive emissions monitoring plan required by 
paragraphs (b), (c), and (d) of this section.
    (ii) The plan must include the identification and location of each 
fugitive emissions component designated as difficult-to-monitor.
    (iii) The plan must include an explanation of why each fugitive 
emissions component designated as difficult-to-monitor is difficult-to-
monitor.
    (iv) The plan must include a schedule for monitoring the difficult-
to-monitor fugitive emissions components at least once per calendar 
year.
    (3) If you are using Method 21 of appendix A-7 to this part, 
fugitive emissions components that cannot be monitored because 
monitoring personnel would be exposed to immediate danger while 
conducting a monitoring survey may be designated as unsafe-to-monitor. 
Fugitive emissions components that are designated unsafe-to-monitor 
must meet the specifications of paragraphs (g)(3)(i) through (iv) of 
this section.
    (i) A written plan must be developed for all the fugitive emissions 
components designated unsafe-to-monitor. This written plan must be 
incorporated into the fugitive emissions monitoring plan required by 
paragraphs (b), (c), and (d) of this section.
    (ii) The plan must include the identification and location of each 
fugitive emissions component designated as unsafe-to-monitor.
    (iii) The plan must include an explanation of why each fugitive 
emissions component designated as unsafe-to-monitor is unsafe-to-
monitor.
    (iv) The plan must include a schedule for monitoring the fugitive 
emissions components designated as unsafe-to-monitor.
    (4) The requirements of paragraphs (g)(1)(iv)(F) and (g)(1)(v)(B) 
of this section are waived during a quarterly monitoring period for any 
fugitive emissions components designated facility located within an 
area that has an average calendar month temperature

[[Page 17157]]

below 0 degrees Fahrenheit for two of three consecutive calendar months 
of a quarterly monitoring period. The calendar month temperature 
average for each month within the quarterly monitoring period must be 
determined using historical monthly average temperatures over the 
previous three years as reported by a National Oceanic and Atmospheric 
Administration source or other source approved by the Administrator. 
The requirements of paragraph (g)(1)(iv) and (v) of this section shall 
not be waived for two consecutive quarterly monitoring periods.
    (h) Repairs. Each identified source of fugitive emissions shall be 
repaired in accordance with paragraphs (h)(1) and (2) of this section.
    (1) A first attempt at repair shall be made in accordance with 
paragraphs (h)(1)(i) and (ii) of this section.
    (i) A first attempt at repair shall be made no later than 15 
calendar days after detection of fugitive emissions that were 
identified using AVO.
    (ii) If you are complying with paragraph (g)(1)(i) through (vi) of 
this section using OGI or Method 21 of appendix A-7 to this part, a 
first attempt at repair shall be made no later than 30 calendar days 
after detection of the fugitive emissions.
    (2) Repair shall be completed as soon as practicable, but no later 
than 15 calendar days after the first attempt at repair as required in 
paragraph (h)(1)(i) of this section, and 30 calendar days after the 
first attempt at repair as required in paragraph (h)(1)(ii) of this 
section.
    (3) Delay of repair will be allowed if the conditions in paragraphs 
(h)(3)(i) or (ii) of this section are met.
    (i) If the repair is technically infeasible, would require a vent 
blowdown, a compressor station shutdown, a well shutdown or well shut-
in, or would be unsafe to repair during operation of the unit, the 
repair must be completed during the next scheduled compressor station 
shutdown for maintenance, scheduled well shutdown, scheduled well shut-
in, after a scheduled vent blowdown, or within 2 years of detecting the 
fugitive emissions, whichever is earliest. A vent blowdown is the 
opening of one or more blowdown valves to depressurize major production 
and processing equipment, other than a storage vessel.
    (ii) If the repair requires replacement of a fugitive emissions 
component or a part thereof, but the replacement cannot be acquired and 
installed within the repair timelines specified in paragraphs (h)(1) 
and (2) of this section due to either of the conditions specified in 
paragraphs (h)(3)(ii)(A) or (B) of this section, the repair must be 
completed in accordance with paragraph (h)(3)(ii)(C) of this section 
and documented in accordance with Sec.  60.5420c(c)(13)(v)(I).
    (A) Valve assembly supplies had been sufficiently stocked but are 
depleted at the time of the required repair.
    (B) A replacement fugitive emissions component or a part thereof 
requires custom fabrication.
    (C) The required replacement must be ordered no later than 10 
calendar days after the first attempt at repair. The repair must be 
completed as soon as practicable, but no later than 30 calendar days 
after receipt of the replacement component, unless the repair requires 
a compressor station or well shutdown. If the repair requires a 
compressor station or well shutdown, the repair must be completed in 
accordance with the timeframe specified in paragraph (h)(3)(i) of this 
section.
    (4) Each identified source of fugitive emissions must be resurveyed 
to complete repair according to the requirements of paragraphs 
(h)(4)(i) through (v) of this section, to ensure that there are no 
fugitive emissions.
    (i) The operator may resurvey the fugitive emissions components to 
verify repair using either Method 21 of appendix A-7 to this part or 
OGI, except as specified in paragraph (h)(4)(v) of this section.
    (ii) For each repair that cannot be made during the monitoring 
survey when the fugitive emissions are initially found, a digital 
photograph must be taken of that component, or the component must be 
tagged during the monitoring survey when the fugitive emissions were 
initially found for identification purposes and subsequent repair. The 
digital photograph must include the date that the photograph was taken 
and must clearly identify the component by location within the site 
(e.g., the latitude and longitude of the component or by other 
descriptive landmarks visible in the picture).
    (iii) Operators that use Method 21 of appendix A-7 to this part to 
resurvey the repaired fugitive emissions components are subject to the 
resurvey provisions specified in paragraphs (h)(4)(iii)(A) and (B) of 
this section.
    (A) A fugitive emissions component is repaired when the Method 21 
instrument indicates a concentration of less than 500 ppmv above 
background or when no soap bubbles are observed when the alternative 
screening procedures specified in section 8.3.3 of Method 21 of 
appendix A-7 to this part are used.
    (B) Operators must use the Method 21 monitoring requirements 
specified in paragraph (c)(8)(ii) of this section or the alternative 
screening procedures specified in section 8.3.3 of Method 21 of 
appendix A-7 to this part.
    (iv) Operators that use OGI to resurvey the repaired fugitive 
emissions components are subject to the resurvey provisions specified 
in paragraphs (h)(4)(iv)(A) and (B) of this section.
    (A) A fugitive emissions component is repaired when the OGI 
instrument shows no indication of visible emissions.
    (B) Operators must use the OGI monitoring requirements specified in 
paragraph (c)(7) of this section.
    (v) For fugitive emissions identified using AVO detection methods, 
the operator may resurvey using those same methods, Method 21 of 
appendix A-7 to this part, or OGI. For operators that use AVO detection 
methods, a fugitive emissions component is repaired when there are no 
indications of fugitive emissions using these methods.
    (i) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to fugitive emissions components 
designated facilities as required by Sec.  60.5410c(i).
    (j) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to fugitive emissions 
components designated facilities as required by Sec.  60.5415c(j).
    (k) Reporting and recordkeeping. You must comply with the reporting 
requirements as specified in Sec.  60.5420c(b)(1) and (8), and the 
recordkeeping requirements as specified in Sec.  60.5420c(c)(13).
    (l) Well closure requirements. You must complete the requirements 
specified in paragraphs (l)(1) through (4) of this section.
    (1) You must submit a well closure plan to the Administrator within 
30 days of the cessation of production from all wells located at the 
well site as specified in Sec.  60.5420c(a)(4)(i). The well closure 
plan must include, at a minimum, the information specified in 
paragraphs (l)(1)(i) through (iii) of this section.
    (i) Description of the steps necessary to close all wells at the 
well site, including permanent plugging of all wells;
    (ii) Description of the financial requirements and disclosure of 
financial assurance to complete closure; and
    (iii) Description of the schedule for completing all activities in 
the well closure plan.
    (2) You must submit a notification as specified in Sec.  
60.5420c(a)(4)(ii) of intent to close the well site to the 
Administrator 60 days before you begin well closure activities.

[[Page 17158]]

    (3) You must conduct a survey of the well site using OGI, including 
each closed well, after completing all well closure activities outlined 
in the well closure plan specified in paragraph (l)(1) of this section. 
If any emissions are imaged by the OGI instrument, then you must take 
steps to eliminate those emissions and you must resurvey the source of 
emissions. You must repeat steps to eliminate emissions and resurvey 
the source of emissions until no emissions are imaged by the OGI 
instrument. You must update the well closure plan specified in 
paragraph (l)(1) of this section to include the video of the OGI survey 
demonstrating closure of all wells at the site.
    (4) You must maintain the records specified in Sec.  
60.5420c(c)(13) and submit the reports specified in Sec.  
60.5420c(b)(8).


Sec.  60.5398c   What alternative GHG standards apply to fugitive 
emissions components designated facilities and what inspection and 
monitoring requirements apply to covers and closed vent systems when 
using an alternative technology?

    This section provides alternative GHG standards for fugitive 
emissions components designated facilities in Sec.  60.5397c and 
alternative continuous inspection and monitoring requirements for 
covers and closed vent systems in Sec.  60.5416c(a)(1)(ii) and (iii), 
(2)(ii) through (iv), and (3)(iii) and (iv). If you choose to use an 
alternative standard under this section, you must submit the 
notification under paragraph (a) of this section. If you choose to 
demonstrate compliance with the alternative GHG standards through 
periodic screening, you are subject to the requirements in paragraph 
(b) of this section. If you choose to demonstrate compliance through a 
continuous monitoring system, you are subject to the requirements in 
paragraph (c) of this section. The technology used for periodic 
screenings under paragraph (b) of this section or continuous monitoring 
under paragraph (c) of this section must be approved in accordance with 
Sec.  60.5398b(d).
    (a) Notification. If you choose to demonstrate compliance with the 
alternative GHG standards in either paragraph (b) or (c) of this 
section, you must notify the Administrator of adoption of the 
alternative standards in the first annual report following 
implementation of the alternative standards, as specified in Sec.  
60.5424c(a). Once you have implemented the alternative standards, you 
must continue to comply with the alternative standards.
    (b) Periodic Screening. You may choose to demonstrate compliance 
for your fugitive emissions components designated facility and 
compliance with continuous inspection and monitoring requirements for 
your covers and closed vent systems through periodic screenings using 
any methane measurement technology approved in accordance with Sec.  
60.5398b(d). If you choose to demonstrate compliance using periodic 
screenings, you must comply with the requirements in paragraphs (b)(1) 
through (5) of this section and comply with the recordkeeping and 
reporting requirements in Sec.  60.5424c.
    (1) You must use one or more alternative test method(s) approved 
per Sec.  60.5398b(d) to conduct periodic screenings.
    (i) The required frequencies for conducting periodic screenings are 
listed in tables 2 and 3 to this subpart. You must choose the 
appropriate frequency for conducting periodic screenings based on the 
minimum aggregate detection threshold of the method used to conduct the 
periodic screenings. You must also use tables 2 and 3 to this subpart 
to determine whether you must conduct an annual fugitive emissions 
survey using OGI, except as provided in paragraph (b)(1)(ii) of this 
section.
    (ii) Use of table 2 or 3 to this subpart is based on the required 
frequency for conducting monitoring surveys in Sec.  60.5397c(g)(1)(i) 
through (v).
    (iii) You may replace one or more individual periodic screening 
events required by table 2 or 3 to this subpart with an OGI survey. The 
OGI survey must be conducted according to the requirements outlined in 
Sec.  60.5397c.
    (iv) If you use multiple methods to conduct periodic screenings, 
you must conduct all periodic screenings, regardless of the method used 
for the individual periodic screening event, at the frequency required 
for the alternative test method with the highest aggregate detection 
threshold (e.g., if you use methods with aggregate detection thresholds 
of 15 kg/hr, your periodic screenings must be conducted monthly). You 
must also conduct an annual OGI survey if an annual OGI survey is 
required for the alternative test method with the highest aggregate 
detection threshold.
    (2) You must develop a monitoring plan that covers the collection 
of fugitive emissions components, covers, and closed vent systems at 
each site where you will use periodic screenings to demonstrate 
compliance. You may develop a site-specific monitoring plan, or you may 
include multiple sites that you own or operate in one plan. At a 
minimum, the monitoring plan must contain the information specified in 
paragraphs (b)(2)(i) through (ix) of this section.
    (i) Identification of each site that will be monitored through 
periodic screening, including latitude and longitude coordinates of the 
site in decimal degrees to an accuracy and precision of five decimals 
of a degree using the North American Datum of 1983.
    (ii) Identification of the alternative test method(s) approved per 
Sec.  60.5398b(d) that will be used for periodic screenings and the 
spatial resolution (i.e., component-level, area-level, or facility-
level) of the technology used for each method.
    (iii) Identification of and contact information for the entities 
that will be performing the periodic screenings.
    (iv) Required frequency for conducting periodic screenings, based 
on the criteria outlined in paragraph (b)(1) of this section.
    (v) If you are required to conduct an annual OGI survey by 
paragraph (b)(1)(i) or (iii) of this section or you choose to replace 
any individual screening event with an OGI survey, your monitoring plan 
must also include the information required by Sec.  60.5397c(b).
    (vi) Procedures for conducting monitoring surveys required by 
paragraphs (b)(5)(ii)(A), (b)(5)(iii)(A), and (b)(5)(iv)(A) of this 
section. At a minimum, your monitoring plan must include the 
information required by Sec.  60.5397c(c)(2), (3), (7), and (8) and 
Sec.  60.5397c(d), as applicable. The provisions of Sec.  
60.5397c(d)(3) do not apply for purposes of conducting monitoring 
surveys required by paragraphs (b)(5)(ii) through (iv) of this section.
    (vii) Procedures and timeframes for identifying and repairing 
fugitive emissions components, covers, and closed vent systems from 
which emissions are detected.
    (viii) Procedures and timeframes for verifying repairs for fugitive 
emissions components, covers, and closed vent systems.
    (ix) Records that will be kept and the length of time records will 
be kept.
    (3) You must conduct the initial screening of your site according 
to the timeframes specified in (b)(3)(i) and (ii) of this section.
    (i) Within 90 days of the effective date of your state or Tribal 
plan for each fugitive emissions components designated facility and 
storage vessel designated facility located at a well site.
    (ii) No later than the final date by which the next monitoring 
survey required by Sec.  60.5397c(g)(1)(i) through

[[Page 17159]]

(v) would have been required to be conducted if you were previously 
complying with the requirements in Sec.  60.5397c and Sec.  60.5416c.
    (4) If you are required to conduct an annual OGI survey by 
paragraph (b)(1)(i) or (iii) of this section, you must conduct OGI 
surveys according to the schedule in paragraphs (b)(4)(i) through (iv) 
of this section.
    (i) You must conduct the initial OGI survey no later than 12 
calendar months after conducting the initial screening survey in 
paragraph (b)(3) of this section.
    (ii) Each subsequent OGI survey must be conducted no later than 12 
calendar months after the previous OGI survey was conducted. Each 
identified source of fugitive emissions during the OGI survey shall be 
repaired in accordance with Sec.  60.5397c(h).
    (iii) If you replace a periodic screening event with an OGI survey 
or you are required to conduct a monitoring survey in accordance with 
paragraph (b)(5)(ii)(A) of this section prior to the date that your 
next OGI survey under paragraph (b)(4)(ii) of this section is due, the 
OGI survey conducted in lieu of the periodic screening event or the 
monitoring survey under paragraph (b)(5)(ii)(A) of this section can be 
used to fulfill the requirements of paragraph (b)(4)(ii) of this 
section. The next OGI survey is required to be conducted no later than 
12 calendar months after the date of the survey conducted under 
paragraph (b)(1)(iv) or (b)(5)(ii)(A) of this section.
    (iv) You cannot use a monitoring survey conducted under paragraph 
(b)(5)(iii)(A) or (b)(5)(iv)(A) of this section to fulfill the 
requirements of paragraph (b)(4)(ii) of this section unless the 
monitoring survey included all fugitive emission components at the 
site.
    (5) You must investigate confirmed detections of emissions from 
periodic screening events and repair each identified source of 
emissions in accordance with paragraphs (b)(5)(i) through (vi) of this 
section.
    (i) You must receive the results of the periodic screening no later 
than 5 calendar days after the screening event occurs.
    (ii) If you use an alternative test method with a facility-level 
spatial resolution to conduct a periodic screening event and the 
results of the periodic screening event indicate a confirmed detection 
of emissions from a designated facility, you must take the actions 
listed in paragraphs (b)(5)(ii)(A) through (C) of this section.
    (A) You must conduct a monitoring survey of the entire fugitive 
emissions components designated facility following the procedures in 
your monitoring plan. During the survey, you must observe each fugitive 
emissions component for fugitive emissions.
    (B) You must inspect all covers and closed vent system(s) with OGI 
or Method 21 of appendix A-7 to this part in accordance with the 
requirements in Sec.  60.5416c(b)(1) through (4), as applicable.
    (C) You must conduct a visual inspection of all covers and closed 
vent systems to identify if there are any defects, as defined in Sec.  
60.5416c(a)(1)(ii), Sec.  60.5416c(a)(2)(iii), or Sec.  
60.5416c(a)(3)(i), as applicable.
    (iii) If you use an alternative test method with an area-level 
spatial resolution to conduct a periodic screening event and the 
results of the periodic screening event indicate a confirmed detection 
of emissions from a designated facility, you must take the actions 
listed in paragraphs (b)(5)(iii)(A) and (B) of this section, as 
applicable.
    (A) You must conduct a monitoring survey of all your fugitive 
emissions components located within a 4-meter radius of the location of 
the periodic screening's confirmed detection. You must follow the 
procedures in your monitoring plan when conducting the survey.
    (B) If the confirmed detection occurred in the portion of a site 
that contains a storage vessel or a closed vent system, you must 
inspect all covers and all closed vent systems that are connected to 
all storage vessels and closed vent systems that are within a 2-meter 
radius of the location of the periodic screening's confirmed detection 
(i.e., you must inspect the whole system that is connected to the 
portion of the system in the radius of the detected event, not just the 
portion of the system that falls within the radius of the detected 
event).
    (1) You must inspect the cover(s) and closed vent system(s) with 
OGI or Method 21 of appendix A-7 to this part in accordance with the 
requirements in Sec.  60.5416c(b)(1) through (4), as applicable.
    (2) You must conduct a visual inspection of the closed vent 
system(s) and cover(s) to identify if there are any defects, as defined 
in Sec.  60.5416c(a)(1)(ii), Sec.  60.5416c(a)(2)(iii), or Sec.  
60.5416c(a)(3)(i), as applicable.
    (iv) If you use an alternative test method with a component-level 
spatial resolution to conduct a periodic screening event and the 
results of the periodic screening event indicate a confirmed detection 
of emissions from a designated facility, you must take the actions 
listed in paragraphs (b)(5)(iv)(A) and (B) of this section, as 
applicable.
    (A) You must conduct a monitoring survey of the all the fugitive 
emissions components located within a 1-meter radius of the location of 
the periodic screening's confirmed detection. You must follow the 
procedures in your monitoring plan when conducting the survey.
    (B) If the confirmed detection occurred in the portion of a site 
that contains a storage vessel or a closed vent system, you must 
inspect all covers and all closed vent systems that are connected to 
all storage vessels and closed vent systems that are within a 0.5-meter 
radius of the location of the periodic screening's confirmed detection 
(i.e., you must inspect the whole system that is connected to the 
portion of the system in the radius of the detected event, not just the 
portion of the system that falls within the radius of the detected 
event).
    (1) You must inspect the cover(s) and closed vent system(s) with 
OGI or Method 21 of appendix A-7 to this part in accordance with the 
requirements in Sec.  60.5416c(b)(1) through (4), as applicable.
    (2) You must conduct a visual inspection of the closed vent 
system(s) and cover(s) to identify if there are any defects, as defined 
in Sec.  60.5416c(a)(1)(ii), Sec.  60.5416c(a)(2)(iii), or Sec.  
60.5416c(a)(3)(i), as applicable.
    (v) You must repair all sources of fugitive emissions in accordance 
with Sec.  60.5397c(h) and all emissions or defects of covers and 
closed vent systems in accordance with Sec.  60.5416c(b)(4), except as 
specified in this paragraph (b)(5)(v). Except as allowed by Sec. Sec.  
60.5397c(h)(3) and 60.5416c(b)(5), all repairs must be completed, 
including the resurvey verifying the repair, within 30 days of 
receiving the results of the periodic screening in paragraph (b)(5)(i) 
of this section.
    (vi) If the results of the periodic screening event in paragraph 
(b)(5)(i) of this section indicate a confirmed detection at a 
designated facility, and the ground-based monitoring survey and 
inspections required by paragraphs (b)(5)(ii) through (iv) of this 
section demonstrate the confirmed detection was caused by a failure of 
a control device used to demonstrate continuous compliance under this 
subpart, you must initiate an investigative analysis to determine the 
underlying primary and other contributing cause(s) of such failure 
within 24 hours of receiving the results of the monitoring survey and/
or inspection. As part of the investigation, you must determine if the 
control

[[Page 17160]]

device is operating in compliance with the applicable requirements of 
Sec. Sec.  60.5415c and 60.5417c, and if not, what actions are 
necessary to bring the control device into compliance with those 
requirements as soon as possible and prevent future failures of the 
control device from the same underlying cause(s).
    (vii) If the results of the inspections required in paragraphs 
(b)(5)(ii) through (iv) of this section indicate that there is an 
emission or defect in your cover or closed vent system, you must 
perform an investigative analysis to determine the underlying primary 
and other contributing cause(s) of emissions from your cover or closed 
vent system within 5 days of completing the inspection required by 
paragraphs (b)(5)(ii) through (iv) of this section. The investigative 
analysis must include a determination as to whether the system was 
operated outside of the engineering design analysis and whether updates 
are necessary for the cover or closed vent system to prevent future 
emissions from the cover and closed vent system.
    (6) You must maintain the records as specified in Sec.  
60.5420c(c)(3) through (c)(6), (c)(13) and (c)(14), and Sec.  
60.5424c(c).
    (7) You must submit reports as specified in Sec.  60.5424c.
    (c) Continuous Monitoring. You may choose to demonstrate compliance 
for your fugitive emissions components designated facility and 
compliance with continuous inspection and monitoring requirements for 
your covers and closed vent systems through continuous monitoring using 
a technology approved in accordance with Sec.  60.5398b(d). If you 
choose to demonstrate compliance using continuous monitoring, you must 
comply and develop a monitoring plan consistent with the requirements 
in paragraphs (c)(1) through (9) of this section and comply with the 
recordkeeping and reporting requirements in Sec.  60.5424c.
    (1) For the purpose of this section, continuous monitoring means 
the ability of a methane monitoring system to determine and record a 
valid methane mass emissions rate or equivalent of designated 
facilities at least once for every 12-hour block.
    (i) The detection threshold of the system must be such that it can 
detect at least 0.40 kg/hr (0.88 lb/hr) of methane.
    (ii) The health of the devices used within the continuous 
monitoring system must be confirmed for power and function at least 
twice every six-hour block.
    (iii) The continuous monitoring system must transmit all applicable 
valid data at least once every 24-hours. The continuous monitoring 
system must transmit all valid data collected, including health checks 
required in paragraph (c)(1)(ii) of this section.
    (iv) The continuous monitoring system must continuously collect 
data as specified in paragraph (c)(1) of this section, except as 
specified in paragraphs (c)(1)(iv)(A) through (D) of this section:
    (A) The rolling 12-month average operational downtime of the 
continuous monitoring system must be less than or equal to 10 percent.
    (B) Operational downtime of the continuous monitoring system is 
defined as a period of time for which any monitor fails to collect or 
transmit data as specified in paragraph (c)(1) of this section or any 
monitor is out-of-control as specified in paragraph (c)(1)(iv)(C) of 
this section.
    (C) A monitor is out-of-control if it fails ongoing quality 
assurance checks, as specified in the alternative test method approved 
under Sec.  60.5398b(d), or if the monitor output is outside of range. 
The beginning of the out-of-control period is defined as the time of 
the failure of the quality assurance check. The end of the out-of-
control period is defined as the time when either the monitor passes a 
subsequent quality assurance check, or a new monitor is installed. The 
out-of-control period for a monitor outside of range starts at the time 
when the monitor first reads outside of range and ends when the monitor 
reads within range again.
    (D) The downtime for the continuous monitoring system must be 
calculated each calendar month. Once 12 months of data are available, 
at the end of each calendar month, you must calculate the 12-month 
average by averaging that month with the previous 11 calendar months. 
You must determine the rolling 12-month average by recalculating the 
12-month average at the end of each month.
    (2) You must develop a monitoring plan that covers the collection 
of fugitive emissions components, covers, and closed vent systems for 
each site where continuous monitoring will be used to demonstrate 
compliance. At a minimum, the monitoring plan must contain the 
information specified in paragraphs (c)(2)(i) through (xii) of this 
section.
    (i) Identification of each site to be monitored through continuous 
monitoring, including latitude and longitude coordinates of the site in 
decimal degrees to an accuracy and precision of at least four decimals 
of a degree using the North American Datum of 1983.
    (ii) Identification of the approved alternative test method(s) 
approved under Sec.  60.5398b(d) used for the continuous monitoring, 
including the detection principle; the manufacturer, make, and model; 
instrument manual, if applicable; and the manufacturer's recommended 
maintenance schedule.
    (iii) If the continuous monitoring system is administered through a 
third-party provider, contact information where the provider can be 
reached 24 hours a day.
    (iv) Number and location of monitors. If the continuous monitoring 
system uses open path technology, you must identify the location of any 
reflectors used. These locations should be identified by latitude and 
longitude coordinates in decimal degrees to an accuracy and precision 
of at least five decimals of a degree using the North American Datum of 
1983.
    (v) Discussion of system calibration requirements, including but 
not limited to, the calibration procedures and calibration schedule for 
the detection systems and meteorology systems.
    (vi) Identification of critical components and infrastructure 
(e.g., power, data systems) and procedures for their repairs.
    (vii) Procedures for out-of-control periods.
    (viii) Procedures for establishing baseline emissions, including 
the identification of any sources with methane emissions not subject to 
this subpart. The procedures for establishing the baseline emissions 
must account for variability in the operation of the site. Operation of 
the site during the development of the baseline emissions must 
represent the site's expected annual production or throughput.
    (ix) Procedures for determining when a fugitive emissions event is 
detected by the continuous monitoring technology.
    (x) Procedures and timeframes for identifying and repairing 
fugitive emissions components, covers, and closed vent systems from 
which emissions are detected.
    (xi) Procedures and timeframes for verifying repairs for fugitive 
emissions components, covers, and closed vent systems.
    (xii) Records that will be kept and the length of time records will 
be kept.
    (3) You must install and begin conducting monitoring with your 
continuous monitoring system according to the timeframes specified in 
paragraphs (c)(3)(i) and (ii) of this section.
    (i) Within 120 days of the effective date of your state or Tribal 
plan for each fugitive emissions components

[[Page 17161]]

designated facility and storage vessel designated facility located at a 
well site.
    (ii) No later than the final date by which the next monitoring 
survey required by Sec.  60.5397c(g)(1)(i) through (v) would have been 
required to be conducted if you were previously complying with the 
requirements in Sec.  60.5397c and Sec.  60.5416c.
    (4) You are subject to the following action-levels as specified in 
paragraphs (c)(4)(i) and (ii) of this section for any designated 
facilities located at a well site, centralized production facility, or 
compressor station.
    (i) For designated facilities located at a wellhead only well site, 
the action levels are as follows.
    (A) The 90-day rolling average action-level is 1.2 kg/hr (2.6 lbs/
hr) of methane over the site-specific baseline emissions.
    (B) The 7-day rolling average action level is 15 kg/hr (34 lbs/hr) 
of methane over site-specific baseline emissions.
    (ii) For designated facilities located at well sites with major 
production and processing equipment (including small well sites), 
centralized production facilities, and compressor stations, the action 
levels are as follows.
    (A) The 90-day rolling average action-level is 1.6 kg/hr (3.6 lbs/
hr) of methane over the site-specific baseline emissions.
    (B) The rolling 7-day average action level is 21 kg/hr (46 lbs/hr) 
of methane over the site-specific baseline emissions.
    (5) You must establish site-specific baseline emissions upon 
initial installation and activation of a continuous monitoring system. 
You must establish the baseline emissions under the conditions outlined 
in paragraphs (c)(5)(i) through (iii) of this section. You must 
determine the baseline emission rates according to paragraphs 
(c)(5)(iv) and (v) of this section. The baseline must be established 
initially and any time there is a major change to the processing 
equipment at a well site (including small well sites), centralized 
production facility, or compressor station.
    (i) Inspect all fugitive emissions components according to the 
requirements in Sec.  60.5397c and covers and closed vent systems 
according to the requirements in Sec.  60.5416c. This includes all 
fugitive emissions components, covers, and closed vent systems, 
regardless of whether they are regulated by this subpart. Repairs of 
any fugitive emissions, leaks, or defects found during the inspection 
must be completed prior to beginning the period in paragraph 
(c)(5)(iii) of this section.
    (ii) Verify control devices (e.g., flares) on all affected sources 
are operating in compliance with the applicable requirements of 
Sec. Sec.  60.5415c and 60.5417c. You must ensure that all control 
devices are operating in compliance with the applicable regulations 
prior to beginning the period in paragraph (b)(5)(iii) of this section. 
Verify that all other methane emission sources (e.g., reciprocating 
engines) located at the site are operating consistent with any 
applicable regulations. You must ensure that these sources are 
operating in compliance with the applicable regulations prior to 
beginning the period in paragraph (b)(5)(iii) of this section.
    (iii) Using the alternative test method approved per Sec.  
60.5398b(d), record the site-level emission rate from your continuous 
monitoring system for 30 operating days. You must minimize any 
activities that are not normal, day-to-day activities during this 30 
operating day period. Document any maintenance activities and the 
period (including the start date and time and end date and time) such 
activities occurred during the 30 operating day period.
    (iv) Determine the site-specific baseline by calculating the mean 
emission rate (kg/hr of methane) for the 30 operating day period, less 
any time periods when maintenance activities were conducted.
    (v) The site-specific baseline emission rate must be no more than 
10 times the applicable 90-day action-level defined in paragraphs 
(c)(4)(i) and (c)(4)(ii) of this section.
    (6) Calculate the emission rate from your site according to 
paragraphs (c)(6)(i) through (iii) of this section. Compare the 
emission rate calculated in this paragraph (c)(6) to the appropriate 
action levels in paragraph (c)(4) of this section to determine whether 
you have exceeded an action level.
    (i) Each calendar day, calculate the daily average mass emission 
rate in kg/hr of methane from your continuous monitoring system.
    (ii) Once the system has been operating for 7 calendar days, at the 
end of each calendar day calculate the 7-day average mass emission rate 
by averaging the mass emission rate from that day with the mass 
emission rate from the previous 6 calendar days. Subtract the site-
specific baseline mass emission rate from the 7-day average mass 
emission rate when comparing the mass emission rate to the applicable 
action level. Determine the 7-day rolling average by recalculating the 
7-day average each calendar day, less the site-specific baseline.
    (iii) Once the system has been operating for 90 calendar days, at 
the end of each calendar day calculate the 90-day average mass emission 
rate by averaging the mass emission rate from that day with the mass 
emission rate from the previous 89 calendar days. Subtract the site-
specific baseline emission rate from the 90-day average mass emission 
rate when comparing the mass emission rate to the applicable action 
level. Determine the 90-day rolling average by recalculating the 90-day 
average each calendar day, less the site-specific baseline.
    (7) Within 5 days of determining that either of your action levels 
in paragraph (c)(4) of this section has been exceeded, you must 
initiate an investigative analysis to determine the underlying primary 
and contributing cause(s) of such exceedance and actions to be taken to 
reduce the mass emission rate below the applicable action level.
    (i) You must complete the investigative analysis and take initial 
steps to bring the mass emission rate below the action level no later 
than 5 days after determining there is an exceedance of the action 
level in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section.
    (ii) You must complete the investigative analysis and take initial 
steps to bring the mass emission rate below the action level no later 
than 30 days after determining there is an exceedance of the action 
level in paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section.
    (8) You must develop a mass emission rate reduction plan if you 
meet any of the criteria in paragraphs (c)(8)(i) through (iii) of this 
section. The plan must describe the action(s) completed to date to 
reduce the mass emission rate below the action level, additional 
measures that you propose to employ to reduce methane emissions below 
the action level, and a schedule for completion of these measures. You 
must submit the plan to the Administrator within 60 days of initially 
determining there is an exceedance of an action level in paragraph 
(c)(4) of this section.
    (i) If, upon completion of the initial actions required under 
paragraph (c)(7) of this section, the average mass emission rate for 
the following 30-day period is not below the applicable action level in 
paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section. The beginning 
of the 30-day period starts on the calendar day following completion of 
the initial actions in paragraph (c)(7) of this section.
    (ii) If, upon completion of the initial actions required under 
paragraph (c)(6) of this section, the average mass emission rate for 
the following 24-hour period is not below the applicable action level 
in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section. The average 
mass emission rate will be the mass

[[Page 17162]]

emission rate calculated according to paragraph (c)(6)(i) of this 
section for the calendar day following completion of the initial 
corrective actions in paragraph (c)(7) of this section.
    (iii) All actions needed to reduce the average mass emission rate 
below the action level require more than 30 days to implement.
    (9) You must maintain the records as specified in Sec.  
60.5420c(c)(3) through (c)(6), (c)(13) and (c)(14), and Sec.  
60.5424c(e). You must submit the reports as specified in Sec.  
60.5420c(b)(1), (b)(3) through (9) and Sec.  60.5424c.


Sec.  60.5400c   What GHG standards apply to process unit equipment 
designated facilities?

    This section applies to process unit equipment designated 
facilities located at an onshore natural gas processing plant. You must 
comply with the requirements of paragraphs (a) through (l) of this 
section to reduce methane emissions from equipment leaks, except as 
provided in Sec.  60.5402c. As an alternative to the standards in this 
section, you may comply with the requirements in Sec.  60.5401c.
    (a) General standards. You must comply with the requirements in 
paragraphs (b) through (d) of this section for each pump in light 
liquid service, pressure relief device in gas/vapor service, valve in 
gas/vapor or light liquid service, and connector in gas/vapor or light 
liquid service, as applicable. You must comply with the requirements in 
paragraph (e) of this section for each open-ended valve or line. You 
must comply with the requirements in paragraph (f) of this section for 
each closed vent system and control device used to comply with 
equipment leak provisions in this section. You must comply with 
paragraph (g) of this section for each pump, valve, and connector in 
heavy liquid service and pressure relief device in light liquid or 
heavy liquid service. You must make repairs as specified in paragraph 
(h) of this section. You must demonstrate initial compliance with the 
standards as specified in paragraph (i) of this section. You must 
demonstrate continuous compliance with the standards as specified in 
paragraph (j) of this section. You must perform the reporting as 
specified in paragraph (k) of this section. You must perform the 
recordkeeping as required in paragraph (l) of this section.
    (1) Each piece of equipment is presumed to have the potential to 
emit methane unless an owner or operator demonstrates that the piece of 
equipment does not have the potential to emit methane. For a piece of 
equipment to be considered not to have the potential to emit methane, 
the methane content of a gaseous stream must be below detection limits 
using Method 18 of appendix A-6 of this part. Alternatively, if the 
piece of equipment is in wet gas service, you may choose to determine 
the methane content of the stream is below the detection limit of the 
methods described in ASTM E168-16(R2023), E169-16(R2022), or E260-96 
(all incorporated by reference, seeSec.  60.17).
    (2) [Reserved]
    (b) Monitoring surveys. You must monitor for leaks using OGI in 
accordance with appendix K to this part, unless otherwise specified in 
paragraphs (c) or (d) of this section.
    (1) Monitoring surveys must be conducted bimonthly.
    (2) Any emissions observed using OGI are defined as a leak.
    (c) Additional requirements for pumps in light liquid service. In 
addition to the requirements in paragraph (b) of this section, you must 
conduct weekly visual inspections of all pumps in light liquid service 
for indications of liquids dripping from the pump seal, except as 
specified in paragraphs (c)(3) and (4) of this section. If there are 
indications of liquids dripping from the pump seal, you must follow the 
procedure specified in either paragraph (c)(1) or (2) of this section.
    (1) Monitor the pump within 5 calendar days using the methods 
specified in Sec.  60.5406c. A leak is detected if any emissions are 
observed using OGI, or if an instrument reading of 2,000 ppmv or 
greater is provided using Method 21 of appendix A-7 to this part.
    (2) Designate the visual indications of liquids dripping as a leak 
and repair the leak as specified in paragraph (h) of this section.
    (3) If any pump is equipped with a closed vent system capable of 
capturing and transporting any leakage from the seal or seals to a 
process, fuel gas system, or a control device that complies with the 
requirements of paragraph (f) of this section, it is exempt from the 
weekly inspection requirements in paragraph (c) of this section.
    (4) Any pump that is located within the boundary of an unmanned 
plant site is exempt from the weekly visual inspection requirements in 
paragraph (c) of this section, provided that each pump is visually 
inspected as often as practicable and at least bimonthly.
    (d) Additional requirements for pressure relief devices in gas/
vapor service. In addition to the requirements in paragraph (b) of this 
section, you must monitor each pressure relief device as specified in 
paragraphs (d)(1) of this section, except as specified in paragraphs 
(d)(2) and (d)(3) of this section.
    (1) You must monitor each pressure relief device within 5 calendar 
days after each pressure release to detect leaks using the methods 
specified in Sec.  60.5406c. A leak is detected if any emissions are 
observed using OGI, or if an instrument reading of 500 ppmv or greater 
is provided using Method 21 of appendix A-7 to this part.
    (2) Any pressure relief device that is located in a 
nonfractionating plant that is monitored only by non-plant personnel 
may be monitored after a pressure release the next time the monitoring 
personnel are onsite or within 30 calendar days after a pressure 
release, whichever is sooner, instead of within 5 calendar days as 
specified in paragraph (d)(1) of this section. No pressure relief 
device described in this paragraph may be allowed to operate for more 
than 30 calendar days after a pressure release without monitoring.
    (3) Any pressure relief device that is routed to a process or fuel 
gas system or equipped with a closed vent system capable of capturing 
and transporting leakage through the pressure relief device to a 
control device as described in paragraph (f) of this section is exempt 
from the requirements of paragraph (d)(1) of this section.
    (e) Open-ended valves or lines. Each open-ended valve or line must 
be equipped with a cap, blind flange, plug, or a second valve, except 
as provided in paragraphs (e)(4) and (5) of this section. The cap, 
blind flange, plug, or second valve must seal the open end of the valve 
or line at all times except during operations requiring process fluid 
flow through the open-ended valve or line.
    (1) If evidence of a leak is found at any time by AVO, or any other 
detection method, a leak is detected.
    (2) Each open-ended valve or line equipped with a second valve must 
be operated in a manner such that the valve on the process fluid end is 
closed before the second valve is closed.
    (3) When a double block-and-bleed system is being used, the bleed 
valve or line may remain open during operations that require venting 
the line between the block valves but shall remain closed at all other 
times.
    (4) Open-ended valves or lines in an emergency shutdown system 
which are designed to open automatically in the event of a process 
upset are exempt from the requirements of this section.
    (5) Open-ended valves or lines containing materials which would 
autocatalytically polymerize or would

[[Page 17163]]

present an explosion, serious overpressure, or other safety hazard if 
capped or equipped with a double block-and-bleed system as specified in 
paragraphs (e) introductory text, (e)(2) and (3) of this section are 
exempt from the requirements of this section.
    (f) Closed vent systems and control devices. Closed vent systems 
used to comply with the equipment leak provisions of this section must 
comply with the requirements in Sec. Sec.  60.5411c and 60.5416c. 
Control devices used to comply with the equipment leak provisions of 
this section must comply with the requirements in Sec. Sec.  60.5412c, 
60.5415c(e), and 60.5417c.
    (g) Pumps, valves, and connectors in heavy liquid service and 
pressure relief devices in light liquid or heavy liquid service. If 
evidence of a potential leak is found at any time by AVO, or any other 
detection method, a leak is detected and must be repaired in accordance 
with paragraph (h) of this section.
    (h) Repair requirements. When a leak is detected, you must comply 
with the requirements of paragraphs (h)(1) through (5) of this section, 
except as provided in paragraph (h)(6) of this section.
    (1) A weatherproof and readily visible identification tag, marked 
with the equipment identification number, must be attached to the 
leaking equipment. The identification tag on equipment may be removed 
after it has been repaired.
    (2) A first attempt at repair must be made as soon as practicable, 
but no later than 5 calendar days after the leak is detected. A first 
attempt at repair is not required if the leak is detected using OGI and 
the equipment identified as leaking would require elevating the repair 
personnel more than 2 meters above a support surface.
    (i) First attempts at repair for pumps in light liquid or heavy 
liquid service include, but are not limited to, the practices described 
in paragraphs (h)(2)(i)(A) and (B) of this section, where practicable.
    (A) Tightening the packing gland nuts.
    (B) Ensuring that the seal flush is operating at design pressure 
and temperature.
    (ii) For each valve where a leak is detected, you must comply with 
paragraphs (h)(2)(ii)(A) (B), (C) or (D) of this section.
    (A) Repack the existing valve with a low-e packing.
    (B) Replace the existing valve with a low-e valve; or
    (C) Perform a drill and tap repair with a low-e injectable packing.
    (D) An owner or operator is not required to utilize a low-e valve 
or low-e packing to replace or repack a valve if the owner or operator 
demonstrates that a low-e valve or low-e packing is not technically 
feasible. Low-e valve or low-e packing that is not suitable for its 
intended use is considered to be technically infeasible. Factors that 
may be considered in determining technical infeasibility include: 
retrofit requirements for installation (e.g., re-piping or space 
limitation), commercial unavailability for valve type, or certain 
instrumentation assemblies.
    (3) Repair of leaking equipment must be completed within 15 
calendar days after detection of each leak, except as provided in 
paragraphs (h)(4), (5) and (6) of this section.
    (4) If the repair for visual indications of liquids dripping for 
pumps in light liquid service can be made by eliminating visual 
indications of liquids dripping, you must make the repair within 5 
calendar days of detection.
    (5) If the repair for AVO or other indication of a leak for open-
ended valves or lines; pumps, valves, or connectors in heavy liquid 
service; or pressure relief devices in light liquid or heavy liquid 
service can be made by eliminating the AVO, or other indication of a 
potential leak, you must make the repair within 5 calendar days of 
detection.
    (6) Delay of repair of equipment for which leaks have been detected 
is allowed if repair within 15 days is technically infeasible without a 
process unit shutdown or as specified in paragraphs (h)(6)(i) through 
(v) of this section. Repair of this equipment shall occur before the 
end of the next process unit shutdown. Monitoring to verify repair must 
occur within 15 days after startup of the process unit.
    (i) Delay of repair of equipment is allowed for equipment which is 
isolated from the process, and which does not have the potential to 
emit methane.
    (ii) Delay of repair for valves and connectors is allowed if the 
conditions in paragraphs (h)(6)(ii)(A) and (B) of this section are met.
    (A) You must demonstrate that emissions of purged material 
resulting from immediate repair are greater than the fugitive emissions 
likely to result from delay of repair, and
    (B) When repair procedures are conducted, the purged material is 
collected and destroyed or recovered in a control device complying with 
paragraph (f) of this section.
    (iii) Delay of repair for pumps is allowed if the conditions in 
paragraphs (h)(6)(iii)(A) and (B) of this section are met.
    (A) Repair requires the use of a dual mechanical seal system that 
includes a barrier fluid system, and
    (B) Repair is completed as soon as practicable, but not later than 
6 months after the leak was detected.
    (iv) If delay of repair is required to repack or replace the valve, 
you may use delay of repair. Delay of repair beyond a process unit 
shutdown is allowed for a valve, if valve assembly replacement is 
necessary during the process unit shutdown, valve assembly supplies 
have been depleted, and valve assembly supplies had been sufficiently 
stocked before the supplies were depleted. Delay of repair beyond the 
next process unit shutdown will not be allowed unless the next process 
unit shutdown occurs sooner than 6 months after the first process unit 
shutdown.
    (v) When delay of repair is allowed for a leaking pump, valve, or 
connector that remains in service, the pump, valve, or connector may be 
considered to be repaired and no longer subject to delay of repair 
requirements if two consecutive bimonthly monitoring results show no 
leak remains.
    (i) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to equipment leaks at onshore natural gas 
processing plants as required by Sec.  60.5410c(g).
    (j) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to equipment leaks at onshore 
natural gas processing plants as required by Sec.  60.5415c(i).
    (k) Reporting. You must perform the reporting requirements as 
specified in Sec.  60.5420c(b)(1) and (10) and Sec.  60.5422c.
    (l) Recordkeeping. You must perform the recordkeeping requirements 
as specified in Sec.  60.5420c(c)(7), (9), and (11) and Sec.  60.5421c.


Sec.  60.5401c   What are the alternative GHG standards for process 
unit equipment designated facilities?

    This section provides alternative standards for process unit 
equipment designated facilities located at an onshore natural gas 
processing plant. You may choose to comply with the standards in this 
section instead of the requirements in Sec.  60.5400c. For purposes of 
the alternative standards provided in this section, you must comply 
with the requirements of paragraphs (a) through (m) of this section to 
reduce methane emissions from equipment leaks, except as provided in 
Sec.  60.5402c.
    (a) General standards. You must comply with the requirements in 
paragraphs (b) of this section for each

[[Page 17164]]

pump in light liquid service. You must comply with the requirements of 
paragraph (c) of this section for each pressure relief device in gas/
vapor service. You must comply with the requirements in paragraph (d) 
of this section for each open-ended valve or line. You must comply with 
the requirements in paragraph (e) of this section for each closed vent 
system and control device used to comply with equipment leak provisions 
in this section. You must comply with paragraph (f) of this section for 
each valve in gas/vapor or light liquid service. You must comply with 
paragraph (g) of this section for each pump, valve, and connector in 
heavy liquid service and pressure relief device in light liquid or 
heavy liquid service. You must comply with paragraph (h) of this 
section for each connector in gas/vapor and light liquid service. You 
must make repairs as specified in paragraph (i) of this section. You 
must demonstrate initial compliance with the standards as specified in 
paragraph (j) of this section. You must demonstrate continuous 
compliance with the standards as specified in paragraph (k) of this 
section. You must perform the reporting requirements as specified in 
paragraph (l) of this section. You must perform the recordkeeping 
requirements as required in paragraph (m) of this section.
    (1) Each piece of equipment is presumed to have the potential to 
emit methane unless an owner or operator demonstrates that the piece of 
equipment does not have the potential to emit methane. For a piece of 
equipment to be considered not to have the potential to emit methane, 
the methane content of a gaseous stream must be below detection limits 
using Method 18 of appendix A-6 to this part. Alternatively, if the 
piece of equipment is in wet gas service, you may choose to determine 
the methane content of the stream is below the detection limit of the 
methods described in ASTM E168-16(R2023), E169-16(R2022), or E260-96 
(all incorporated by reference, see Sec.  60.17).
    (2) [Reserved]
    (b) Pumps in light liquid service. You must monitor each pump in 
light liquid service monthly to detect leaks by the methods specified 
in Sec.  60.5406c, except as provided in paragraphs (b)(2) through (4) 
of this section. A leak is defined as an instrument reading of 2,000 
ppmv or greater. A pump that begins operation in light liquid service 
after the initial startup date for the process unit must be monitored 
for the first time within 30 days after the end of its startup period, 
except for a pump that replaces a leaking pump and except as provided 
in paragraphs (b)(2) through (4) of this section.
    (1) In addition to the requirements in paragraph (b) of this 
section, you must conduct weekly visual inspections of all pumps in 
light liquid service for indications of liquids dripping from the pump 
seal. If there are indications of liquids dripping from the pump seal, 
you must follow the procedure specified in either paragraph (b)(1)(i) 
or (ii) of this section.
    (i) Monitor the pump within 5 days using the methods specified in 
Sec.  60.5406c. A leak is defined as an instrument reading of 2,000 
ppmv or greater.
    (ii) Designate the visual indications of liquids dripping as a 
leak, and repair the leak as specified in paragraph (i) of this 
section.
    (2) Each pump equipped with a dual mechanical seal system that 
includes a barrier fluid system is exempt from the requirements in 
paragraph (b) of this section, provided the requirements specified in 
paragraphs (b)(2)(i) through (vi) of this section are met.
    (i) Each dual mechanical seal system meets the requirements of 
paragraphs (b)(2)(i)(A), (B), or (C) of this section.
    (A) Operated with the barrier fluid at a pressure that is at all 
times greater than the pump stuffing box pressure; or
    (B) Equipped with a barrier fluid degassing reservoir that is 
routed to a process or fuel gas system or connected by a closed vent 
system to a control device that complies with the requirements of 
paragraph (e) of this section; or
    (C) Equipped with a system that purges the barrier fluid into a 
process stream with zero methane emissions to the atmosphere.
    (ii) The barrier fluid system is in heavy liquid service or does 
not have the potential to emit methane.
    (iii) Each barrier fluid system is equipped with a sensor that will 
detect failure of the seal system, the barrier fluid system, or both.
    (iv) Each pump is checked according to the requirements in 
paragraph (b)(1) of this section.
    (v) Each sensor meets the requirements in paragraphs (b)(2)(v)(A) 
through (C) of this section.
    (A) Each sensor as described in paragraph (b)(2)(iii) of this 
section is checked daily or is equipped with an audible alarm.
    (B) You determine, based on design considerations and operating 
experience, a criterion that indicates failure of the seal system, the 
barrier fluid system, or both.
    (C) If the sensor indicates failure of the seal system, the barrier 
fluid system, or both, based on the criterion established in paragraph 
(b)(2)(v)(B) of this section, a leak is detected.
    (3) Any pump that is designated, as described in Sec.  
60.5421c(b)(12), for no detectable emissions, as indicated by an 
instrument reading of less than 500 ppmv above background, is exempt 
from the requirements of paragraphs (b), (b)(1), and (b)(2) of this 
section if the pump:
    (i) Has no externally actuated shaft penetrating the pump housing;
    (ii) Is demonstrated to be operating with no detectable emissions 
as indicated by an instrument reading of less than 500 ppmv above 
background as measured by the methods specified in Sec.  60.5406c; and
    (iii) Is tested for compliance with paragraph (b)(3)(ii) of this 
section initially upon designation, annually, and at other times 
requested by the Administrator.
    (4) If any pump is equipped with a closed vent system capable of 
capturing and transporting any leakage from the seal or seals to a 
process, fuel gas system, or a control device that complies with the 
requirements of paragraph (e) of this section, it is exempt from 
paragraphs (b) introductory text and (b)(1) through (3) of this 
section, and the repair requirements of paragraph (i) of this section.
    (5) Any pump that is designated, as described in Sec.  
60.5421c(b)(13), as an unsafe-to-monitor pump is exempt from the 
monitoring and inspection requirements of paragraphs (b) introductory 
text, (b)(1), and (b)(2)(iv) through (vi) of this section if the 
conditions in paragraph (b)(5)(i) and (ii) are met.
    (i) You demonstrate that the pump is unsafe-to-monitor because 
monitoring personnel would be exposed to an immediate danger as a 
consequence of complying with paragraph (b) of this section; and
    (ii) You have a written plan that requires monitoring of the pump 
as frequently as practicable during safe-to-monitor times, but not more 
frequently than the periodic monitoring schedule otherwise applicable, 
and you repair the equipment according to the procedures in paragraph 
(i) of this section if a leak is detected.
    (6) Any pump that is located within the boundary of an unmanned 
plant site is exempt from the weekly visual inspection requirements in 
paragraph (b)(1) and (b)(2)(iv) of this section, and the daily 
requirements of paragraph (b)(2)(v) of this section, provided that each 
pump is visually inspected as often as practicable and at least 
monthly.

[[Page 17165]]

    (c) Pressure relief devices in gas/vapor service. You must monitor 
each pressure relief device quarterly using the methods specified in 
Sec.  60.5406c. A leak is defined as an instrument reading of 500 ppmv 
or greater above background.
    (1) In addition to the requirements in paragraph (c) of this 
section, after each pressure release, you must monitor each pressure 
relief device within 5 calendar days after each pressure release to 
detect leaks. A leak is detected if an instrument reading of 500 ppmv 
or greater is provided using the methods specified in Sec.  
60.5406c(b).
    (2) Any pressure relief device that is located in a 
nonfractionating plant that is monitored only by non-plant personnel 
may be monitored after a pressure release the next time the monitoring 
personnel are onsite, or within 30 calendar days after a pressure 
release, whichever is sooner, instead of within 5 calendar days as 
specified in paragraph (c)(1) of this section.
    (3) No pressure relief device described in paragraph (c)(2) of this 
section may be allowed to operate for more than 30 calendar days after 
a pressure release without monitoring.
    (4) Any pressure relief device that is routed to a process or fuel 
gas system or equipped with a closed vent system capable of capturing 
and transporting leakage through the pressure relief device to a 
control device as described in paragraph (e) of this section is exempt 
from the requirements of paragraphs (c) introductory text and (c)(1) of 
this section.
    (5) Pressure relief devices equipped with a rupture disk are exempt 
from the requirements of paragraphs (c)(1) and (2) of this section 
provided you install a new rupture disk upstream of the pressure relief 
device as soon as practicable, but no later than 5 calendar days after 
each pressure release, except as provided in paragraph (i)(4) of this 
section.
    (d) Open-ended valves or lines. Each open-ended valve or line must 
be equipped with a cap, blind flange, plug, or a second valve, except 
as provided in paragraphs (d)(4) and (5) of this section. The cap, 
blind flange, plug, or second valve must seal the open end of the valve 
or line at all times except during operations requiring process fluid 
flow through the open-ended valve or line.
    (1) If evidence of a leak is found at any time by AVO, or any other 
detection method, a leak is detected and must be repaired in accordance 
with paragraph (i) of this section. A leak is defined as an instrument 
reading of 500 ppmv or greater if Method 21 of appendix A-7 to this 
part is used.
    (2) Each open-ended valve or line equipped with a second valve must 
be operated in a manner such that the valve on the process fluid end is 
closed before the second valve is closed.
    (3) When a double block-and-bleed system is being used, the bleed 
valve or line may remain open during operations that require venting 
the line between the block valves but shall remain closed at all other 
times.
    (4) Open-ended valves or lines in an emergency shutdown system 
which are designed to open automatically in the event of a process 
upset are exempt from the requirements of paragraphs (d), and (d)(1) 
through (3) of this section.
    (5) Open-ended valves or lines containing materials which would 
autocatalytically polymerize or would present an explosion, serious 
overpressure, or other safety hazard if capped or equipped with a 
double block-and-bleed system as specified in paragraphs (d) 
introductory text and (d)(2) and (3) of this section are exempt from 
the requirements of this section.
    (e) Closed vent systems and control devices. Closed vent systems 
used to comply with the equipment leak provisions of this section must 
comply with the requirements in Sec. Sec.  60.5411c and 60.5416c. 
Control devices used to comply with the equipment leak provisions of 
this section must comply with the requirements in Sec. Sec.  60.5412c, 
60.5415c(e), and 60.5417c.
    (f) Valves in gas/vapor and light liquid service. You must monitor 
each valve in gas/vapor and in light liquid service quarterly to detect 
leaks by the methods specified in Sec.  60.5406c, except as provided in 
paragraphs (h)(3) through (5) of this section.
    (1) A valve that begins operation in gas/vapor service or in light 
liquid service after the initial startup date for the process unit must 
be monitored for the first time within 90 days after the end of its 
startup period to ensure proper installation, except for a valve that 
replaces a leaking valve and except as provided in paragraphs (h)(3) 
through (5) of this section.
    (2) An instrument reading of 500 ppmv or greater is a leak. You 
must repair each leaking valve according to the requirements in 
paragraph (i) of this section.
    (3) Any valve that is designated, as described in Sec.  
60.5421c(b)(12), for no detectable emissions, as indicated by an 
instrument reading of less than 500 ppmv above background, is exempt 
from the requirements of paragraphs (f) of this section if the valve:
    (i) Has no externally actuating mechanism in contact with the 
process fluid;
    (ii) Is operated with emissions less than 500 ppmv above background 
as determined by the methods specified in Sec.  60.5406c; and
    (iii) Is tested for compliance with paragraph (f)(3)(ii) of this 
section initially upon designation, annually, and at other times 
requested by the Administrator.
    (4) Any valve that is designated, as described in Sec.  
60.5421c(b)(13), as an unsafe-to-monitor pump is exempt from the 
monitoring requirements of paragraph (f) of this section if the 
requirements in paragraphs (f)(4)(i) and (ii) of this section are met.
    (i) You demonstrate that the valve is unsafe-to-monitor because 
monitoring personnel would be exposed to an immediate danger as a 
consequence of complying with paragraph (f) of this section; and
    (ii) You have a written plan that requires monitoring of the valve 
as frequently as practicable during safe-to-monitor times, but not more 
frequently than the periodic monitoring schedule otherwise applicable, 
and you repair the equipment according to the procedures in paragraph 
(i) of this section if a leak is detected.
    (5) Any valve that is designated, as described in Sec.  
60.5421c(b)(14), as a difficult-to-monitor valve is exempt from the 
monitoring requirements of paragraph (h) of this section if the 
requirements in paragraph (f)(5)(i) through (iii) of this section are 
met.
    (i) You demonstrate that the valve cannot be monitored without 
elevating the monitoring personnel more than 2 meters above a support 
surface.
    (ii) The process unit within which the valve is located has less 
than 3.0 percent of its total number of valves designated as difficult-
to-monitor.
    (iii) You have a written plan that requires monitoring of the at 
least once per calendar year.
    (g) Pumps, valves, and connectors in heavy liquid service and 
pressure relief devices in light liquid or heavy liquid service. If 
evidence of a potential leak is found at any time by AVO, or any other 
detection method, you must comply with either paragraph (g)(1) or (2) 
of this section.
    (1) You must monitor the equipment within 5 calendar days by the 
method specified in Sec.  60.5406c and repair any leaks detected 
according to paragraph (i) of this section. An instrument reading of 
10,000 ppmv or greater is defined as a leak.
    (2) You must designate the AVO, or other indication of a leak as a 
leak and repair the leak according to paragraph (i) of this section.

[[Page 17166]]

    (h) Connectors in gas/vapor service and in light liquid service. 
You must initially monitor all connectors in the process unit for leaks 
by the later of either 12 months after the compliance date or 12 months 
after initial startup. If all connectors in the process unit have been 
monitored for leaks prior to the compliance date, no initial monitoring 
is required provided either no process changes have been made since the 
monitoring or the owner or operator can determine that the results of 
the monitoring, with or without adjustments, reliably demonstrate 
compliance despite process changes. If required to monitor because of a 
process change, you are required to monitor only those connectors 
involved in the process change.
    (1) You must monitor all connectors in gas/vapor service and in 
light liquid service annually, except as provided in paragraph (e) of 
this section or paragraph (h)(2) of this section.
    (2) Any connector that is designated, as described in Sec.  
60.5421c(b)(13), as an unsafe-to-monitor connector is exempt from the 
requirements of paragraphs (h) and (h)(1) of this section if the 
requirements of paragraphs (h)(2)(i) and (ii) of this section are met.
    (i) You demonstrate the connector is unsafe-to-monitor because 
monitoring personnel would be exposed to an immediate danger as a 
consequence of complying with paragraphs (h) and (h)(1) of this 
section; and
    (ii) You have a written plan that requires monitoring of the 
connector as frequently as practicable during safe-to-monitor times, 
but not more frequently than the periodic monitoring schedule otherwise 
applicable, and you repair the equipment according to the procedures in 
paragraph (i) of this section if a leak is detected.
    (3) Inaccessible, ceramic, or ceramic-line connectors.
    (i) Any connector that is inaccessible or that is ceramic or 
ceramic-lined (e.g., porcelain, glass, or glass-lined), is exempt from 
the monitoring requirements of paragraphs (h) and (h)(1) of this 
section, from the leak repair requirements of paragraph (i) of this 
section, and from the recordkeeping and reporting requirements of 
Sec. Sec.  60.5421c and 60.5422c. An inaccessible connector is one that 
meets any of the specifications in paragraphs (h)(3)(i)(A) through (F) 
of this section, as applicable.
    (A) Buried.
    (B) Insulated in a manner that prevents access to the connector by 
a monitor probe.
    (C) Obstructed by equipment or piping that prevents access to the 
connector by a monitor probe.
    (D) Unable to be reached from a wheeled scissor-lift or hydraulic-
type scaffold that would allow access to connectors up to 7.6 meters 
(25 feet) above the ground.
    (E) Inaccessible because it would require elevating monitoring 
personnel more than 2 meters (7 feet) above a permanent support surface 
or would require the erection of scaffold.
    (F) Not able to be accessed at any time in a safe manner to perform 
monitoring. Unsafe access includes, but is not limited to, the use of a 
wheeled scissor-lift on unstable or uneven terrain, the use of a 
motorized man-lift basket in areas where an ignition potential exists, 
or access would require near proximity to hazards such as electrical 
lines or would risk damage to equipment.
    (ii) If any inaccessible, ceramic, or ceramic-lined connector is 
observed by AVO, or other means to be leaking, the indications of a 
leak to the atmosphere by AVO or other means must be eliminated as soon 
as practicable.
    (4) Connectors which are part of an instrumentation systems and 
inaccessible, ceramic, or ceramic-lined connectors meeting the 
provisions of paragraph (h)(3) of this section, are not subject to the 
recordkeeping requirements of Sec.  60.5421c(b)(1).
    (i) Repair requirements. When a leak is detected, comply with the 
requirements of paragraphs (i)(1) through (5) of this section, except 
as provided in paragraph (i)(6) of this section.
    (1) A weatherproof and readily visible identification tag, marked 
with the equipment identification number, must be attached to the 
leaking equipment. The identification tag on the equipment may be 
removed after it has been repaired.
    (2) A first attempt at repair must be made as soon as practicable, 
but no later than 5 calendar days after the leak is detected.
    (i) First attempts at repair for pumps in light liquid or heavy 
liquid service include, but are not limited to, the practices described 
in paragraphs (i)(2)(i)(A) and (B) of this section, where practicable.
    (A) Tightening the packing gland nuts.
    (B) Ensuring that the seal flush is operating at design pressure 
and temperature.
    (ii) For each valve where a leak is detected, you must comply with 
paragraphs (i)(2)(ii)(A), (B) or (C), and (D) of this section.
    (A) Repack the existing valve with a low-e packing.
    (B) Replace the existing valve with a low-e valve; or
    (C) Perform a drill and tap repair with a low-e injectable packing.
    (D) An owner or operator is not required to utilize a low-e valve 
or low-e packing to replace or repack a valve if the owner or operator 
demonstrates that a low-e valve or low-e packing is not technically 
feasible. Low-e valve or low-e packing that is not suitable for its 
intended use is considered to be technically infeasible. Factors that 
may be considered in determining technical infeasibility include: 
retrofit requirements for installation (e.g., re-piping or space 
limitation), commercial unavailability for valve type, or certain 
instrumentation assemblies.
    (3) Repair of leaking equipment must be completed within 15 
calendar days after detection of each leak, except as provided in 
paragraphs (i)(4), (5) and (6) of this section.
    (4) If the repair for visual indications of liquids dripping for 
pumps in light liquid service can be made by eliminating visual 
indications of liquids dripping, you must make the repair within 5 
calendar days of detection.
    (5) If the repair for AVO or other indication of a leak for open-
ended lines or valves; pumps, valves, or connectors in heavy liquid 
service; or pressure relief devices in light liquid or heavy liquid 
service can be made by eliminating the AVO, or other indication of a 
potential leak, you must make the repair within 5 calendar days of 
detection.
    (6) Delay of repair of equipment for which leaks have been detected 
will be allowed if repair within 15 calendar days is technically 
infeasible without a process unit shutdown or as specified in 
paragraphs (i)(6)(i) through (v) of this section. Repair of this 
equipment shall occur before the end of the next process unit shutdown. 
Monitoring to verify repair must occur within 15 calendar days after 
startup of the process unit.
    (i) Delay of repair of equipment will be allowed for equipment 
which is isolated from the process, and which does not have the 
potential to emit methane.
    (ii) Delay of repair for valves and connectors will be allowed if 
the conditions in paragraphs (i)(6)(ii)(A) and (B) are met.
    (A) You demonstrate that emissions of purged material resulting 
from immediate repair are greater than the fugitive emissions likely to 
result from delay of repair, and
    (B) When repair procedures are conducted, the purged material is

[[Page 17167]]

collected and destroyed or recovered in a control device complying with 
paragraph (e) of this section.
    (iii) Delay of repair for pumps will be allowed if the conditions 
in paragraphs (i)(6)(iii)(A) and (B) of this section are met.
    (A) Repair requires the use of a dual mechanical seal system that 
includes a barrier fluid system, and
    (B) Repair is completed as soon as practicable, but not later than 
6 months after the leak was detected.
    (iv) If delay of repair is required to repack or replace the valve, 
you may use delay of repair. Delay of repair beyond a process unit 
shutdown will be allowed for a valve, if valve assembly replacement is 
necessary during the process unit shutdown, valve assembly supplies 
have been depleted, and valve assembly supplies had been sufficiently 
stocked before the supplies were depleted. Delay of repair beyond the 
next process unit shutdown will not be allowed unless the next process 
unit shutdown occurs sooner than 6 months after the first process unit 
shutdown.
    (v) When delay of repair is allowed for a leaking pump, valve, or 
connector that remains in service, the pump, valve, or connector may be 
considered to be repaired and no longer subject to delay of repair 
requirements if two consecutive monthly monitoring results show no leak 
remains.
    (j) Initial compliance. You must demonstrate initial compliance 
with the standards that apply to equipment leaks at onshore natural gas 
processing plants as required by Sec.  60.5410c(g).
    (k) Continuous compliance. You must demonstrate continuous 
compliance with the standards that apply to equipment leaks at onshore 
natural gas processing plants as required by Sec.  60.5415c(i).
    (l) Reporting. You must perform the reporting requirements as 
specified in Sec.  60.5420c(b)(1) and (b)(10) and Sec.  60.5422c.
    (m) Recordkeeping. You must perform the recordkeeping requirements 
as specified in Sec.  60.5420c(c)(7), (9), (11), and Sec.  60.5421c.


Sec.  60.5402c   What are the exceptions to the GHG standards for 
process unit equipment designated facilities?

    (a) You may comply with the following exceptions to the provisions 
of Sec. Sec.  60.5400c(a) and 60.5401c(a), as applicable.
    (b) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and 
connectors in gas/vapor service and in light liquid service that are 
located at a nonfractionating plant that does not have the design 
capacity to process 283,200 standard cubic meters per day (scmd) (10 
million standard cubic feet per day) or more of field gas may comply 
with the exceptions specified in paragraphs (b)(1) or (2) of this 
section.
    (1) You are exempt from bimonthly OGI monitoring as required under 
Sec.  60.5400c(b).
    (2) You are exempt from the routine Method 21 of appendix A-7 to 
this part monitoring requirements of Sec.  60.5401c(b), (c), (f), and 
(h), if complying with the alternative standards of Sec.  60.5401c.
    (c) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and 
connectors in gas/vapor service and in light liquid service within a 
process unit that is located in the Alaskan North Slope are exempt from 
the monitoring requirements Sec.  60.5400c(b) and (c) and Sec.  
60.5401c(b), (c), (f) and (h).
    (d) You may use the following provisions instead of Sec.  
60.5403c(e):
    (1) Equipment is in heavy liquid service if the weight percent 
evaporated is 10 percent or less at 150 degrees Celsius (302 degrees 
Fahrenheit) as determined by ASTM D86-96 (incorporated by reference, 
see Sec.  60.17).
    (2) Equipment is in light liquid service if the weight percent 
evaporated is greater than 10 percent at 150 [deg]Celsius (302 [deg]F) 
as determined by ASTM D86-96 (incorporated by reference, see Sec.  
60.17).
    (e) Equipment that is in vacuum service, except connectors in gas/
vapor and light liquid service, is excluded from the requirements of 
Sec.  60.5400c(b) through (g), if it is identified as required in Sec.  
60.5421c(b)(15). Equipment that is in vacuum service is excluded from 
the requirements of Sec.  60.5401c(b) through (g) if it is identified 
as required in Sec.  60.5421c(b)(15).
    (f) Equipment that you designate as having the potential to emit 
methane less than 300 hr/yr is excluded from the requirements of Sec.  
60.5400c(b) through (g) and Sec.  60.5401c(b) through (h), if it is 
identified as required in Sec.  60.5421c(b)(16) and it meets any of the 
conditions specified in paragraphs (f)(1) through (3) of this section.
    (1) The equipment has the potential to emit methane only during 
startup and shutdown.
    (2) The equipment has the potential to emit methane only during 
process malfunctions or other emergencies.
    (3) The equipment is backup equipment that has the potential to 
emit methane only when the primary equipment is out of service.

Model Rule--Test Methods and Performance Testing


Sec.  60.5405c   What test methods and procedures must I use for my 
centrifugal compressor and reciprocating compressor designated 
facilities?

    (a) You must use one of the methods described in paragraph (a)(1) 
and (2) of this section to screen for emissions or leaks from the 
reciprocating compressor rod packing when complying with Sec.  
60.5393c(a)(2)(iv) and from the compressor dry and wet seal vents when 
complying with Sec.  60.5392c(a)(2)(i)(A).
    (1) Optical gas imaging instrument. Use an optical gas imaging 
instrument for equipment leak detection as specified in either 
paragraph (a)(1)(i) or (ii) of this section. For the purposes of 
paragraphs (a)(1)(i) and (ii) of this section, any visible emissions 
observed by the optical gas imaging instrument from reciprocating rod 
packing or compressor dry or wet seal vent is a leak.
    (i) Optical gas imaging instrument as specified in appendix K of 
this part. For reciprocating compressor and centrifugal compressor 
designated facilities with wet or dry seals located at onshore natural 
gas processing plants, use an optical gas imaging instrument to screen 
for emissions from reciprocating rod packing or centrifugal compressor 
dry or wet seal vent in accordance with the protocol specified in 
appendix K of this part.
    (ii) Optical gas imaging instrument as specified in Sec.  60.5397c 
of this subpart. For reciprocating compressor and centrifugal 
compressor designated facilities with wet or dry seals located at 
centralized production facilities, compressor stations, or other 
location that is not an onshore natural gas processing plant, use an 
optical gas imaging instrument to screen for emissions from 
reciprocating rod packing or centrifugal compressor with wet or dry 
seals in accordance with the elements of Sec.  60.5397c(c)(7).
    (2) Method 21. Use Method 21 in appendix A-7 to this part according 
to Sec.  60.5403c(b)(1) and (2). For the purposes of this section, an 
instrument reading of 500 ppmv above background or greater is a leak.
    (b) You must determine natural gas volumetric flow rate using a 
rate meter which meets the requirement in Method 2D in appendix A-1 to 
this part. Rate meters must be calibrated on an annual basis according 
to the requirements in Method 2D.
    (c) You must use a high-volume sampler to measure emissions of the 
reciprocating compressor rod packing or centrifugal compressor dry or 
wet seal

[[Page 17168]]

vent in accordance with paragraphs (c)(1) through (7) of this section.
    (1) You must use a high-volume sampler designed to capture the 
entirety of the emissions from the applicable vent and measure the 
entire range of methane concentrations being emitted as well as the 
total volumetric flow at standard conditions. You must develop a 
standard operating procedure for this device and document these 
procedures in the appropriate monitoring plan. In order to get reliable 
results, persons using this device should be knowledgeable in its 
operation and the requirements in this section.
    (2) This procedure may involve hazardous materials, operations, and 
equipment. This procedure may not address all of the safety problems 
associated with its use. It is the responsibility of the user of this 
procedure to establish appropriate safety and health practices and 
determine the applicability of regulatory limitations prior to 
performing this procedure.
    (3) The high-volume sampler must include a methane gas sensor(s) 
which meets the requirements in paragraphs (c)(3)(i) through (iii) of 
this section.
    (i) The methane sensor(s) must be selective to methane with minimal 
interference, less than 2.5 percent for the sum of responses to other 
compounds in the gas matrix. You must document the minimal interference 
though empirical testing or through data provided by the manufacturer 
of the sensor.
    (ii) The methane sensor(s) must have a measurement range over the 
entire expected range of concentrations.
    (iii) The methane sensor(s) must be capable of taking a measurement 
once every second, and the data system must be capable of recording 
these results for each sensor at all times during operation of the 
sampler.
    (4) The high-volume sampler must be designed such that it is 
capable of sampling sufficient volume in order to capture all emissions 
from the applicable vent. Your high-volume sampler must include a flow 
measurement sensor(s) which meets the requirements of paragraphs 
(c)(4)(i) and (ii) of this section.
    (i) The flow measurement sensor must have a measurement range over 
the entire expected range of flow rates sampled. If needed multiple 
sensors may be used to capture the entire range of expected flow rates.
    (ii) The flow measurement sensor(s)must be capable of taking a 
measurement once every second, and the data system must be capable of 
recording these results for each sensor at all times during operation 
of the sampler.
    (5) You must calibrate your methane sensor(s) according to the 
procedures in paragraphs (c)(5)(i)(A) and (B) of this section, and flow 
measurement sensors must be calibrated according to the procedures in 
paragraph (c)(5)(ii) of this section.
    (i) For Methane sensor calibration:
    (A) Initially and on a semi-annual basis, determine the linearity 
at four points through the measurement range for each methane sensor 
using methane gaseous calibration cylinder standards. At each point, 
the difference between the cylinder value and the sensor reading must 
be less than 5 percent of the respective calibration gas value. If the 
sensor does not meet this requirement, perform corrective action on the 
sensor, and do not use the sampler until these criteria can be met.
    (B) Prior to and at the end of each testing day, challenge each 
sensor at two points, a low point, and a mid-point, using methane 
gaseous calibration cylinder standards. At each point, the difference 
between the cylinder value and the sensor reading must be less than 5 
percent of the respective calibration gas value. If the sensor does not 
meet this requirement, perform corrective action on the sensor and do 
not use the sampler again until these criteria can be met. If the post-
test calibration check fails at either point, invalidate the data from 
all tests performed subsequent to the last passing calibration check.
    (ii) Flow measurement sensors must meet the requirements in Method 
2D in appendix A-1 to this part. Rate meters must be calibrated on an 
annual basis according to the requirements in Method 2D. If your flow 
sensor relies on ancillary temperature and pressure measurements to 
correct the flow rate to standard conditions, the temperature and 
pressure sensors must also be calibrated on an annual basis. Standard 
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92 
in. Hg).
    (6) You must conduct sampling of the reciprocating compressor rod 
packing or centrifugal compressor dry or wet seal vent in accordance 
with the procedures in paragraphs (c)(6)(i) through (v) of this 
section.
    (i) The instrument must be operated consistent with manufacturer 
recommendations; users are encouraged to develop a standard operating 
procedure to document the exact procedures used for sampling.
    (ii) Identify the rod packing or centrifugal compressor dry or wet 
seal vent to be measured and record the signal to noise ratio (S/N) of 
the engine. Collect a background methane sample in parts per million by 
volume (ppmv) for a minimum of one minute and record the result along 
with the date and time.
    (iii) Approach the vent with the sample hose and adjust the sampler 
so that you are measuring at the full flow rate. Then, adjust the flow 
rate to ensure the measured methane concentration is within the 
calibrated range of the methane sensor and minimum methane 
concentration is at least 2 ppmv higher than the background 
concentration. Sample for a period of at least one minute and record 
the average flow rate in standard cubic feet per minute and the methane 
sample concentration in ppmv, along with the date and time. Standard 
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92 
in. Hg).
    (iv) Calculate the leak rate according to the following equation:
    [GRAPHIC] [TIFF OMITTED] TR08MR24.037
    
Where:

CH4<INF>B</INF> = background methane concentration, ppmv
CH4<INF>S</INF> = methane sample concentration, ppmv
V = Average flow rate of the sampler, scfm
Q = Methane emission rate, scfm

    (v) You must collect at least three separate one-minute 
measurements and determine the average leak rate. The relative percent 
difference of these three separate samples should be less than 10 
percent.
    (7) If the measured natural gas flow determined as specified in 
paragraph (c)(6) of this section exceeds 70.0 percent of the 
manufacturer's reported maximum sampling flow rate you must either use 
a temporary or permanent

[[Page 17169]]

flow meter according to paragraph (b) of this section or use another 
method meeting the requirements in paragraph (d) of this section to 
determine the leak or flow rate.
    (d) As an alternative to a high-volume sampler, you may use any 
other method that has been validated in accordance with the procedures 
specified in Method 301 in appendix A to 40 CFR part 63, subject to 
Administrator approval, as specified in Sec.  60.8(b).


Sec.  60.5406c   What test methods and procedures must I use for my 
process unit equipment designated facilities?

    (a) In conducting the performance tests required in Sec.  60.8, you 
must use as reference methods and procedures the test methods in 
appendix A to this part or other methods and procedures as specified in 
this section, except as provided in Sec.  60.8(b).
    (b) You must determine compliance with the standards in Sec.  
60.5401c as follows:
    (1) Method 21 of appendix A-7 to this part shall be used to 
determine the presence of leaking sources. The instrument shall be 
calibrated before use each day of its use by the procedures specified 
in Method 21 of appendix A-7 to this part. The following calibration 
gases shall be used:
    (i) Zero air (less than 10 ppmv of hydrocarbon in air); and
    (ii) A mixture of methane or n-hexane and air at a concentration no 
more than 2,000 ppmv greater than the leak definition concentration of 
the equipment monitored. If the monitoring instrument's design allows 
for multiple calibration scales, then the lower scale shall be 
calibrated with a calibration gas that is no higher than 2,000 ppmv 
above the concentration specified as a leak, and the highest scale 
shall be calibrated with a calibration gas that is approximately or 
equal to 10,000 ppmv. If only one scale on an instrument will be used 
during monitoring, you need not calibrate the scales that will not be 
used during that day's monitoring.
    (iii) Verification that your monitoring equipment meets the 
requirements specified in Section 6.0 of Method 21 of appendix A-7 to 
this part. For purposes of instrument capability, the leak definition 
shall be 500 ppmv or greater methane using a FID-based instrument for 
valves and connectors and 2,000 ppmv methane or greater for pumps. If 
you wish to use an analyzer other than a FID-based instrument, you must 
develop a site-specific leak definition that would be equivalent to 500 
ppmv methane using a FID-based instrument (e.g., 10.6 eV PID with a 
specified isobutylene concentration as the leak definition would 
provide equivalent response to your compound of interest).
    (2) The instrument must be calibrated before use each day of its 
use by the procedures specified in Method 21 of appendix A-7 to this 
part. At minimum, you must also conduct precision tests at the interval 
specified in Method 21 of appendix A-7 to this part, Section 8.1.2, and 
a calibration drift assessment at the end of each monitoring day. The 
calibration drift assessment must be conducted as specified in 
paragraph (b)(2)(i) of this section. Corrective action for drift 
assessments is specified in paragraphs (b)(2)(ii) and (iii) of this 
section.
    (i) Check the instrument using the same calibration gas that was 
used to calibrate the instrument before use. Follow the procedures 
specified in Method 21 of appendix A-7 to this part, Section 10.1, 
except do not adjust the meter readout to correspond to the calibration 
gas value. If multiple scales are used, record the instrument reading 
for each scale used. Divide the arithmetic difference of the initial 
and post-test calibration response by the corresponding calibration gas 
value for each scale and multiply by 100 to express the calibration 
drift as a percentage.
    (ii) If a calibration drift assessment shows a negative drift of 
more than 10 percent, then all equipment with instrument readings 
between the fugitive emission definition multiplied by (100 minus the 
percent of negative drift) divided by 100 and the fugitive emission 
definition that was monitored since the last calibration must be re-
monitored.
    (iii) If any calibration drift assessment shows a positive drift of 
more than 10 percent from the initial calibration value, then, at the 
owner/operator's discretion, all equipment with instrument readings 
above the fugitive emission definition and below the fugitive emission 
definition multiplied by (100 plus the percent of positive drift) 
divided by 100 monitored since the last calibration may be re-
monitored.
    (c) You shall determine compliance with the no detectable emission 
standards in Sec.  60.5401c(b), (c), and (f) as specified in paragraphs 
(c)(1) and (2) of this section.
    (1) The requirements of paragraph (b) of this section shall apply.
    (2) Method 21 of appendix A-7 to this part shall be used to 
determine the background level. All potential leak interfaces shall be 
traversed as close to the interface as possible. The arithmetic 
difference between the maximum concentration indicated by the 
instrument and the background level is compared with 500 ppmv for 
determining compliance.
    (d) You shall demonstrate that a piece of equipment is in light 
liquid service by showing that all of the following conditions apply:
    (1) The vapor pressure of one or more of the organic components is 
greater than 0.3 kPa at 20 [deg]C (1.2 in. H<INF>2</INF>O at 68 
[deg]F). Standard reference texts or ASTM D2879-83, -96, or -97 
(incorporated by reference, see Sec.  60.17) shall be used to determine 
the vapor pressures.
    (2) The total concentration of the pure organic components having a 
vapor pressure greater than 0.3 kPa at 20 [deg]C (1.2 in. 
H<INF>2</INF>O at 68 [deg]F) is equal to or greater than 20 percent by 
weight.
    (3) The fluid is a liquid at operating conditions.
    (e) Samples used in conjunction with paragraphs (d) and (e) of this 
section shall be representative of the process fluid that is contained 
in or contacts the equipment, or the gas being combusted in the flare.

Model Rule--Initial Compliance Requirements


Sec.  60.5410c   How do I demonstrate initial compliance with the 
standards for each of my designated facilities?

    You must determine initial compliance with the standards for each 
designated facility using the requirements of paragraphs (a) through 
(i) of this section. Except as otherwise provided in this section, the 
initial compliance period begins on the date specified in Sec.  
60.5387c and ends no later than 1 year after that date. The initial 
compliance period may be less than 1 full year.
    (a) Gas well liquids unloading standards for well designated 
facility. To demonstrate initial compliance with the GHG standards for 
each gas well liquids unloading operation conducted at your well 
designated facility as required by Sec.  60.5390c, you must comply with 
paragraphs (a)(1) through (4) of this section, as applicable.
    (1) You must submit the initial annual report for your well 
designated facility as required in Sec.  60.5420c(b)(1) and (2).
    (2) If you comply by using a liquids unloading technology or 
technique that does not vent to the atmosphere according to Sec.  
60.5390c(a)(1), you must maintain the records specified in Sec.  
60.5420c(c)(1)(i).
    (3) If you comply by using a liquids unloading technology or 
technique that vents to the atmosphere according to Sec.  
60.5390c(a)(2), (b) and (c), you must comply with paragraphs (a)(3)(i) 
and (ii) of this section.

[[Page 17170]]

    (i) Employ best management practices to minimize venting of methane 
emissions as specified in Sec.  60.5390c(d) for each gas well liquids 
unloading operation.
    (ii) Maintain the records specified in Sec.  60.5420c(c)(1)(ii).
    (4) If you comply by using Sec.  60.5390c(g), you must comply with 
paragraphs (b)(4)(i) through (vi) of this section.
    (i) Reduce methane emissions by 95.0 percent or greater and as 
demonstrated by the requirements of Sec.  60.5413c.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411c(a) and (c) to capture all emissions and route all 
emissions to a control device that meets the conditions specified in 
Sec.  60.5412c.
    (iii) Conduct an initial performance test as required in Sec.  
60.5413c within 180 days after the initial gas well liquids unloading 
operation or install a control device tested under Sec.  60.5413c(d) 
which meets the criteria in Sec.  60.5413c(d)(11) and (e), and comply 
with the continuous compliance requirements of Sec.  60.5415c(e).
    (iv) You must conduct the initial inspections required in Sec.  
60.5416c(a) and (b).
    (v) You must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417c(a) through (i), as 
applicable.
    (vi) You must maintain the records specified in Sec.  
60.5420c(c)(1)(iii), (c)(7) and (c)(9) through (12), as applicable and 
submit the reports as required by Sec.  60.5420c(b)(11) through (13), 
as applicable.
    (b) Associated gas well standards for well designated facility. To 
demonstrate initial compliance with the GHG standards for each 
associated gas well as required by Sec.  60.5391c, you must comply with 
paragraphs (b)(1) through (5) of this section.
    (1) If you comply with the requirements of Sec.  60.5391c(a), you 
must maintain the records specified in Sec.  60.5420c(c)(2)(i) and 
submit the information required by Sec.  60.5420c(b)(3)(i) through (iv) 
in your initial annual report.
    (2) If you comply with Sec.  60.5391c(b) because you have 
demonstrated that annual methane emissions are 40 tons per year or 
less, you must document the calculation of annual methane emissions 
determined in accordance with Sec.  60.5391c(e)(1) and submit them in 
the initial annual report, and comply with paragraphs (b)(4) of this 
section.
    (3) If you comply with Sec.  60.5391c(b) because you have 
demonstrated that it is not feasible to comply with Sec.  
60.5391c(a)(1), (2), (3), or (4) due to technical reasons, document the 
initial demonstration and certification of the technical reason in 
accordance with Sec.  60.5391c(e)(1) and submit them in the initial 
annual report, and comply with paragraphs (b)(4) of this section. 
Submit this documentation in the initial annual report, and comply with 
paragraph (b)(4) of this section.
    (4) If you comply with Sec.  60.5391c(b), you must comply with 
paragraphs (b)4)((i) through (iv) of this section
    (i) Reduce methane emissions by 95.0 percent or greater and as 
demonstrated by the requirements of Sec.  60.5413c.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411c(a) and (c) to capture the associated gas and route the 
captured associated gas to a control device that meets the conditions 
specified in Sec.  60.5412c.
    (iii) Conduct an initial performance test as required in Sec.  
60.5413c within 180 days after initial startup or by 36 months after 
the state plan submittal deadline (as specified in Sec.  60.5362c(c)), 
whichever date is later, or install a control device tested under Sec.  
60.5413c(d) which meets the criteria in Sec.  60.5413c(d)(11) and (e) 
and you must comply with the continuous compliance requirements of 
Sec.  60.5415c(e).
    (iv) Conduct the initial inspections required in Sec.  60.5416c(a) 
and (b).
    (v) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417c(a) through (g), as applicable.
    (vi) Maintain the records specified in Sec.  60.5420c(c)(2)(ii) and 
(c)(7) and (9) through (12), as applicable.
    (5) You must submit the initial annual report for your associated 
gas well at a well designated facility as required in Sec.  
60.5420c(b)(1), (3), and (10) through (12), as applicable.
    (c) Centrifugal compressor designated facility. To demonstrate 
initial compliance with the GHG standards in Sec.  60.5392c(a)(1) and 
(2) for your centrifugal compressors (including both wet seal 
centrifugal compressors and dry seal centrifugal compressors) that 
require volumetric flow rate measurements, you must comply with 
paragraphs (c)(1), (6), and (7) of this section. Alternatively, if you 
comply with the GHG standards for your wet seal and dry seal 
centrifugal compressor designated facility by reducing methane 
emissions from each centrifugal compressor wet seal fluid degassing 
system by 95.0 percent in accordance with Sec.  60.5392c(a)(3) and (4), 
you must achieve initial compliance by complying with paragraphs (c)(2) 
through (7) of this section. If you comply with the GHG standards for 
your wet seal and dry seal centrifugal compressor designated facility 
by routing emissions from the wet seal fluid degassing system through a 
closed vent system to a process in accordance with Sec.  
60.5392c(a)(5), you must achieve initial compliance by complying with 
paragraphs (c)(2), (4), (6), and (7) of this section.
    (1) You must maintain the volumetric flow rates for your 
centrifugal compressors as specified in paragraphs (c)(1)(i) through 
(iii) of this section, as applicable. You must conduct your initial 
annual volumetric measurement as required by Sec.  60.5392c(a)(1).
    (i) For your wet seal centrifugal compressors (including self-
contained wet seal centrifugal compressors), you must maintain the 
volumetric flow rate at or below 3 scfm per seal.
    (ii) For your Alaska North Slope centrifugal compressor equipped 
with sour seal oil separator and capture system, you must maintain the 
volumetric flow rate at or below 9 scfm per seal.
    (iii) For your dry seal compressor, you must maintain the 
volumetric flow rate at or below 10 scfm per seal.
    (2) If you use a control device to reduce emissions to comply with 
Sec.  60.5392c(a)(4) or route the emissions to a process to comply with 
Sec.  60.5392c(a)(5), you must equip the wet seal fluid degassing 
system or dry seal system with a cover that meets the requirements of 
Sec.  60.5411c(b) and route the captured vapors through a closed vent 
system that meets the requirements of Sec.  60.5411c(a) and (c).
    (3) If you use a control device to comply with Sec.  
60.5392c(a)(4), you must conduct an initial performance test as 
required in Sec.  60.5413c within 180 days after initial startup, or by 
36 months after the state plan submittal deadline (as specified in 
Sec.  60.5362c(c)), whichever date is later, or install a control 
device tested under Sec.  60.5413c(d) which meets the criteria in Sec.  
60.5413c(d)(11) and (e) and you must comply with the continuous 
compliance requirements of Sec.  60.5415c(e).
    (4) If you use a control device to comply with Sec.  60.5392c(a)(4) 
or comply with Sec.  60.5392c(a)(5) by routing to a process, you must 
conduct the initial inspections required in Sec.  60.5416c(a) and (b).
    (5) If you use a control device to comply with Sec.  
60.5392c(a)(4), you must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417c(a) through (i), as 
applicable.
    (6) You must submit the initial annual report for your centrifugal 
compressor

[[Page 17171]]

designated facility as required in Sec.  60.5420c(b)(1) and (4) and 
(b)(10) through (12), as applicable.
    (7) You must maintain the records as specified in Sec.  
60.5420c(c)(3) and (c)(7) through (12), as applicable.
    (d) Reciprocating compressor designated facility. To demonstrate 
initial compliance with the GHG standards for each reciprocating 
compressor designated facility as required by Sec.  60.5393c, you must 
comply with paragraphs (d)(1) through (7) of this section.
    (1) If you comply with Sec.  60.5393c(a) by maintaining volumetric 
flow rate at or below 2 scfm per cylinder (or a combined cylinder 
emission flow rate greater than the number of compression cylinders 
multiplied by 2 scfm) as required by Sec.  60.5393c(a), you must 
maintain volumetric flow rate at or below 2 scfm and you must conduct 
your initial annual volumetric flow rate measurement as required by 
Sec.  60.5393c(a)(1).
    (2) If you comply with Sec.  60.5393c by collecting the methane 
emissions from your reciprocating compressor rod packing using a rod 
packing emissions collection system as required by Sec.  
60.5393c(d)(1), you must equip the reciprocating compressor with a 
cover that meets the requirements of Sec.  60.5411c(b), route emissions 
to a process through a closed vent system that meets the requirements 
of Sec.  60.5411c(a) and (c), and you must conduct the initial 
inspections required in Sec.  60.5416c(a) and (b).
    (3) If you comply with Sec.  60.5393c(d) by collecting emissions 
from your rod packing emissions collection system by using a control 
device to reduce methane emissions by 95.0 percent as required by Sec.  
60.5393c(d)(2), you must equip the reciprocating compressor with a 
cover that meets the requirements of Sec.  60.5411c(b), route emissions 
to a control device that meets the conditions specified in Sec.  
60.5412c through a closed vent system that meets the requirements of 
Sec.  60.5411c(a) and (c), and you must conduct the initial inspections 
required in Sec.  60.5416c(a) and (b).
    (4) If you comply with Sec.  60.5393c(d)(2), you must conduct an 
initial performance test as required in Sec.  60.5413c within 180 days 
after initial startup, or by 36 months after the state plan submittal 
deadline (as specified in Sec.  60.5362c(c)), whichever date is later, 
or install a control device tested under Sec.  60.5413c(d) which meets 
the criteria in Sec.  60.5413c(d)(11) and (e) and you must comply with 
the continuous compliance requirements of Sec.  60.5415c(e).
    (5) If you comply with Sec.  60.5393c(d)(2), you must install and 
operate the continuous parameter monitoring systems in accordance with 
Sec.  60.5417c(a) through (i), as applicable.
    (6) You must submit the initial annual report for your 
reciprocating compressor as required in Sec.  60.5420c(b)(1), (5) and 
(10) through (12), as applicable.
    (7) You must maintain the records as specified in Sec.  
60.5420c(c)(4) and (7) through (12), as applicable.
    (e) Process controller designated facility. To demonstrate initial 
compliance with GHG emission standards for your process controller 
designated facility, you must comply with paragraphs (e)(1) through (5) 
of this section, as applicable. If you change compliance methods, you 
must perform the applicable compliance demonstrations of paragraphs 
(e)(1) through (3) of this section again for the new compliance method, 
note the change in compliance method in the annual report required by 
Sec.  60.5420c(b)(6)(iv), and maintain the records required by 
paragraph (e)(1)(i) or (ii) of this section for the new compliance 
method.
    (1) For process controller designated facilities complying with the 
requirements of Sec.  60.5394c(a), you must demonstrate that your 
process controller designated facility does not emit any methane to the 
atmosphere by meeting the requirements of paragraph (e)(3) of this 
section.
    (i) If you comply by routing the emissions to a process, you must 
meet the requirements for closed vent systems specified in paragraph 
(e)(3) of this section.
    (ii) If you comply by using a self-contained natural gas-driven 
process controller, you must conduct an initial no identifiable 
emissions inspection required by Sec.  60.5416c(b).
    (2) For each process controller designated facility located at a 
site in Alaska that does not have access to electrical power, you must 
demonstrate initial compliance with Sec.  60.5394c(b)(1) and (2) or 
with Sec.  60.5394c(b)(3), as an alternative to complying with 
paragraph Sec.  60.5394c(a) by meeting the requirements specified in 
(e)(2)(i) through (v) of this section for each process controller, as 
applicable.
    (i) For each process controller in the process controller 
designated facility operating with a bleed rate of less than or equal 
to 6 scfh, you must maintain records in accordance with Sec.  
60.5420c(c)(5)(iii)(A) that demonstrate the process controller is 
designed and operated to achieve a bleed rate less than or equal to 6 
scfh.
    (ii) For each process controller in the process controller 
designated facility operating with a bleed rate greater than 6 scfh, 
you must maintain records that demonstrate that a controller with a 
higher bleed rate than 6 scfh is required based on a specific 
functional need for that controller as specified in Sec.  
60.5420c(c)(5)(iii)(B).
    (iii) For each intermittent vent process controller in the process 
controller designated facility you must demonstrate that each 
intermittent vent controller does not emit to the atmosphere during 
idle periods by conducting initial monitoring in accordance with Sec.  
60.5394c(b)(2)(ii).
    (iv) For each process controller designated facility that complies 
by reducing methane emissions from all controllers in the process 
controller designated facility by 95.0 percent in accordance with Sec.  
60.5394c(b)(3), you must comply with paragraphs (e)(2)(iv)(A) through 
(D) of this section.
    (A) Reduce methane emissions by 95.0 percent or greater and as 
demonstrated by the requirements of Sec.  60.5413c.
    (B) Route all process controller designated facility emissions to a 
control device that meets the conditions specified in Sec.  60.5412c 
through a closed vent system that meets the requirements specified in 
paragraph (e)(3) of this section.
    (C) Conduct an initial performance test as required in Sec.  
60.5413c within 180 days after initial startup, or by 36 months after 
the state plan submittal deadline (as specified in Sec.  60.5362c(c)), 
whichever date is later, or install a control device tested under Sec.  
60.5413c(d) which meets the criteria in Sec.  60.5413c(d)(11) and (e) 
and you must comply with the continuous compliance requirements of 
Sec.  60.5415c(g).
    (D) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417c(a) through (g), as applicable.
    (3) For each closed vent system used to comply with Sec.  60.5394c, 
you must meet the requirements specified in paragraphs (e)(3)(i) and 
(ii) of this section.
    (i) Install a closed vent system that meets the requirements of 
Sec.  60.5411c(a) and (c).
    (ii) Conduct the initial inspections of the closed vent system and 
bypasses, if applicable, as required in Sec.  60.5416c(a) and (b).
    (4) You must submit the initial annual report for your process 
controller designated facility as required in Sec.  60.5420c(b)(1) and 
(6).

[[Page 17172]]

    (5) You must maintain the records as specified in Sec.  
60.5420c(c)(5).
    (f) Pump designated facility. To demonstrate initial compliance 
with the GHG standards for your pump designated facility as required by 
Sec.  60.5395c, you must comply with paragraphs (f)(1) through (4) of 
this section, as applicable. If you change compliance methods, you must 
perform the applicable compliance demonstrations of paragraphs (f)(1) 
and (2) of this section again for the new compliance method, note the 
change in compliance method in the annual report required by Sec.  
60.5420c(b)(9)(v), and maintain the records required by paragraph 
(f)(4) of this section for the new compliance method.
    (1) For pump designated facilities complying with the requirements 
of Sec.  60.5395c(a) or (b)(2) by routing emissions to a process, you 
must meet the requirements specified in paragraphs (f)(1)(ii) and (iv) 
of this section. For pump designated facilities complying with the 
requirements of Sec.  60.5395c(b)(3), you must meet the requirements 
specified in paragraphs (f)(1)(i) and (v) of this section.
    (i) Reduce methane emissions by 95.0 percent or greater and as 
demonstrated by the requirements of Sec.  60.5413c.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411c(a) and (c) to capture all emissions from all pumps in 
the pump designated facility and route all emissions to a process or 
control device that meets the conditions specified in Sec.  60.5412c.
    (iii) Conduct an initial performance test as required in Sec.  
60.5413c within 180 days after initial startup, or by 36 months after 
the state plan submittal deadline (as specified in Sec.  60.5362c(c)), 
whichever date is later, or install a control device tested under Sec.  
60.5413c(d) which meets the criteria in Sec.  60.5413c(d)(11) and (e), 
and you must comply with the continuous compliance requirements of 
Sec.  60.5415c(e).
    (iv) Conduct the initial inspections of the closed vent system and 
bypasses, if applicable, as required in Sec.  60.5416c(a) and (b).
    (v) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417c(a) through (i), as applicable.
    (2) Submit the certifications specified in paragraphs (f)(2)(i) 
through (iii) of this section, as applicable.
    (i) The certification required by Sec.  60.5395c(b)(3) that there 
is no vapor recovery unit on site and that there is a control device on 
site, but it does not achieve a 95.0 percent emissions reduction.
    (ii) The certification required by Sec.  60.5395c(b)(4) that there 
is no control device or process available on site.
    (iii) The certification required by Sec.  60.5395c(b)(5)(i) that it 
is technically infeasible to capture and route the pump designated 
facility emissions to a process or an existing control device.
    (3) You must submit the initial annual report for your pump 
designated facility as specified in Sec.  60.5420c(b)(1) and (9).
    (4) You must maintain the records for your pump designated facility 
as specified in Sec.  60.5420c (c)(7) and (c)(9) through (12), as 
applicable, and (c)(14).
    (g) Process unit equipment designated facility. To achieve initial 
compliance with the GHG standards for process unit equipment designated 
facilities as required by Sec.  60.5400c, you must comply with 
paragraphs (g)(1) through (4) and (g)(11) through (15) of this section, 
unless you meet and comply with the exception in Sec.  60.5402c(b), 
(e), or (f) or meet the exemption in Sec.  60.5402c(c). If you comply 
with the GHG standards for process unit equipment designated facilities 
using the alternative standards in Sec.  60.5401c, you must comply with 
paragraphs (g)(5) through (15) of this section, unless you meet the 
exemption in Sec.  60.5402c(b) or (c) or the exception in Sec.  
60.5402c(e) or (f).
    (1) You must conduct monitoring for each pump in light liquid 
service, pressure relief device in gas/vapor service, valve in gas/
vapor or light liquid service and connector in gas/vapor or light 
liquid service as required by Sec.  60.5400c(b).
    (2) You must conduct monitoring as required by Sec.  60.5400c(c) 
for each pump in light liquid service.
    (3) You must conduct monitoring as required by Sec.  60.5400c(d) 
for each pressure relief device in gas/vapor service.
    (4) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec.  60.5400c(e).
    (5) You must conduct monitoring for each pump in light liquid 
service as required by Sec.  60.5401c(b).
    (6) You must conduct monitoring for each pressure relief device in 
gas/vapor service as required by Sec.  60.5401c(c).
    (7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec.  60.5401c(d).
    (8) You must conduct monitoring for each valve in gas/vapor or 
light liquid service as required by Sec.  60.5401c(f).
    (9) You must conduct monitoring for each pump, valve, and connector 
in heavy liquid service and each pressure relief device in light liquid 
or heavy liquid service as required by Sec.  60.5401c(g).
    (10) You must conduct monitoring for each connector in gas/vapor or 
light liquid service as required by Sec.  60.5401c(h).
    (11) For each pump equipped with a dual mechanical seal system that 
degasses the barrier fluid reservoir to a process or a control device, 
each pump which captures and transports leakage from the seal or seals 
to a process or a control device, or each pressure relief device which 
captures and transports leakage through the pressure relief device to a 
process or a control device, you must meet the requirements of 
paragraph (g)(11)(i) through (vi) of this section.
    (i) Reduce methane emissions by 95.0 percent or greater and as 
demonstrated by the requirements of Sec.  60.5413c or route to a 
process.
    (ii) Install a closed vent system that meets the requirements of 
Sec.  60.5411c(a) and (c) to capture all emissions from each pump 
equipped with a dual mechanical seal system that degasses the barrier 
fluid reservoir, each pump which captures and transports leakage from 
the seal or seals, or each pressure relief device which captures and 
transports leakage through the pressure relief device and route all 
emissions to a process or to a control device that meets the conditions 
specified in Sec.  60.5412c.
    (iii) If routing to a control device, conduct an initial 
performance test as required in Sec.  60.5413c within 180 days after 
initial startup, or by 36 months after the state plan submittal 
deadline (as specified in Sec.  60.5362c(c)), whichever date is later, 
or install a control device tested under Sec.  60.5413c(d) which meets 
the criteria in Sec.  60.5413c(d)(11) and (e), and you must comply with 
the continuous compliance requirements of Sec.  60.5415c(d).
    (iv) Conduct the initial inspections of the closed vent system and 
bypasses, if applicable, as required in Sec.  60.5416c(a) and (b).
    (v) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417c(a) through (g), as applicable.
    (vi) Maintain the records as required by Sec.  60.5420c(c)(7) and 
(c)(9) through (12), as applicable and submit the reports as required 
by Sec.  60.5420c(b)(10) through (12), as applicable.
    (12) You must tag and repair each identified leak as required in 
Sec.  60.5400c(h) or Sec.  60.5400c(i), as applicable.
    (13) You must submit the notice required by Sec.  60.5420c(a)(2).

[[Page 17173]]

    (14) You must submit the initial semiannual report and subsequent 
semiannual report as required by Sec.  60.5422c and the annual reports 
in Sec.  60.5420c(b)(10)(i) through (iv), as applicable.
    (15) You must maintain the records specified by Sec.  60.5421c.
    (h) Storage vessel designated facility. To achieve initial 
compliance with the GHG standards for each storage vessel designated 
facility as required by Sec.  60.5396c, you must comply with paragraphs 
(h)(1) through (9) of this section. To achieve initial compliance with 
the GHG standards for each storage vessel designated facility that 
complies by using a floating roof in accordance with Sec.  
60.5396c(b)(2), you must comply with paragraph (h)(1) and (10) of this 
section.
    (1) You must determine the potential for methane emissions as 
specified in Sec.  60.5386c(e)(2).
    (2) You must reduce methane emissions by 95.0 percent or greater 
according to Sec.  60.5396c(a) and as demonstrated by the requirements 
of Sec.  60.5413c or route to a process.
    (3) If you use a control device to reduce emissions, you must equip 
each storage vessel in the storage vessel designated facility with a 
cover that meets the requirements of Sec.  60.5411c(b), install a 
closed vent system that meets the requirements of Sec.  60.5411c(a) and 
(c) to capture all emissions from the storage vessel designated 
facility, and route all emissions to a control device that meets the 
conditions specified in Sec.  60.5412c. If you route emissions to a 
process, you must equip each storage vessel in the storage vessel 
affected facility with a cover that meets the requirements of Sec.  
60.5411c(b), install a closed vent system that meets the requirements 
of Sec.  60.5411c(a) and (c) to capture all emissions from the storage 
vessel affected facility, and route all emissions to a process.
    (4) If you use a control device to reduce emissions, you must 
conduct an initial performance test as required in Sec.  60.5413c 
within 180 days after initial startup, or within 180 days 36 months 
after the state plan submittal deadline (as specified in Sec.  
60.5362c(c)), whichever date is later, or install a control device 
tested under Sec.  60.5413c(d) which meets the criteria in Sec.  
60.5413c(d)(11) and (e), and you must comply with the continuous 
compliance requirements of Sec.  60.5415c(h).
    (5) You must conduct the initial inspections of the closed vent 
system and bypasses, if applicable, as required in Sec.  60.5416c(a) 
and (b).
    (6) You must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417c(a) through (g), as 
applicable.
    (7) You must maintain the records as required by Sec.  
60.5420c(c)(7) through (12), as applicable and submit the reports as 
required by Sec.  60.5420c(b)(10) through (12), as applicable.
    (8) You must submit the initial annual report for your storage 
vessel designated facility required by Sec.  60.5420c(b)(1) and (7).
    (9) You must maintain the records required for your storage vessel 
designated facility, as specified in Sec.  60.5420c(c)(6) for each 
storage vessel designated facility.
    (10) For each storage vessel designated facility that complies by 
using a floating roof, you must meet the requirements of Sec.  
60.112b(a)(1) or (2) and the relevant monitoring, inspection, 
recordkeeping, and reporting requirements in subpart Kb of this part. 
You must submit a statement that you are complying with Sec.  
60.112b(d)(a)(1) or (2) in accordance with Sec.  60.5396c(b)(2) with 
the initial annual report specified in Sec.  60.5420c(b)(1) and (7).
    (i) Fugitive emission components designated facility. To achieve 
initial compliance with the GHG standards for fugitive emissions 
components designated facilities as required by Sec.  60.5397c, you 
must comply with paragraphs (i)(1) through (5) of this section.
    (1) You must develop a fugitive emissions monitoring plan as 
required in Sec.  60.5397c(b), (c), and (d).
    (2) You must conduct an initial monitoring survey as required in 
Sec.  60.5397c(e) and (f).
    (3) You must repair each identified source of fugitive emissions 
for each designated facility as required in Sec.  60.5397c(h).
    (4) You must submit the initial annual report for each fugitive 
emissions components designated facility as required in Sec.  
60.5420c(b)(1) and (8).
    (5) You must maintain the records specified in Sec.  
60.5420c(c)(13).


Sec.  60.5411c   What additional requirements must I meet to determine 
initial compliance for my covers and closed vent systems?

    For each cover or closed vent system at your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, storage 
vessel, and process unit equipment designated facilities, you must 
comply with the applicable requirements of paragraphs (a) through (c) 
of this section.
    (a) Closed vent system requirements. (1) Reciprocating compressor 
rod packing, process controllers, and pumps. You must design the closed 
vent system to capture and route all gases, vapors, and fumes to a 
process.
    (2) Associated gas wells, gas wells where liquids are being 
unloaded, centrifugal compressors, reciprocating compressor rod 
packing, process controllers in Alaska, pumps, storage vessels, and 
process unit equipment. You must design the closed vent system to 
capture and route all gases, vapors, and fumes to a process or a 
control device that meets the requirements specified in Sec.  
60.5412c(a) through (d) of this section. For pumps complying with Sec.  
60.5395c(b)(3), you must design the closed vent system to capture and 
route all gases, vapors, and fumes to a control device that meets the 
requirements specified in Sec.  60.5412c(a) through (d) of this 
section.
    (3) You must design and operate the closed vent system with no 
identifiable emissions as demonstrated by Sec.  60.5416c(a) and (b).
    (4) For bypass devices, you must meet the requirements specified in 
paragraphs (a)(4)(i) and (ii) of this section if the closed vent system 
contains one or more bypass devices that could be used to divert all or 
a portion of the gases, vapors, or fumes from entering the control 
device or being routed to a process.
    (i) Except as provided in paragraph (a)(4)(ii) of this section, you 
must comply with either paragraph (a)(4)(i)(A) or (B) of this section 
for each bypass device.
    (A) You must properly install, calibrate, maintain, and operate a 
flow indicator at the inlet to the bypass device. The flow indicator 
must be capable of taking periodic readings as specified in Sec.  
60.5416c(a)(4)(i) and sound an alarm, or initiate notification via 
remote alarm to the nearest field office, when the bypass device is 
open such that the stream is being, or could be, diverted away from the 
control device or process, and sent to the atmosphere. You must 
maintain records of each time the alarm is activated according to Sec.  
60.5420c(c)(9).
    (B) You must secure the bypass device valve installed at the inlet 
to the bypass device in the non-diverting position using a car-seal or 
a lock-and-key type configuration.
    (ii) Low leg drains, high point bleeds, analyzer vents, open-ended 
valves or lines, and safety devices are not subject to the requirements 
of paragraph (a)(4)(i) of this section.
    (b) Cover requirements for storage vessels, centrifugal 
compressors, and reciprocating compressors. (1) The cover and all 
openings on the cover (e.g., access hatches, sampling ports, pressure

[[Page 17174]]

relief devices and gauge wells) shall form a continuous impermeable 
barrier over the entire surface area of the liquid in the storage 
vessel or centrifugal compressor wet seal fluid degassing system, or 
reciprocating compressor rod packing emissions collection system.
    (2) 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 as follows:
    (i) To add material to, or remove material from the unit (this 
includes openings necessary to equalize or balance the internal 
pressure of the unit following changes in the level of the material in 
the unit);
    (ii) To inspect or sample the material in the unit;
    (iii) To inspect, maintain, repair, or replace equipment located 
inside the unit; or
    (iv) To vent liquids, gases, or fumes from the unit through a 
closed vent system designed and operated in accordance with the 
requirements of paragraph (a) of this section to a control device or to 
a process.
    (3) Each storage vessel thief hatch shall be equipped, maintained, 
and operated with a weighted mechanism or equivalent, to ensure that 
the lid remains properly seated and sealed under normal operating 
conditions, including such times when working, standing/breathing, and 
flash emissions may be generated. You must select gasket material for 
the hatch based on composition of the fluid in the storage vessel and 
weather conditions.
    (4) You must design and operate the cover with no identifiable 
emissions as demonstrated by Sec.  60.5416c(a) and (b), except when 
operated as provided in paragraphs (b)(2)(i) through (iii) of this 
section.
    (c) Design requirements. (1) You must conduct an assessment that 
the closed vent system is of sufficient design and capacity to ensure 
that all gases, vapors, and fumes from the designated facility are 
routed to the control device or process and that the control device or 
process is of sufficient design and capacity to accommodate all 
emissions from the designated facility. The assessment must be 
certified by a qualified professional engineer or an in-house engineer 
with expertise on the design and operation of the closed vent system in 
accordance with paragraphs (c)(1)(i) and (ii) of this section.
    (i) You must provide the following certification, signed and dated 
by a qualified professional engineer or an in-house engineer: ``I 
certify that the closed vent system design and capacity assessment was 
prepared under my direction or supervision. I further certify that the 
closed vent system design and capacity assessment was conducted, and 
this report was prepared pursuant to the requirements of subpart OOOOc 
of this part. Based on my professional knowledge and experience, and 
inquiry of personnel involved in the assessment, the certification 
submitted herein is true, accurate, and complete.''
    (ii) The assessment shall be prepared under the direction or 
supervision of a qualified professional engineer or an in-house 
engineer who signs the certification in paragraph (c)(1)(i) of this 
section.


Sec.  60.5412c   What additional requirements must I meet for 
determining initial compliance of my control devices?

    You must meet the requirements of paragraphs (a) and (b) of this 
section for each control device used to comply with the emissions 
standards for your well, centrifugal compressor, reciprocating 
compressor, storage vessel, process controller, pump, or process unit 
equipment designated facility. If you use a carbon adsorption system as 
a control device to meet the requirements of paragraph (a)(2) of this 
section, you also must meet the requirements in paragraph (c) of this 
section.
    (a) Each control device used to meet the emissions reduction 
standard in Sec.  60.5390c(g) for your well designated facility gas 
well that unloads liquids; Sec.  60.5391c(b) for your well designated 
facility with associated gas; Sec.  60.5392c(a)(4) for your centrifugal 
compressor designated facility; Sec.  60.5393c(d)(2) for your 
reciprocating compressor designated facility; Sec.  60.5396c(a)(2) for 
your storage vessel designated facility; Sec.  60.5394c(b)(3) for your 
process controller designated facility in Alaska; Sec.  60.5395c(b)(1) 
for your pumps designated facility; or either Sec.  60.5400c(f) or 
Sec.  60.5401c(e) for your process equipment designated facility must 
be installed according to paragraphs (a)(1) through (3) of this 
section. As an alternative to paragraphs (a)(1) through (3) of this 
section, you may install a control device model tested under Sec.  
60.5413c(d), which meets the criteria in Sec.  60.5413c(d)(11) and 
which meets the initial and continuous compliance requirements in Sec.  
60.5413c(e).
    (1) Each enclosed combustion device (e.g., thermal vapor 
incinerator, catalytic vapor incinerator, boiler, or process heater) 
must be designed and operated in accordance with paragraph (a)(1)(i) of 
this section, meet one of the operating limits specified in paragraphs 
(a)(1)(ii) through (v) of this section, and except for boilers and 
process heaters meeting the requirements of paragraph (a)(1)(iii) of 
this section and catalytic vapor incinerators meeting the requirements 
of paragraph (a)(1)(v) of this section, meet the operating limits 
specified in paragraphs (a)(1)(vi) through (ix) of this section. 
Alternatively, the enclosed combustion device must meet the 
requirements specified in paragraph (d) of this section.
    (i) You must reduce the mass content of methane in the gases vented 
to the device by 95.0 percent by weight or greater or reduce the 
concentration of total organic compounds (TOC) in the exhaust gases at 
the outlet to the device to a level equal to or less than 275 ppmv as 
propane on a wet basis corrected to 3 percent oxygen as determined in 
accordance with the requirements of Sec.  60.5413c(b), with the 
exceptions noted in Sec.  60.5413c(a).
    (ii) For an enclosed combustion device for which you demonstrate 
during the performance test conducted under Sec.  60.5413c(b) that 
combustion zone temperature is an indicator of destruction efficiency, 
you must operate at or above the minimum temperature established during 
the most recent performance test. During the performance test conducted 
under Sec.  60.5413c(b), you must continuously record the temperature 
of the combustion zone and average the temperature for each test run. 
The established minimum temperature limit is the average of the test 
run averages.
    (iii) For an enclosed combustion device which is a boiler or 
process heater, you must introduce the vent stream into the flame zone 
of the boiler or process heater and introduce the vent stream with the 
primary fuel or use the vent stream as the primary fuel.
    (iv) For an enclosed combustion device other than those meeting the 
operating limits in paragraphs (a)(1)(ii), (iii), and (v) of this 
section, if the enclosed combustion device is unassisted or pressure-
assisted, you must maintain the net heating value (NHV) of the gas sent 
to the enclosed combustion device at or above the applicable limits 
specified in paragraphs (a)(1)(iv)(A) and (B) of this section. If the 
enclosed combustion device is steam-assisted or air-assisted, you must 
meet the applicable limits specified in paragraphs (a)(1)(iv)(C) and 
(D) of this section, as appropriate.
    (A) For enclosed combustion devices that do not use assist gas or 
pressure-assisted burner tips to promote mixing at the burner tip, 200 
British thermal units (Btu) per standard cubic feet (Btu/scf).

[[Page 17175]]

    (B) For enclosed combustion devices that use pressure-assisted 
burner tips to promote mixing at the burner tip, 800 Btu/scf.
    (C) For steam-assisted and air-assisted enclosed combustion 
devices, maintain the combustion zone NHV (NHV<INF>cz</INF>) at or 
above 270 Btu/scf.
    (D) For enclosed combustion devices with perimeter assist air, 
maintain the NHV dilution parameter (NHV<INF>dil</INF>) at or above 22 
British thermal units per square foot (Btu/sqft). If the only assist 
air provided to the enclosed combustion control device is perimeter 
assist air intentionally entrained in lower and/or upper steam at the 
burner tip and the effective diameter is 9 inches or greater, you are 
only required to comply with the NHV<INF>cz</INF> limit specified in 
paragraph (a)(1)(iv)(C) of this section.
    (v) For an enclosed combustion device which is a catalytic vapor 
incinerator, you must operate the catalytic vapor incinerator at or 
above the minimum temperature of the catalyst bed inlet and at or above 
the minimum temperature differential between the catalyst bed inlet and 
the catalyst bed outlet established in accordance with Sec.  
60.5417c(f) and as determined in your performance test conducted in 
accordance with Sec.  60.5413c(b).
    (vi) Unless you have an enclosed combustion device with pressure-
assisted burner tips to promote mixing at the burner tip, you must 
operate each enclosed combustion control device at or below the maximum 
inlet gas flow rate established in accordance with Sec.  60.5417c(f) 
and as determined in your performance test conducted in accordance with 
Sec.  60.5413c(b).
    (vii) You must operate the combustion control device at or above 
the minimum inlet gas flow rate established in accordance with Sec.  
60.5417c(f).
    (viii) You must install and operate a continuous burning pilot or 
combustion flame. An alert must be sent to the nearest control room 
whenever the pilot or combustion flame is unlit.
    (ix) You must operate the enclosed combustion device with no 
visible emissions, except for periods not to exceed a total of 1 minute 
during any 15-minute period. A visible emissions test using section 11 
of Method 22 of appendix A-7 to this part must be performed at least 
once every calendar month, separated by at least 15 days between each 
test. The observation period shall be 15 minutes or once the amount of 
time visible emissions is present has exceeded 1 minute, whichever time 
period is less. Alternatively, you may conduct visible emissions 
monitoring according to Sec.  60.5417c(h). Devices failing the visible 
emissions test must follow manufacturer's repair instructions, if 
available, or best combustion engineering practice as outlined in the 
unit inspection and maintenance plan, to return the unit to compliant 
operation. All inspection, repair, and maintenance activities for each 
unit must be recorded in a maintenance and repair log and must be 
available for inspection. Following return to operation from 
maintenance or repair activity, each device must pass a Method 22 of 
appendix A-7 to this part visual observation as described in this 
paragraph or be monitored according to Sec.  60.5417c(h).
    (2) Each vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device must be designed and 
operated to reduce the mass content of methane in the gases vented to 
the device by 95.0 percent by weight or greater as determined in 
accordance with the requirements of Sec.  60.5413c(b). As an 
alternative to the performance testing requirements of Sec.  
60.5413c(b), you may demonstrate initial compliance by conducting a 
design analysis for vapor recovery devices according to the 
requirements of Sec.  60.5413c(c). For a condenser, you also must 
calculate the daily average condenser outlet temperature in accordance 
with Sec.  60.5417c(e), and you must determine the condenser efficiency 
for the current operating day using the daily average condenser outlet 
temperature and the condenser performance curve established in 
accordance with Sec.  60.5417c(f)(2). You must determine the average 
TOC emission reduction in accordance with Sec.  60.5415c(e)(1)(ix)(D). 
For a carbon adsorption system, you also must comply with paragraph (c) 
of this section.
    (3) Each flare must be designed and operated according to the 
requirements specified in paragraphs (a)(3)(i) through (viii) of this 
section, as applicable. Alternatively, flares must meet the 
requirements specified in paragraph (d) of this section.
    (i) For unassisted flares, you must maintain the NHV of the vent 
gas sent to the flare at or above 200 Btu/scf.
    (ii) For flares that use pressure-assisted burner tips to promote 
mixing at the burner tip, you must maintain the NHV of the vent gas 
sent to the flare at or above 800 Btu/scf.
    (iii) For steam-assisted and air-assisted flares, you must maintain 
the NHVcz at or above 270 Btu/scf.
    (iv) For flares with perimeter assist air, you must maintain the 
NHVdil at or above 22 Btu/sqft. If the only assist air provided to the 
flare is perimeter assist air intentionally entrained in lower and/or 
upper steam at the flare tip and the effective diameter is 9 inches or 
greater, you are not required to comply with the NHVdil limit.
    (v) For flares other than pressure-assisted flares, you must 
determine the maximum flow rate of vent gas to the control system based 
on the design considerations of the designated facilities to 
demonstrate compliance with the flare tip velocity limits in Sec.  
60.18(b) according to Sec.  60.5417c(d)(8)(iv). The maximum flare tip 
velocity limits do not apply for pressure-assisted flares.
    (vi) You must operate the flare at or above the minimum inlet gas 
flow rate. The minimum inlet gas flow rate is established based on 
manufacturer recommendations.
    (vii) You must operate the flare with no visible emissions, except 
for periods not to exceed a total of 1 minute during any 15-minute 
period. You must conduct the compliance determination with the visible 
emission limits using Method 22 of appendix A-7 to this part, or you 
must monitor the flare according to Sec.  60.5417c(h).
    (viii) You must install and operate a continuous burning pilot or 
combustion flame. An alert must be sent to the nearest control room 
whenever the pilot flame is unlit.
    (b) You must operate each control device installed on your well, 
centrifugal compressor, reciprocating compressor, storage vessel, 
process controller, pump, or process unit equipment designated facility 
in accordance with the requirements specified in paragraphs (b)(1) and 
(2) of this section.
    (1) You must operate each control device used to comply with this 
subpart at all times when gases, vapors, and fumes are vented from the 
designated facility through the closed vent system to the control 
device. You may vent more than one designated facility to a control 
device used to comply with this subpart.
    (2) For each control device monitored in accordance with the 
requirements of Sec.  60.5417c(a) through (i), you must demonstrate 
compliance according to the requirements of Sec.  60.5415c(e), as 
applicable.
    (c) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (a)(2) of this section, you must 
comply with the requirements of paragraph (c)(1) of this section. If 
the carbon adsorption system is a regenerative-type carbon adsorption 
system, you also must comply with the

[[Page 17176]]

requirements of paragraph (c)(2) of this section.
    (1) You must manage the carbon in accordance with the requirements 
specified in paragraphs (c)(1)(i) and (ii) of this section.
    (i) Following the initial startup of the control device, you must 
replace all carbon in the carbon adsorption system with fresh carbon on 
a regular, predetermined time interval that is no longer than the 
carbon service life established according to Sec.  60.5413c(c)(2) or 
(3). You must maintain records identifying the schedule for replacement 
and records of each carbon replacement as required in Sec.  
60.5420c(c)(9) and (11).
    (ii) You must either regenerate, reactivate, or burn the spent 
carbon removed from the carbon adsorption system in one of the units 
specified in paragraphs (c)(1)(ii)(A) through (F) of this section.
    (A) Regenerate or reactivate the spent carbon in a unit for which 
you have been issued a final permit under 40 CFR part 270 that 
implements the requirements of 40 CFR part 264, subpart X.
    (B) Regenerate or reactivate the spent carbon in a unit equipped 
with an operating organic air emissions control in accordance with an 
emissions standard for VOC under another subpart in 40 CFR part 63 or 
this part.
    (C) Burn the spent carbon in a hazardous waste incinerator for 
which the owner or operator complies with the requirements of 40 CFR 
part 63, subpart EEE, and has submitted a Notification of Compliance 
under 40 CFR 63.1207(j).
    (D) Burn the spent carbon in a hazardous waste boiler or industrial 
furnace for which the owner or operator complies with the requirements 
of 40 CFR part 63, subpart EEE, and has submitted a Notification of 
Compliance under 40 CFR 63.1207(j).
    (E) Burn the spent carbon in an industrial furnace for which you 
have been issued a final permit under 40 CFR part 270 that implements 
the requirements of 40 CFR part 266, subpart H.
    (F) Burn the spent carbon in an industrial furnace that you have 
designed and operated in accordance with the interim status 
requirements of 40 CFR part 266, subpart H.
    (2) You must comply with the requirements of paragraph (c)(2)(i) 
through (iii) of this section for each regenerative-type carbon 
adsorption system.
    (i) You must measure and record the average total regeneration 
stream mass flow or volumetric flow during each carbon bed regeneration 
cycle to demonstrate compliance with the total regeneration stream flow 
established in accordance with Sec.  60.5413c(c)(2).
    (ii) You must check the mechanical connections for leakage at least 
every month, and you must perform a visual inspection at least every 3 
months of all components of the flow continuous parameter monitoring 
system for physical and operational integrity and all electrical 
connections for oxidation and galvanic corrosion, if your continuous 
parameter monitoring system is not equipped with a redundant flow 
sensor.
    (iii) You must measure and record the average carbon bed 
temperature for the duration of the carbon bed steaming cycle and 
measure the actual carbon bed temperature after regeneration and within 
15 minutes of completing the cooling cycle. You must maintain the 
average carbon bed temperature above the temperature limit in 
established accordance with Sec.  60.5413c(c)(2) during the carbon bed 
steaming cycle and below the carbon bed temperature established in in 
accordance with Sec.  60.5413c(c)(2) after the regeneration cycle.
    (d) To demonstrate that a flare or enclosed combustion device 
reduces methane in the gases vented to the device by 95.0 percent by 
weight or greater, as outlined in Sec.  60.8(b), you may submit a 
request for an alternative test method. At a minimum, the request must 
follow the requirements outlined in paragraphs (d)(1) through (5) of 
this section.
    (1) The alternative method must be capable of demonstrating 
continuous compliance with a combustion efficiency of 95.0 percent or 
greater or it must be capable of demonstrating continuous compliance 
with the following metrics:
    (i) NHV<INF>cz</INF> of 270 Btu/scf or greater.
    (ii) NHV<INF>dil</INF> of 22 Btu/sqft or greater, if the 
alternative test method will be used for enclosed combustion devices or 
flares with perimeter assist air.
    (2) The alternative method must be validated according to Method 
301 in appendix A to 40 CFR part 63 for each type of control device 
covered by the alternative test method (e.g., air-assisted flare, 
unassisted enclosed combustion device) or the alternative test method 
must contain performance-based procedures and indicators to ensure 
self-validation.
    (3) At a minimum the alternative test method must provide a reading 
for each successive 15-minute period.
    (4) The alternative test method must be capable of documenting 
periods when the enclosed combustion device or flare operates with 
visible emissions. If the alternative test method cannot identify 
periods of visible emissions, you must conduct the inspections required 
by Sec.  60.5417c(d)(8)(v).
    (5) If the alternative test method demonstrates compliance with the 
metrics specified in paragraphs (d)(1)(i) and (ii) of this section 
instead of demonstrating continuous compliance with 95.0 percent or 
greater combustion efficiency, you must still install the pilot or 
combustion flame monitoring system required by Sec.  60.5417c(d)(8)(i). 
If the alternative test method demonstrates continuous compliance with 
a combustion efficiency of 95.0 percent or greater, the requirement in 
Sec.  60.5417c(d)(8)(i) no longer applies.


Sec.  60.5413c   What are the performance testing procedures for 
control devices?

    This section applies to the performance testing of control devices 
used to demonstrate compliance with the emissions standards for your 
well, centrifugal compressor, reciprocating compressor, storage vessel, 
process controller, pump designated facilities complying with Sec.  
60.5393c(b)(1), or process unit equipment designated facility. You must 
demonstrate that a control device achieves the performance requirements 
of Sec.  60.5412c(a)(1) or (2) using the performance test methods and 
procedures specified in this section. For condensers and carbon 
adsorbers, you may use a design analysis as specified in paragraph (c) 
of this section in lieu of complying with paragraph (b) of this 
section. In addition, this section contains the requirements for 
enclosed combustion device performance tests conducted by the 
manufacturer applicable to well, centrifugal compressor, reciprocating 
compressor, storage vessel, process controller, pump designated 
facilities complying with Sec.  60.5393c(b)(1), or process unit 
equipment designated facilities.
    (a) Performance test exemptions. You are exempt from the 
requirements to conduct initial and periodic performance tests and 
design analyses if you use any of the control devices described in 
paragraphs (a)(1) through (6) of this section. You are exempt from the 
requirements to conduct an initial performance test if you use a 
control device described in paragraph (a)(7) of this section.
    (1) A flare that is designed and operated in accordance with the 
requirements in Sec.  60.5412c(a)(3). You must conduct the compliance 
determination using Method 22 of appendix A-7 to this part to determine 
visible emissions or monitor the flare according to Sec.  60.5417c(h). 
The net heating value of the vent gas must be

[[Page 17177]]

determined according to Sec.  60.5417c(d)(8)(ii).
    (2) A boiler or process heater with a design heat input capacity of 
44 megawatts or greater.
    (3) A boiler or process heater into which the vent stream is 
introduced with the primary fuel or is used as the primary fuel.
    (4) A boiler or process heater burning hazardous waste for which 
you have been issued a final permit under 40 CFR part 270 and comply 
with the requirements of 40 CFR part 266, subpart H; you have certified 
compliance with the interim status requirements of 40 CFR part 266, 
subpart H; you have submitted a Notification of Compliance under 40 CFR 
63.1207(j) and comply with the requirements of 40 CFR part 63, subpart 
EEE; or you comply with 40 CFR part 63, subpart EEE, and will submit a 
Notification of Compliance under 40 CFR 63.1207(j) by the date 
specified in Sec.  60.5420c(b)(11) for submitting the initial 
performance test report.
    (5) A hazardous waste incinerator for which you have submitted a 
Notification of Compliance under 40 CFR 63.1207(j), or for which you 
will submit a Notification of Compliance under 40 CFR 63.1207(j) by the 
date specified in Sec.  60.5420c(b)(11) for submitting the initial 
performance test report, and you comply with the requirements of 40 CFR 
part 63, subpart EEE.
    (6) A control device for which performance test is waived in 
accordance with Sec.  60.8(b).
    (7) A control device whose model can be demonstrated to meet the 
performance requirements of Sec.  60.5412c(a)(1)(i) through a 
performance test conducted by the manufacturer, as specified in 
paragraph (d) of this section.
    (b) Test methods and procedures. You must use the test methods and 
procedures specified in paragraphs (b)(1) through (4) of this section, 
as applicable, for each performance test conducted to demonstrate that 
a control device meets the requirements of Sec.  60.5412c(a)(1) or (2). 
You must conduct the initial and periodic performance tests according 
to the schedule specified in paragraph (b)(5) of this section. Each 
performance test must consist of a minimum of 3 test runs. Each run 
must be at least 1 hour long.
    (1) You must use Method 1 or 1A of appendix A-1 to this part, as 
appropriate, to select the sampling sites. Any references to 
particulate mentioned in Methods 1 and 1A do not apply to this section.
    (i) Sampling sites must be located at the inlet of the first 
control device and at the outlet of the final control device to 
determine compliance with a control device percent reduction 
requirement.
    (ii) The sampling site must be located at the outlet of the 
combustion device to determine compliance with a TOC exhaust gas 
concentration limit.
    (2) You must determine the gas volumetric flow rate using Method 2, 
2A, 2C, or 2D of appendix A-2 of this part, as appropriate.
    (3) To determine compliance with the control device percent 
reduction performance requirement in Sec.  60.5412c(a)(1)(i) or (a)(2), 
you must use Method 18 of appendix A-6 to this part, Method 320 of 
appendix A to 40 CFR part 63, or ASTM D6348-12e1(incorporated by 
reference, see Sec.  60.17) to measure methane or Method 25A of 
appendix A-7 to this part to measure TOC, as propane. You must use 
Method 4 of appendix A-3 to this part to convert the Method 25A results 
to a dry basis. You must use the procedures in paragraphs (b)(3)(i) 
through (iii) of this section to calculate percent reduction 
efficiency.
    (i) You must compute the mass rate of methane or TOC using the 
following equations:
[GRAPHIC] [TIFF OMITTED] TR08MR24.038

Where:

E<INF>i</INF>, E<INF>o</INF> = Mass rate of methane or TOC at the 
inlet and outlet of the control device, respectively, dry basis, 
kilograms per hour.
K<INF>2</INF> = Constant, 2.494 x 10<SUP>-6</SUP> (parts per 
million) (gram-mole per standard cubic meter) (kilogram/gram) 
(minute/hour), where standard temperature (gram-mole per standard 
cubic meter) is 20[deg] degrees Celsius.
C<INF>i</INF>, C<INF>o</INF> = Concentration of methane of the gas 
stream as measured by Method 18 of appendix A-6, Method 320 of 
appendix A to 40 CFR part 63, or ASTM D6348-12e1 or TOC, as propane, 
of the gas stream as measured by Method 25A of appendix A-7 to this 
part at the inlet and outlet of the control device, respectively, 
dry basis, parts per million by volume.
M<INF>p</INF> = Molecular weight of methane, if using Method 18 of 
appendix A-6 to this part, Method 320 of appendix A to 40 CFR part 
63, or ASTM D6348-12e1, 16.04 gram/gram-mole. Molecular weight of 
propane, if using Method 25A of appendix A-7 to this part, 44.1 
gram/gram-mole.
Q<INF>i</INF>, Q<INF>o</INF> = Flow rate of gas stream at the inlet 
and outlet of the control device, respectively, dry standard cubic 
meter per minute.

    (ii) You must calculate the percent reduction in TOC as follows:
    [GRAPHIC] [TIFF OMITTED] TR08MR24.039
    
Where:

R<INF>cd</INF> = Control efficiency of control device, percent.
E<INF>i</INF> = Mass rate of methane or TOC at the inlet to the 
control device as calculated under paragraph (b)(3)(i) of this 
section, kilograms per hour.
E<INF>o</INF> = Mass rate of methane or TOC at the outlet of the 
control device, as calculated under paragraph (b)(3)(i) of this 
section, kilograms per hour.

    (iii) If the vent stream entering a boiler or process heater with a 
design

[[Page 17178]]

capacity less than 44 megawatts is introduced with the combustion air 
or as a secondary fuel, you must determine the weight-percent reduction 
of methane across the device by comparing the methane in all combusted 
vent streams and primary and secondary fuels with the methane exiting 
the device, respectively.
    (4) You must use Method 25A of appendix A-7 to this part to measure 
TOC, as propane, to determine compliance with the TOC exhaust gas 
concentration limit specified in Sec.  60.5412c(a)(1)(i). You must 
determine the concentration in parts per million by volume on a wet 
basis and correct it to 3 percent oxygen. You must use the emission 
rate correction factor for excess air, integrated sampling and analysis 
procedures of Method 3A or 3B of appendix A-2 to this part, ASTM D6522-
20, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (both 
incorporated by reference, see Sec.  60.17) to determine the oxygen 
concentration. The samples must be taken during the same time that the 
samples are taken for determining TOC concentration. You must correct 
the TOC concentration for percent oxygen as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.040

Where:
C<INF>c</INF> = TOC concentration, as propane, corrected to 3 
percent oxygen, parts per million by volume on a wet basis.
C<INF>m</INF> = TOC concentration, as propane, parts per million by 
volume on a wet basis.
%O<INF>2m</INF> = Concentration of oxygen, percent by volume as 
measured, wet.

    (5) You must conduct performance tests according to the schedule 
specified in paragraphs (b)(5)(i) through (iii) of this section.
    (i) You must conduct an initial performance test within 180 days 
after initial startup for your designated facility. You must submit the 
performance test results as required in Sec.  60.5420c(b)(11).
    (ii) You must conduct periodic performance tests for all control 
devices required to conduct initial performance tests. You must conduct 
the first periodic performance test no later than 60 months after the 
initial performance test required in paragraph (b)(5)(i) of this 
section. You must conduct subsequent periodic performance tests at 
intervals no longer than 60 months following the previous periodic 
performance test or whenever you desire to establish a new operating 
limit. If a control device is not operational at the time a performance 
test is due, you must conduct the performance test no later than 30 
calendar days after returning the control device to service. You must 
submit the periodic performance test results as specified in Sec.  
60.5420c(b)(11).
    (iii) If the initial performance test was conducted by the 
manufacturer under paragraph (d) of this section, you must conduct the 
first periodic performance test no later than 60 months after initial 
installation and startup of the control device. You must conduct 
subsequent periodic performance tests at intervals no longer than 60 
months following the previous periodic performance test. If a control 
device is not operational at the time a performance test is due, you 
must conduct the performance test no later than 30 calendar days after 
returning the control device to service. You must submit the periodic 
performance test results as specified in Sec.  60.5420c(b)(11).
    (c) Control device design analysis to meet the requirements of 
Sec.  60.5412c(a)(2). (1) For a condenser, the design analysis must 
include an analysis of the vent stream composition, constituent 
concentrations, flow rate, relative humidity, and temperature and must 
establish the design outlet organic compound concentration level, 
design average temperature of the condenser exhaust vent stream and the 
design average temperatures of the coolant fluid at the condenser inlet 
and outlet.
    (2) For a regenerable carbon adsorption system, the design analysis 
shall include the vent stream composition, constituent concentrations, 
flow rate, relative humidity and temperature and shall establish the 
design exhaust vent stream organic compound concentration level, 
adsorption cycle time, number and capacity of carbon beds, type and 
working capacity of activated carbon used for the carbon beds, design 
total regeneration stream flow over the period of each complete carbon 
bed regeneration cycle, design carbon bed temperature after 
regeneration, design carbon bed regeneration time and design service 
life of the carbon.
    (3) For a nonregenerable carbon adsorption system, such as a carbon 
canister, the design analysis shall include the vent stream 
composition, constituent concentrations, flow rate, relative humidity 
and temperature and shall establish the design exhaust vent stream 
organic compound concentration level, capacity of the carbon bed, type 
and working capacity of activated carbon used for the carbon bed and 
design carbon replacement interval based on the total carbon working 
capacity of the control device and source operating schedule. In 
addition, these systems shall incorporate dual carbon canisters in case 
of emission breakthrough occurring in one canister.
    (4) If you and the Administrator do not agree on a demonstration of 
control device performance using a design analysis, then you must 
perform a performance test in accordance with the requirements of 
paragraph (b) of this section to resolve the disagreement. The 
Administrator may choose to have an authorized representative observe 
the performance test.
    (d) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph (d) applies to the 
performance testing of a combustion control device conducted by the 
device manufacturer. The manufacturer must demonstrate that a specific 
model of control device achieves the performance requirements in 
paragraph (d)(11) of this section by conducting a performance test as 
specified in paragraphs (d)(2) through (10) of this section. You must 
submit a test report for each combustion control device in accordance 
with the requirements in paragraph (d)(12) of this section.
    (2) Performance testing must consist of three 1-hour (or longer) 
test runs for each of the four firing rate settings specified in 
paragraphs (d)(2)(i) through (iv) of this section, making a total of 12 
test runs per test. Propene (propylene) gas must be used for the 
testing fuel. All fuel analyses must be performed by an independent 
third-party laboratory (not affiliated with the control device 
manufacturer or fuel supplier).
    (i) 90-100 percent of maximum design rate (fixed rate).

[[Page 17179]]

    (ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 100 percent of the maximum design 
rate. Hold at 100 percent for 5 minutes. In the 10 to 15-minute time 
range, incrementally ramp back down to 70 percent of the maximum design 
rate. Repeat three more times for a total of 60 minutes of sampling.
    (iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 70 percent of the maximum design 
rate. Hold at 70 percent for 5 minutes. In the 10 to 15-minute time 
range, incrementally ramp back down to 30 percent of the maximum design 
rate. Repeat three more times for a total of 60 minutes of sampling.
    (iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the 
minimum firing rate. During the first 5 minutes, incrementally ramp the 
firing rate to 30 percent of the maximum design rate. Hold at 30 
percent for 5 minutes. In the 10 to 15-minute time range, incrementally 
ramp back down to the minimum firing rate. Repeat three more times for 
a total of 60 minutes of sampling.
    (3) All models employing multiple enclosures must be tested 
simultaneously and with all burners operational. Results must be 
reported for each enclosure individually and for the average of the 
emissions from all interconnected combustion enclosures/chambers. 
Control device operating data must be collected continuously throughout 
the performance test using an electronic Data Acquisition System. A 
graphic presentation or strip chart of the control device operating 
data and emissions test data must be included in the test report in 
accordance with paragraph (d)(12) of this section. Inlet fuel meter 
data may be manually recorded provided that all inlet fuel data 
readings are included in the final report.
    (4) Inlet testing must be conducted as specified in paragraphs 
(d)(4)(i) and (ii) of this section.
    (i) The inlet gas flow metering system must be located in 
accordance with Method 2A of appendix A-1 to this part (or other 
approved procedure) to measure inlet gas flow rate at the control 
device inlet location. You must position the fitting for filling fuel 
sample containers a minimum of eight pipe diameters upstream of any 
inlet gas flow monitoring meter.
    (ii) Inlet flow rate must be determined using Method 2A of appendix 
A-1 to this part. Record the start and stop reading for each 60-minute 
THC test. Record the gas pressure and temperature at 5-minute intervals 
throughout each 60-minute test.
    (5) Inlet gas sampling must be conducted as specified in paragraphs 
(d)(5)(i) and (ii) of this section.
    (i) At the inlet gas sampling location, securely connect a fused 
silica-coated stainless steel evacuated canister fitted with a flow 
controller sufficient to fill the canister over a 3-hour period. 
Filling must be conducted as specified in paragraphs (d)(5)(i)(A) 
through (C) of this section.
    (A) Open the canister sampling valve at the beginning of each test 
run and close the canister at the end of each test run.
    (B) Fill one canister across the three test runs such that one 
composite fuel sample exists for each test condition.
    (C) Label the canisters individually and record sample information 
on a chain of custody form.
    (ii) Analyze each inlet gas sample using the methods in paragraphs 
(d)(5)(ii)(A) through (C) of this section. You must include the results 
in the test report required by paragraph (d)(12) of this section.
    (A) Hydrocarbon compounds containing between one and five atoms of 
carbon plus benzene using ASTM D1945-03(R2010) (incorporated by 
reference, see Sec.  60.17).
    (B) Hydrogen (H<INF>2</INF>), carbon monoxide (CO), carbon dioxide 
(CO<INF>2</INF>), nitrogen (N<INF>2</INF>), oxygen (O<INF>2</INF>) 
using ASTM D1945-03(R2010) (incorporated by reference, see Sec.  
60.17).
    (C) Higher heating value using ASTM D3588-98(R2003) or ASTM D4891-
89(R2006) (incorporated by reference, see Sec.  60.17).
    (6) Outlet testing must be conducted in accordance with the 
criteria in paragraphs (d)(6)(i) through (v) of this section.
    (i) Sample and flow rate must be measured in accordance with 
paragraphs (d)(6)(i)(A) and (B) of this section.
    (A) The outlet sampling location must be a minimum of four 
equivalent stack diameters downstream from the highest peak flame or 
any other flow disturbance, and a minimum of one equivalent stack 
diameter upstream of the exit or any other flow disturbance. A minimum 
of two sample ports must be used.
    (B) Flow rate must be measured using Method 1 of appendix A-1 to 
this part for determining flow measurement traverse point location, and 
Method 2 of appendix A-1 to this part for measuring duct velocity. If 
low flow conditions are encountered (i.e., velocity pressure 
differentials less than 0.05 inches of water) during the performance 
test, a more sensitive manometer must be used to obtain an accurate 
flow profile.
    (ii) Molecular weight and excess air must be determined as 
specified in paragraph (d)(7) of this section.
    (iii) Carbon monoxide must be determined as specified in paragraph 
(d)(8) of this section.
    (iv) THC must be determined as specified in paragraph (d)(9) of 
this section.
    (v) Visible emissions must be determined as specified in paragraph 
(d)(10) of this section.
    (7) Molecular weight and excess air determination must be performed 
as specified in paragraphs (d)(7)(i) through (iii) of this section.
    (i) An integrated bag sample must be collected during the moisture 
test required by Method 4 of appendix A-3 to this part following the 
procedure specified in (d)(7)(i)(A) and (B) of this section. Analyze 
the bag sample using a gas chromatograph-thermal conductivity detector 
(GC-TCD) analysis meeting the criteria in paragraphs (d)(7)(i)(C) and 
(D) of this section.
    (A) Collect the integrated sample throughout the entire test and 
collect representative volumes from each traverse location.
    (B) Purge the sampling line with stack gas before opening the valve 
and beginning to fill the bag. Clearly label each bag and record sample 
information on a chain of custody form.
    (C) The bag contents must be vigorously mixed prior to the gas 
chromatograph analysis.
    (D) The GC-TCD calibration procedure in Method 3C of appendix A-2 
to this part must be modified as follows: For the initial calibration, 
triplicate injections of any single concentration must agree within 5 
percent of their mean to be valid. The calibration response factor for 
a single concentration re-check must be within 10 percent of the 
original calibration response factor for that concentration. If this 
criterion is not met, repeat the initial calibration using at least 
three concentration levels.
    (ii) Calculate and report the molecular weight of oxygen, carbon 
dioxide, methane and nitrogen in the integrated bag sample and include 
in the test report specified in paragraph (d)(12) of this section. 
Moisture must be determined using Method 4 of appendix A-3 to this 
part. Traverse both ports with the sampling train required by Method 4 
of appendix A-3 to this part during each test run. Ambient air must not 
be introduced into the integrated bag sample required by Method 3C of

[[Page 17180]]

appendix A-2 to this part during the port change.
    (iii) Excess air must be determined using resultant data from the 
Method 3C tests and Method 3B of appendix A-2 to this part, equation 
3B-1, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) 
(incorporated by reference, see Sec.  60.17).
    (8) Carbon monoxide must be determined using Method 10 of appendix 
A-4 of this part. Run the test simultaneously with Method 25A of 
appendix A-7 to this part using the same sampling points. An instrument 
range of 0-10 parts per million by volume-dry (ppmvd) is recommended.
    (9) Total hydrocarbon determination must be performed as specified 
by in paragraphs (d)(9)(i) through (vii) of this section.
    (i) Conduct THC sampling using Method 25A of appendix A-7 to this 
part, except that the option for locating the probe in the center 10 
percent of the stack is not allowed. The THC probe must be traversed to 
16.7 percent, 50 percent, and 83.3 percent of the stack diameter during 
each test run.
    (ii) A valid test must consist of three Method 25A tests, each no 
less than 60 minutes in duration.
    (iii) A 0 to 10 parts per million by volume-wet (ppmvw) (as 
propane) measurement range is preferred; as an alternative a 0 to 30 
ppmvw (as propane) measurement range may be used.
    (iv) Calibration gases must be propane in air and be certified 
through EPA-600/R-12/531--``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' (incorporated by 
reference, see Sec.  60.17).
    (v) THC measurements must be reported in terms of ppmvw as propane.
    (vi) THC results must be corrected to 3 percent CO<INF>2</INF>, as 
measured by Method 3C of appendix A-2 to this part. You must use the 
following equation for this diluent concentration correction:
[GRAPHIC] [TIFF OMITTED] TR08MR24.041

Where:

C<INF>meas</INF> = The measured concentration of the pollutant.
CO<INF>2meas</INF> = The measured concentration of the 
CO<INF>2</INF> diluent.
3 = The corrected reference concentration of CO<INF>2</INF> diluent.
C<INF>corr</INF> = The corrected concentration of the pollutant.

    (vii) Subtraction of methane or ethane from the THC data is not 
allowed in determining results.
    (10) Visible emissions must be determined using Method 22 of 
appendix A-7 to this part. The test must be performed continuously 
during each test run. A digital color photograph of the exhaust point, 
taken from the position of the observer and annotated with date and 
time, must be taken once per test run and the 12 photos included in the 
test report specified in paragraph (d)(12) of this section.
    (11) For performance test criteria:
    (i) The control device model tested must meet the criteria in 
paragraphs (d)(11)(i)(A) through (D) of this section. These criteria 
must be reported in the test report required by paragraph (d)(12) of 
this section.
    (A) Results from Method 22 of appendix A-7 to this part determined 
under paragraph (d)(10) of this section with no indication of visible 
emissions.
    (B) Average results from Method 25A of appendix A-7 to this part 
determined under paragraph (d)(9) of this section equal to or less than 
10.0 ppmvw THC as propane corrected to 3.0 percent CO<INF>2</INF>.
    (C) Average CO emissions determined under paragraph (d)(8) of this 
section equal to or less than 10 parts ppmvd, corrected to 3.0 percent 
CO<INF>2</INF>.
    (D) Excess air determined under paragraph (d)(7) of this section 
equal to or greater than 150 percent.
    (ii) The manufacturer must determine a minimum inlet gas flow rate 
above which each control device model must be operated to achieve the 
criteria in paragraph (d)(11)(iii) of this section. The manufacturer 
must determine a maximum inlet gas flow rate which must not be exceeded 
for each control device model to achieve the criteria in paragraph 
(d)(11)(iii) of this section. The minimum and maximum inlet gas flow 
rate must be included in the test report required by paragraph (d)(12) 
of this section.
    (iii) A manufacturer must demonstrate a destruction efficiency of 
at least 95.0 percent for THC, as propane. A control device model that 
demonstrates a destruction efficiency of 95.0 percent for THC, as 
propane, will meet the control requirement for 95.0 percent destruction 
of methane required under this subpart.
    (12) The owner or operator of a combustion control device model 
tested under this paragraph (d)(12) must submit the information listed 
in paragraphs (d)(12)(i) through (vi) of this section for each test run 
in the test report required by this section in accordance with Sec.  
60.5420c(b)(12). Owners or operators who claim that any of the 
performance test information being submitted is confidential business 
information (CBI) must submit a complete file including information 
claimed to be CBI to the OAQPS CBI office. The preferred method to 
receive CBI is for it to be transmitted electronically using email 
attachments, File Transfer Protocol, or other online file sharing 
services. Electronic submissions must be transmitted directly to the 
OAQPS CBI Office at the email address <a href="/cdn-cgi/l/email-protection#b7d8d6c6c7c4d4d5def7d2c7d699d0d8c1"><span class="__cf_email__" data-cfemail="dab5bbabaaa9b9b8b39abfaabbf4bdb5ac">[email protected]</span></a> and should 
include clear CBI markings and be flagged to the attention of the 
Leader, Measurement Policy Group. 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 <a href="/cdn-cgi/l/email-protection#1a757b6b6a697978735a7f6a7b347d756c"><span class="__cf_email__" data-cfemail="6b040a1a1b180809022b0e1b0a450c041d">[email protected]</span></a> to request a file transfer link. 
If you cannot transmit the file electronically, you may send CBI 
information through the postal service to the following address: U.S. 
EPA, Attn: OAQPS Document Control Officer and Measurement Policy Group 
Leader, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 12055, 
RTP, North Carolina 27711. The mailed CBI material should be double 
wrapped and clearly marked. Any CBI markings should not show through 
the outer envelope. The same file with the CBI omitted must be 
submitted to <a href="/cdn-cgi/l/email-protection#f2bd9b9ead939c96adb59381ada2a6b2b7a2b3dcb5bda4"><span class="__cf_email__" data-cfemail="eea18782b18f808ab1a98f9db1bebaaeabbeafc0a9a1b8">[email protected]</span></a>.
    (i) A full schematic of the control device and dimensions of the 
device components.
    (ii) The maximum net heating value of the device.
    (iii) The test fuel gas flow range (in both mass and volume). 
Include the minimum and maximum allowable inlet gas flow rate.
    (iv) The air/stream injection/assist ranges, if used.
    (v) The test conditions listed in paragraphs (d)(12)(v)(A) through 
(O) of

[[Page 17181]]

this section, as applicable for the tested model.
    (A) Fuel gas delivery pressure and temperature.
    (B) Fuel gas moisture range.
    (C) Purge gas usage range.
    (D) Condensate (liquid fuel) separation range.
    (E) Combustion zone temperature range. This is required for all 
devices that measure this parameter.
    (F) Excess air range.
    (G) Flame arrestor(s).
    (H) Burner manifold.
    (I) Continuous pilot flame indicator.
    (J) Pilot flame design fuel and calculated or measured fuel usage.
    (K) Tip velocity range.
    (L) Momentum flux ratio.
    (M) Exit temperature range.
    (N) Exit flow rate.
    (O) Wind velocity and direction.
    (vi) The test report must include all calibration quality 
assurance/quality control data, calibration gas values, gas cylinder 
certification, strip charts, or other graphic presentations of the data 
annotated with test times and calibration values.
    (e) Initial and continuous compliance for combustion control 
devices tested by the manufacturer in accordance with paragraph (d) of 
this section. This paragraph (e) applies to the demonstration of 
compliance for a combustion control device tested under the provisions 
in paragraph (d) of this section. Owners or operators must demonstrate 
that a control device achieves the performance criteria in paragraph 
(d)(11) of this section by installing a device tested under paragraph 
(d) of this section, complying with the criteria specified in 
paragraphs (e)(1) through (10) of this section, maintaining the records 
specified in Sec.  60.5420c(c)(10) and submitting the report specified 
in Sec.  60.5420c(b)(10)(v) and (b)(12).
    (1) The inlet gas flow rate must be equal to or greater than the 
minimum inlet gas flow rate and equal to or less than the maximum inlet 
gas flow rate specified by the manufacturer.
    (2) A pilot or combustion flame must be present at all times of 
operation. An alert must be sent to the nearest control room whenever 
the pilot or combustion flame is unlit.
    (3) Devices must be operated with no visible emissions, except for 
periods not to exceed a total of 1 minute during any 15-minute period. 
A visible emissions test conducted according to section 11 of Method 22 
of appendix A-7 to this part must be performed at least once every 
calendar month, separated by at least 15 days between each test. The 
observation period shall be 15 minutes or once the amount of time 
visible emissions is present has exceeded 1 minute, whichever time 
period is less. Alternatively, you may conduct visible emissions 
monitoring according to Sec.  60.5417c(h).
    (4) Devices failing the visible emissions test must follow 
manufacturer's repair instructions, if available, or best combustion 
engineering practice as outlined in the unit inspection and maintenance 
plan, to return the unit to compliant operation. All repairs and 
maintenance activities for each unit must be recorded in a maintenance 
and repair log and must be available for inspection.
    (5) Following return to operation from maintenance or repair 
activity, each device must pass a visual observation according to 
Method 22 of appendix A-7 to this part as described in paragraph (e)(3) 
of this section or be monitored according to Sec.  60.5417c(h).
    (6) If the owner or operator operates a combustion control device 
model tested under this section, an electronic copy of the performance 
test results required by this section shall be submitted via email to 
<a href="/cdn-cgi/l/email-protection#6f200603300e010b30280e1c303f3b2f2a3f2e41282039"><span class="__cf_email__" data-cfemail="531c3a3f0c323d370c1432200c0307131603127d141c05">[email protected]</span></a> unless the test results for that model of 
combustion control device are posted at the following website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
    (7) Ensure that each enclosed combustion device is maintained in a 
leak free condition.
    (8) Operate each control device following the manufacturer's 
written operating instructions, procedures, and maintenance schedule to 
ensure good air pollution control practices for minimizing emissions.
    (9) Install and operate the continuous parameter monitoring systems 
in accordance with Sec.  60.5417c(a) and (c) through (i).
    (10) Comply with the applicable NHV limit specified in Sec.  
60.5412c(a)(1)(iv).

Model Rule--Continuous Compliance Requirements


Sec.  60.5415c   How do I demonstrate continuous compliance with the 
standards for each of my designated facilities?

    (a) Gas well liquids unloading standards for well designated 
facility. For each well liquids unloading operation at your well 
designated facility, you must demonstrate continuous compliance with 
the requirements of Sec.  60.5390c by submitting the annual report 
information specified in Sec.  60.5420c(b)(1) and (2) and maintaining 
the records for each well liquids unloading event that vents to the 
atmosphere as specified in Sec.  60.5420c(c)(1). For each gas well 
liquids unloading well affected facility that complies with the 
requirements of Sec.  60.5390c(g), you must route emissions to a 
control device through a closed vent system and continuously comply 
with the closed vent requirements of Sec.  60.5416c. You also must 
comply with the requirements specified in paragraph (f) of this section 
and maintain the records in Sec.  60.5420c(c)(7), (9) and (11).
    (b) Associated gas well standards for well designated facility. For 
each associated gas well at your well designated facility, you must 
demonstrate continuous compliance with the requirements of Sec.  
60.5391c by submitting the reports required by Sec.  60.5420c(b)(1) and 
(3) and maintaining the records specified in Sec.  60.5420c(c)(2). For 
each associated gas well at your well designated facility that complies 
with the requirements of Sec.  60.5391c(b) or (c), you must route 
emissions to a control device through a closed vent system and 
continuously comply with the closed vent requirements of Sec.  
60.5416c. You must also comply with the requirements specified in 
paragraph (e) of this section and maintain the records in paragraphs 
(c)(7), (9) and (11) of this section.
    (c) Centrifugal compressor designated facility. For each 
centrifugal compressor designated facility complying with the 
volumetric flow rate measurements requirements in Sec.  60.5392c(a)(1) 
and (2), you must demonstrate continuous compliance according to 
paragraph (c)(1) and paragraphs (c)(3) and (4) of this section. 
Alternatively, for each wet seal and dry seal centrifugal compressor 
designated facility complying with Sec.  60.5392c(a)(3) and (a)(4) or 
(5) by routing emissions to a control device or to a process, you must 
demonstrate continuous compliance according to paragraphs (c)(2) 
through (4) of this section.
    (1) You must maintain volumetric flow rate at or below the 
volumetric flow rates specified in paragraphs (c)(1)(i) through (iii) 
of this section for your centrifugal compressor, as applicable, and you 
must conduct the required volumetric flow rate measurement of your dry 
or wet seal in accordance with Sec.  60.5392c(a)(1) and (2) on or 
before 8,760 hours of operation after your last volumetric flow rate 
measurement which demonstrates compliance with the applicable 
volumetric flow rate.
    (i) For your wet seal centrifugal compressors (including self-
contained wet seal centrifugal compressors), you must maintain the 
volumetric flow rate at or below 3 scfm per seal (or in the case of 
manifolded groups of seals, 3 scfm multiplied by the number of seals).

[[Page 17182]]

    (ii) For your Alaska North Slope centrifugal compressor equipped 
with sour seal oil separator and capture system, you must maintain the 
volumetric flow rate at or below 9 scfm per seal (or in the case of 
manifolded groups of wet seals, 9 scfm multiplied by the number of 
seals).
    (iii) For your dry seal compressor, you must maintain the 
volumetric flow rate at or below 10 scfm per seal (or in the case of 
manifolded groups of wet seals, 10 scfm multiplied by the number of 
seals).
    (2) For each wet seal and dry seal centrifugal compressor 
designated facility complying by routing emissions to a control device 
or to a process, you must operate the wet seal emissions collection 
system and dry seal system to route emissions to a control device or a 
process through a closed vent system and continuously comply with the 
closed vent requirements of Sec.  60.5416c(a) and (b). If you comply 
with Sec.  60.5392c(a)(4) by using a control device, you also must 
comply with the requirements in paragraph (e) of this section.
    (3) You must submit the annual reports as required in Sec.  
60.5420c(b)(1), (4) and (10)(i) through (iv), as applicable.
    (4) You must maintain records as required in Sec.  60.5420c(c)(3), 
(7) through (9) and (11), as applicable.
    (d) Pump designated facility. To demonstrate continuous compliance 
with the GHG standards for your pump designated facility as required by 
Sec.  60.5395c, you must comply with paragraphs (d)(1) through (3) of 
this section.
    (1) For pump designated facilities complying with the requirements 
of Sec.  60.5395c(a) by routing emissions to a process and for pump 
designated facilities complying with the requirements of Sec.  
60.5395c(b)(1) or (3), you must continuously comply with the closed 
vent requirements of Sec.  60.5416c(a) and (b). If you comply with 
Sec.  60.5395c(b)(3), you also must comply with the requirements in 
paragraph (d) of this section.
    (2) You must submit the annual reports for your pump designated 
facility as required in Sec.  60.5420c(b)(1), and (9) through (12), as 
applicable.
    (3) You must maintain the records for your pump designated facility 
as specified in Sec.  60.5420c(c)(14), as applicable.
    (e) Additional continuous compliance requirements for well, 
centrifugal compressor, reciprocating compressor, process controllers 
in Alaska, storage vessel, process unit equipment, or pump designated 
facilities. For each associated gas well at your well designated 
facility, each gas well liquids unloading operation at your well 
designated facility, each centrifugal compressor designated facility, 
each reciprocating compressor designated facility, each process 
controller designated facility in Alaska, each storage vessel 
designated facility, each process unit equipment designated facility, 
and each pump designated facility referenced to this paragraph from 
either paragraph (a), (b), (c)(2), (d)(1), (f), (g)(2)(iv), (h) or (i) 
of this section, you must also install monitoring systems as specified 
in Sec.  60.5417c, demonstrate continuous compliance according to 
paragraph (e)(1) of this section, maintain the records in paragraph 
(e)(2) of this section, and comply with the reporting requirements 
specified in paragraph (e)(3) of this section.
    (1) You must demonstrate continuous compliance with the control 
device performance requirements of Sec.  60.5412c(a) using the 
procedures specified in paragraphs (e)(1)(i) through (viii) of this 
section and conducting the monitoring as required by Sec.  60.5417c. If 
you use a condenser as the control device to achieve the requirements 
specified in Sec.  60.5412c(a)(2), you may demonstrate compliance 
according to paragraph (e)(1)(ix) of this section. You may switch 
between compliance with paragraphs (e)(1)(i) through (viii) of this 
section and compliance with paragraph (e)(1)(ix) of this section only 
after at least 1 year of operation in compliance with the selected 
approach. You must provide notification of such a change in the 
compliance method in the next annual report, following the change. If 
you use an enclosed combustion device or a flare as the control device, 
you must also conduct the monitoring required in paragraph (e)(1)(x) of 
this section. If you use an enclosed combustion device or flare using 
an alternative test method approved under Sec.  60.5412c(d), you must 
use the procedures in paragraph (e)(1)(xi) of this section in lieu of 
the procedures in paragraphs (e)(1)(i) through (viii) of this section, 
but you must still conduct the monitoring required in paragraph 
(e)(1)(x) of this section.
    (i) You must operate below (or above) the site-specific maximum (or 
minimum) parameter value established according to the requirements of 
Sec.  60.5417c(f)(1). For flares, you must operate above the limits 
specified in paragraphs (e)(1)(vii)(B) of this section.
    (ii) You must calculate the average of the applicable monitored 
parameter in accordance with Sec.  60.5417c(e).
    (iii) Compliance with the operating parameter limit is achieved 
when the average of the monitoring parameter value calculated under 
paragraph (e)(1)(ii) of this section is either equal to or greater than 
the minimum parameter value or equal to or less than the maximum 
parameter value established under paragraph (e)(1)(i) of this section. 
When performance testing of a combustion control device is conducted by 
the device manufacturer as specified in Sec.  60.5413c(d), compliance 
with the operating parameter limit is achieved when the criteria in 
Sec.  60.5413c(e) are met.
    (iv) You must operate the continuous monitoring system required in 
Sec.  60.5417c(a) at all times the affected source is operating, except 
for periods of monitoring system malfunctions, repairs associated with 
monitoring system malfunctions and required monitoring system quality 
assurance or quality control activities (including, as applicable, 
system accuracy audits and required zero and span adjustments). A 
monitoring system malfunction is any sudden, infrequent, not reasonably 
preventable failure of the monitoring system to provide valid data. 
Monitoring system failures that are caused in part by poor maintenance 
or careless operation are not malfunctions. You are required to 
complete monitoring system repairs in response to monitoring system 
malfunctions and to return the monitoring system to operation as 
expeditiously as practicable.
    (v) You may not use data recorded during monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
or required monitoring system quality assurance or control activities 
in calculations used to report emissions or operating levels. You must 
use all the data collected during all other required data collection 
periods to assess the operation of the control device and associated 
control system.
    (vi) Failure to collect required data is a deviation of the 
monitoring requirements.
    (vii) If you use an enclosed combustion device to meet the 
requirements of Sec.  60.5412c(a)(1) and you demonstrate compliance 
using the test procedures specified in Sec.  60.5413c(b), or you use a 
flare designed and operated in accordance with Sec.  60.5412c(a)(3), 
you must comply with the applicable requirements in paragraphs 
(e)(1)(vii)(A) through (E) of this section.
    (A) For each enclosed combustion device which is not a catalytic 
vapor incinerator and for each flare, you must comply with the 
requirements in

[[Page 17183]]

paragraphs (e)(1)(vii)(A)(1) through (4) of this section.
    (1) A pilot or combustion flame must be present at all times of 
operation. An alert must be sent to the nearest control room whenever 
the pilot or combustion flame is unlit.
    (2) Devices must be operated with no visible emissions, except for 
periods not to exceed a total of 1 minute during any 15-minute period. 
A visible emissions test conducted according to section 11 of Method 22 
of appendix A-7 to this part, must be performed at least once every 
calendar month, separated by at least 15 days between each test. The 
observation period shall be 15 minutes or once the amount of time 
visible emissions is present has exceeded 1 minute, whichever time 
period is less. Alternatively, you may conduct visible emissions 
monitoring according to Sec.  60.5417c(h).
    (3) Devices failing the visible emissions test must follow 
manufacturer's repair instructions, if available, or best combustion 
engineering practice as outlined in the unit inspection and maintenance 
plan, to return the unit to compliant operation. All repairs and 
maintenance activities for each unit must be recorded in a maintenance 
and repair log and must be available for inspection.
    (4) Following return to operation from maintenance or repair 
activity, each device must pass a Method 22 of appendix A-7 to this 
part visual observation as described in paragraph (e)(1)(vii)(D) of 
this section or be monitored according to Sec.  60.5417c(h).
    (B) For flares, you must comply with the requirements in paragraphs 
(e)(1)(vii)(B)(1) through (6) of this section.
    (1) For unassisted flares, maintain the NHV of the gas sent to the 
flare at or above 200 Btu/scf.
    (2) If you use a pressure assisted flare, maintain the NHV of gas 
sent to the flare at or above 800 Btu/scf.
    (3) For steam-assisted and air-assisted flares, maintain the 
NHV<INF>cz</INF> at or above 270 Btu/scf.
    (4) For flares with perimeter assist air, maintain the 
NHV<INF>dil</INF> at or above 22 Btu/sqft. If the only assist air 
provided to the flare is perimeter assist air intentionally entrained 
in lower and/or upper steam at the flare tip and the effective diameter 
is 9 inches or greater, you are not required to comply with the 
NHV<INF>dil</INF> limit.
    (5) Unless you use a pressure-assisted flare, maintain the flare 
tip velocity below the applicable limits in Sec.  60.18(b).
    (6) Maintain the total gas flow to the flare above the minimum 
inlet gas flow rate. The minimum inlet gas flow rate is established 
based on manufacturer recommendations.
    (C) For enclosed combustion devices for which, during the 
performance test conducted under Sec.  60.5413c(b), the combustion zone 
temperature is not an indicator of destruction efficiency, you must 
comply with the requirements in paragraphs (e)(1)(vii)(C)(1) through 
(5) of this section, as applicable.
    (1) Maintain the total gas flow to the enclosed combustion device 
at or above the minimum inlet gas flow rate and at or below the maximum 
inlet flow rate for the enclosed combustion device established in 
accordance with Sec.  60.5417c(f).
    (2) For unassisted enclosed combustion devices, maintain the NHV of 
the gas sent to the enclosed combustion device at or above 200 Btu/scf.
    (3) For enclosed combustion devices that use pressure-assisted 
burner tips to promote mixing at the burner tip, maintain the NHV of 
the gas sent to the enclosed combustion device at or above 800 Btu/scf.
    (4) For steam-assisted and air-assisted enclosed combustion 
devices, maintain the NHV<INF>cz</INF> at or above 270 Btu/scf.
    (5) For enclosed combustion devices with perimeter assist air, 
maintain the NHV<INF>dil</INF> at or above 22 Btu/sqft. If the only 
assist air provided to the enclosed combustion device is perimeter 
assist air intentionally entrained in lower and/or upper steam at the 
flare tip and the effective diameter is 9 inches or greater, you are 
not required to comply with the NHV<INF>dil</INF> limit.
    (D) For enclosed combustion devices for which, during the 
performance test conducted under Sec.  60.5413c(b), the combustion zone 
temperature is demonstrated to be an indicator of destruction 
efficiency, you must comply with the requirements in paragraphs 
(e)(1)(vii)(D)(1) and (2) of this section.
    (1) Maintain the temperature at or above the minimum temperature 
established during the most recent performance test. The minimum 
temperature limit established during the most recent performance test 
is the average temperature recorded during each test run, averaged 
across the 3 test runs (average of the test run averages).
    (2) Maintain the total gas flow to the enclosed combustion device 
at or above the minimum inlet gas flow rate and at or below the maximum 
inlet flow rate for the enclosed combustion device established in 
accordance with Sec.  60.5417c(f).
    (E) For catalytic vapor incinerators you must operate the catalytic 
vapor incinerator at or above the minimum temperature of the catalyst 
bed inlet and at or above the minimum temperature differential between 
the catalyst bed inlet and the catalyst bed outlet established in 
accordance with Sec.  60.5417c(f).
    (viii) If you use a carbon adsorption system as the control device 
to meet the requirements of Sec.  60.5412c(a)(2), you must demonstrate 
compliance by the procedures in paragraphs (e)(1)(viii)(A) and (B) of 
this section, as applicable.
    (A) If you use a regenerative-type carbon adsorption system, you 
must comply with paragraphs (e)(1)(viii)(A)(1) through (4) of this 
section.
    (1) You must maintain the average regenerative mass flow or 
volumetric flow to the carbon adsorber during each bed regeneration 
cycle above the limit established in in accordance with Sec.  
60.5413c(c)(2).
    (2) You must maintain the average carbon bed temperature above the 
temperature limit established in accordance with Sec.  60.5413c(c)(2) 
during the carbon bed steaming cycle and below the carbon bed 
temperature established in in accordance with Sec.  60.5413c(c)(2) 
after the regeneration cycle.
    (3) You must check the mechanical connections for leakage at least 
every month, and you must perform a visual inspection at least every 3 
months of all components of the continuous parameter monitoring system 
for physical and operational integrity and all electrical connections 
for oxidation and galvanic corrosion if your continuous parameter 
monitoring system is not equipped with a redundant flow sensor.
    (4) You must replace all carbon in the carbon adsorption system 
with fresh carbon on a regular, predetermined time interval that is no 
longer than the carbon service life established according to Sec.  
60.5413c(c)(2).
    (B) If you use a nonregenerative-type carbon adsorption system, you 
must replace all carbon in the control device with fresh carbon on a 
regular, predetermined time interval that is no longer than the carbon 
service life established according to Sec.  60.5413c(c)(3).
    (ix) If you use a condenser as the control device to achieve the 
percent reduction performance requirements specified in Sec.  
60.5412c(a)(2), you must demonstrate compliance using the procedures in 
paragraphs (e)(1)(ix)(A) through (E) of this section.
    (A) You must establish a site-specific condenser performance curve 
according to Sec.  60.5417c(f)(2).

[[Page 17184]]

    (B) You must calculate the daily average condenser outlet 
temperature in accordance with Sec.  60.5417c(e).
    (C) You must determine the condenser efficiency for the current 
operating day using the daily average condenser outlet temperature 
calculated under paragraph (e)(1)(ix)(B) of this section and the 
condenser performance curve established under paragraph (e)(1)(ix)(A) 
of this section.
    (D) Except as provided in paragraphs (e)(1)(ix)(D)(1) and (2) of 
this section, at the end of each operating day, you must calculate the 
365-day rolling average TOC emission reduction, as appropriate, from 
the condenser efficiencies as determined in paragraph (e)(1)(ix)(C) of 
this section.
    (1) After the compliance dates specified in Sec.  60.5387c(a), if 
you have less than 120 days of data for determining average TOC 
emission reduction, you must calculate the average TOC emission 
reduction for the first 120 days of operation after the compliance 
date. You have demonstrated compliance with the overall 95.0 percent 
reduction requirement if the 120-day average TOC emission reduction is 
equal to or greater than 95.0 percent.
    (2) After 120 days and no more than 364 days of operation after the 
compliance date specified in Sec.  60.5387c(a), you must calculate the 
average TOC emission reduction as the TOC emission reduction averaged 
over the number of days between the current day and the applicable 
compliance date. You have demonstrated compliance with the overall 95.0 
percent reduction requirement if the average TOC emission reduction is 
equal to or greater than 95.0 percent.
    (E) If you have data for 365 days or more of operation, you have 
demonstrated compliance with the TOC emission reduction if the rolling 
365-day average TOC emission reduction calculated in paragraph 
(e)(1)(ix)(D) of this section is equal to or greater than 95.0 percent.
    (x) During each inspection conducted using an OGI camera under 
Sec.  60.5397c and during each periodic screening event or each 
inspection conducted using an OGI camera under Sec.  60.5398c, you must 
observe each enclosed combustion device and flare to determine if it is 
operating properly. You must determine whether there is a flame present 
and whether any uncontrolled emissions from the control device are 
visible with the OGI camera or the technique used to conduct the 
periodic screening event. During each inspection conducted under Sec.  
60.5397c using AVO, you must observe each enclosed combustion device 
and flare to determine if it is operating properly. Visually confirm 
that the pilot or combustion flame is lit and that the pilot or 
combustion flame is operating properly.
    (xi) If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412c(d), you must 
comply with paragraphs (e)(1)(xi)(A) through (E) of this section.
    (A) You must maintain the combustion efficiency at or above 95.0 
percent. Alternatively, if the alternative test method does not 
directly monitor combustion efficiency, you must comply with the 
applicable requirements in paragraphs (e)(1)(xi)(A)(1) and (2) of this 
section.
    (1) Maintain the NHV<INF>cz</INF> at or above 270 Btu/scf.
    (2) For flares or enclosed combustion devices with perimeter assist 
air, maintain the NHV<INF>dil</INF> at or above 22 Btu/sqft. If the 
only assist air provided to the flare or enclosed combustion device is 
perimeter assist air intentionally entrained in lower and/or upper 
steam at the flare tip and the effective diameter is 9 inches or 
greater, you are only required to comply with the NHV<INF>cz</INF> 
limit specified in paragraph (e)(1)(xi)(A)(1) of this section.
    (B) You must calculate the value of the applicable monitored 
metric(s) in accordance with the approved alternative test method. 
Compliance with the limit is achieved when the calculated values are 
within the range specified in paragraph (e)(1)(xi)(A) of this section.
    (C) You must conduct monitoring using the alternative test method 
at all times the affected source is operating, except for periods of 
monitoring system malfunctions, repairs associated with monitoring 
system malfunctions and required monitoring system quality assurance or 
quality control activities (including, as applicable, system accuracy 
audits and required zero and span adjustments). A monitoring system 
malfunction is any sudden, infrequent, not reasonably preventable 
failure of the monitoring system to provide valid data. Monitoring 
system failures that are caused in part by poor maintenance or careless 
operation are not malfunctions. You are required to complete monitoring 
system repairs in response to monitoring system malfunctions and to 
return the monitoring system to operation as expeditiously as 
practicable.
    (D) You may not use data recorded during monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
or required monitoring system quality assurance or control activities 
in calculations used to report values to demonstrate compliance with 
the limits specified in paragraph (e)(1)(xi)(A) of this section. You 
must use all the data collected during all other required data 
collection periods to assess the operation of the control device and 
associated control system.
    (E) Failure to collect required data is a deviation of the 
monitoring requirements.
    (2) You must maintain the records as specified in Sec.  
60.5420c(c)(10) and (12).
    (3) You must comply with the reporting requirements in Sec.  
60.5420c(b)(10) through (12).
    (f) Reciprocating compressor designated facility. For each 
reciprocating compressor designated facility complying with Sec.  
60.5393c(a) through (c), you must demonstrate continuous compliance 
according to paragraphs (f)(1), (3) and (4) of this section. For each 
reciprocating compressor designated facility complying with Sec.  
60.5393c(d), you must demonstrate continuous compliance according to 
paragraph (f)(4) through (6) of this section. For each reciprocating 
compressor affected facility complying with Sec.  60.5393c(d)(2), you 
must demonstrate continuous compliance according to paragraphs (g)(3) 
through (6) of this section.
    (1) You must maintain the volumetric flow rate at or below 2 scfm 
per cylinder (or at or below the combined volumetric flow rate 
determined by multiplying the number of cylinders by 2 scfm), and you 
must conduct the required volumetric flow rate measurement of your 
reciprocating compressor rod packing vents in accordance with Sec.  
60.5393c(b) on or before 8,760 hours of operation after your last 
volumetric flow rate measurement which demonstrated compliance with the 
applicable volumetric flow rate.
    (2) You must operate the rod packing emissions collection system to 
route emissions to a control device or to a process through a closed 
vent system and continuously comply with the cover and closed vent 
requirements of Sec.  60.5416c. If you comply with Sec.  60.5393c(d) by 
using a control device, you also must comply with the requirements in 
paragraph (e) of this section.
    (3) You must continuously monitor the number of hours of operation 
for each reciprocating compressor affected facility since initial 
startup, since 60 days after the state plan submittal deadline (as 
specified in Sec.  60.5362c(c)), since the previous flow rate 
measurement, or since the date of the

[[Page 17185]]

most recent reciprocating compressor rod packing replacement, whichever 
date is latest.
    (4) You must replace the reciprocating compressor rod packing on or 
before the total number of hours of operation reaches 8,760 hours.
    (5) You must submit the annual reports as required in Sec.  
60.5420c(b)(1), (5), and (b)(10)(i) through (iv), as applicable.
    (6) You must maintain records as required in Sec.  60.5420c(c)(4), 
(7), (9), and (11), as applicable.
    (g) Process controller designated facility. To demonstrate 
continuous compliance with GHG emission standards for your process 
controller designated facility as required by Sec.  60.5394c, you must 
comply with the paragraphs (g)(1) through (4) of this section.
    (1) You must demonstrate that your process controller designated 
facility does not emit any methane to the atmosphere by meeting the 
requirements of paragraphs (g)(1)(i) or (ii) of this section.
    (i) If you comply by routing the emissions to a process, you must 
comply with the closed vent system inspection and monitoring 
requirements of Sec.  60.5416c.
    (ii) If you comply by using a self-contained natural gas-driven 
process controller, you must conduct the no identifiable emissions 
inspections required by Sec.  60.5416c(b).
    (2) For each process controller designated facility located at a 
site in Alaska that does not have access to electrical power, and that 
complies by reducing methane emissions from all controllers in the 
process controller designated facility by 95.0 percent in accordance 
with Sec.  60.5494c(b)(3), you must comply with comply with the closed 
vent requirements of Sec.  60.5416c and the requirements in paragraph 
(f) of this section for the control device.
    (3) You must submit the annual report for your process controller 
as required in Sec.  60.5420c(b)(1), (6), and (10) through (12), as 
applicable.
    (4) You must maintain the records as specified in Sec.  
60.5420c(c)(5) for each process controller designated facility, as 
applicable.
    (h) Storage vessel designated facility. For each storage vessel 
designated facility, you must demonstrate continuous compliance with 
the requirements of Sec.  60.5396c according to paragraphs (h)(1) 
through (10) of this section, as applicable.
    (1) For each storage vessel designated facility complying with the 
requirements of Sec.  60.5396c(a)(2), you must demonstrate continuous 
compliance according to paragraphs (h)(5) and (h)(9) and (10) of this 
section.
    (2) For each storage vessel designated facility complying with the 
requirements of Sec.  60.5396c(a)(3), you must demonstrate continuous 
compliance according to paragraphs (h)(2)(i), (ii), or (iii) of this 
section, as applicable, and (h)(9) and (10) of this section.
    (i) You must maintain the uncontrolled actual methane emissions 
from the storage vessel designated facility at less than 14 tpy.
    (ii) You must comply with paragraph (h)(5) of this section as soon 
as liquids from the well are routed to the storage vessel designated 
facility following fracturing or refracturing according to the 
requirements of Sec.  60.5396c(a)(3)(i).
    (iii) You must comply with paragraph (h)(5) of this section within 
30 days of the monthly determination according to the requirements of 
Sec.  60.5396c(a)(3)(ii), where the monthly emissions determination 
indicates that methane emissions from your storage vessel designated 
facility increase to 14 tpy or greater and the increase is not 
associated with fracturing or refracturing of a well feeding the 
storage vessel designated facility.
    (3) For each storage vessel designated facility or portion of a 
storage vessel designated facility removed from service, you must 
demonstrate compliance with the requirements of Sec.  60.5396c(c)(1), 
by complying with paragraphs (h)(6) and (7) and (h)(9) and (10) of this 
section.
    (4) For each storage vessel designated facility or portion of a 
storage vessel designated facility returned to service, you must 
demonstrate compliance with the requirements of Sec.  60.5396c(c)(1) by 
complying with paragraphs (h)(8) through (10) of this section.
    (5) For each storage vessel designated facility, you must comply 
with paragraphs (h)(5)(i) and (ii) of this section.
    (i) You must reduce methane emissions as specified in Sec.  
60.5396c(a)(2).
    (ii) For each control device installed to meet the requirements of 
Sec.  60.5396c(a)(2), you must demonstrate continuous compliance with 
the performance requirements of Sec.  60.5412c for each storage vessel 
designated facility using the procedure specified in paragraph 
(h)(5)(ii)(A) and (B) of this section. When routing emissions to a 
process, you must demonstrate continuous compliance as specified in 
paragraph (h)(5)(ii)(A) of this section.
    (A) You must comply with Sec.  60.5416c for each cover and closed 
vent system.
    (B) You must comply with the requirements specified in paragraph 
(e) of this section.
    (6) You must completely empty and degas each storage vessel, such 
that each storage vessel no longer contains crude oil, condensate, 
produced water or intermediate hydrocarbon liquids. For a portion of a 
storage vessel designated facility to be removed from service, you must 
completely empty and degas the storage vessel(s), such that the storage 
vessel(s) no longer contains crude oil, condensate, produced water or 
intermediate hydrocarbon liquids. A storage vessel where liquid is left 
on walls, as bottom clingage or in pools due to floor irregularity is 
considered to be completely empty.
    (7) You must disconnect the storage vessel(s) from the tank battery 
by isolating the storage vessel(s) from the tank battery such that the 
storage vessel(s) is no longer manifolded to the tank battery by liquid 
or vapor transfer.
    (8) You must determine the designated facility status of a storage 
vessel returned to service as provided in Sec.  60.5386c(e)(5).
    (9) You must submit the annual reports as required by Sec.  
60.5420c(b)(1) and (7).
    (10) You must maintain the records as required by Sec.  
60.5420c(c)(6) through (9), and (11), as applicable.
    (i) Process unit equipment designated facility. For each process 
unit equipment designated facility, you must demonstrate continuous 
compliance with the requirements of Sec.  60.5400c according to 
paragraphs (i)(1) through (4) and (11) through (16) of this section, 
unless you meet and comply with the exception in Sec.  60.5402c(b), 
(e), or (f) or meet the exemption in Sec.  60.5402c(c). Alternatively, 
if you comply with the GHG standards for process unit designated 
facilities using the standards in Sec.  60.5401c, you must comply with 
paragraphs (i)(5) through (16) of this section, unless you meet the 
exemption in Sec.  60.5402c(b) or (c) or the exception in Sec.  
60.5402c(e) and (f).
    (1) You must conduct monitoring for each pump in light liquid 
service, pressure relief device in gas/vapor service, valve in gas/
vapor and light liquid service and connector in gas/vapor and light 
liquid service as required by Sec.  60.5400c(b).
    (2) You must conduct monitoring as required by Sec.  60.5400c(c) 
for each pump in light liquid service.
    (3) You must conduct monitoring as required by Sec.  60.5400c(d) 
for each pressure relief device in gas/vapor service.
    (4) You must comply with the equipment requirements for each open-

[[Page 17186]]

ended valve or line as required by Sec.  60.5400c(e).
    (5) You must conduct monitoring for each pump in light liquid 
service as required by Sec.  60.5401c(b).
    (6) You must conduct monitoring for each pressure relief device in 
gas/vapor service as required by Sec.  60.5401c(c).
    (7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec.  60.5401c(d).
    (8) You must conduct monitoring for each valve in gas/vapor or 
light liquid service as required by Sec.  60.5401c(f).
    (9) You must conduct monitoring for each pump, valve, and connector 
in heavy liquid service and each pressure relief device in light liquid 
or heavy liquid service as required by Sec.  60.5401c(g).
    (10) You must conduct monitoring for each connector in gas/vapor or 
light liquid service as required by Sec.  60.5401c(h).
    (11) You must collect emissions and meet the closed vent system 
requirements as required by Sec.  60.5416c for each pump equipped with 
a dual mechanical seal system that degasses the barrier fluid reservoir 
to a process or a control device, each pump which captures and 
transports leakage from the seal or seals to a process or control 
device, or each pressure relief device which captures and transports 
leakage through the pressure relief device to a process or control 
device.
    (12) You must comply with the requirements specified in paragraph 
(f) of this section.
    (13) You must tag and repair each identified leak as required in 
Sec.  60.5400c(h) or Sec.  60.5400c(i), as applicable.
    (14) You must submit semiannual reports as required by Sec.  
60.5422c and the annual reports in Sec.  60.5420b(b)(10)(i) through 
(iv), as applicable.
    (15) You must maintain the records specified by Sec.  
60.5420c(c)(7), (c)(9), and (c)(11) as applicable and Sec.  60.5421c.
    (j) Continuous compliance. For each fugitive emissions components 
designated facility, you must demonstrate continuous compliance with 
the requirements of Sec.  60.5397c(a) according to paragraphs (j)(1) 
through (4) of this section.
    (1) You must conduct periodic monitoring surveys as required in 
Sec.  60.5397c(e) and (g).
    (2) You must repair each identified source of fugitive emissions as 
required in Sec.  60.5397c(h).
    (3) You must submit annual reports for fugitive emissions 
components designated facilities as required in Sec.  60.5420c(b)(1) 
and (8).
    (4) You must maintain records as specified in Sec.  
60.5420c(c)(15).


Sec.  60.5416c   What are the initial and continuous cover and closed 
vent system inspection and monitoring requirements?

    For each closed vent system and cover at your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, storage 
vessel, and process unit equipment designated facilities, you must 
comply with the applicable requirements of paragraphs (a) and (b) of 
this section. Each self-contained natural gas process controller must 
comply with paragraph (b) of this section.
    (a) Inspections for closed vent systems, covers, and bypass 
devices. If you install a control device or route emissions to a 
process, you must inspect each closed vent system according to the 
procedures and schedule specified in paragraphs (a)(1) and (2) of this 
section, inspect each cover according to the procedures and schedule 
specified in paragraph (a)(3) of this section, and inspect each bypass 
device according to the procedures of paragraph (a)(4) of this section, 
except as provided in paragraphs (b)(6) and (7) of this section.
    (1) For each closed vent system joint, seam, or other connection 
that is permanently or semi-permanently sealed (e.g., a welded joint 
between two sections of hard piping or a bolted and gasketed ducting 
flange), you must meet the requirements specified in paragraphs 
(a)(1)(i) through (iii) of this section.
    (i) Conduct an initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section to demonstrate 
that the closed vent system operates with no identifiable emissions 
within the first 30 calendar days after routing emissions through the 
closed vent system.
    (ii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in piping; loose connections; liquid 
leaks; or broken or missing caps or other closure devices. You must 
monitor a component or connection using the test methods and procedures 
in paragraph (b) of this section to demonstrate that it operates with 
no identifiable emissions following any time the component is repaired 
or replaced or the connection is unsealed.
    (iii) Conduct AVO inspections in accordance with and at the same 
frequency as specified for fugitive emissions components designated 
facilities located at the same type of site as specified in Sec.  
60.5397c(g). Process unit equipment designated facilities must conduct 
annual AVO inspections concurrent with the inspections required by 
paragraph (a)(1)(ii) of this section.
    (2) For closed vent system components other than those specified in 
paragraph (a)(1) of this section, you must meet the requirements of 
paragraphs (a)(2)(i) through (iv) of this section.
    (i) Conduct an initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section within the first 
30 calendars days after routing emissions through the closed vent 
system to demonstrate that the closed vent system operates with no 
identifiable emissions.
    (ii) Conduct inspections according to the test methods, procedures, 
and frequencies specified in paragraph (b) of this section to 
demonstrate that the components or connections operate with no 
identifiable emissions.
    (iii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in ductwork; loose connections; liquid 
leaks; or broken or missing caps or other closure devices. You must 
monitor a component or connection using the test methods and procedures 
in paragraph (b) of this section to demonstrate that it operates with 
no identifiable emissions following any time the component is repaired 
or replaced or the connection is unsealed.
    (iv) Conduct AVO inspections in accordance with and at the same 
frequency as specified for fugitive emissions components designated 
facilities located at the same type of site, as specified in Sec.  
60.5397c(g). Process unit equipment designated facilities must conduct 
annual AVO inspections concurrent with the inspections required by 
paragraph (a)(2)(iii) of this section.
    (3) For each cover, you must meet the requirements of paragraphs 
(a)(3)(i) through (iv) of this section.
    (i) Conduct the inspections specified in paragraphs (a)(3)(ii) 
through (iv) of this section to identify defects that could result in 
air emissions and to ensure the cover operates with no identifiable 
emissions. Defects include, but are not limited to, visible cracks, 
holes, or gaps in the cover, or between the cover and the separator 
wall; broken, cracked, or otherwise damaged seals or gaskets on closure 
devices; and broken or missing hatches, access covers, caps, or other 
closure devices. In the case where the storage vessel is buried 
partially or entirely

[[Page 17187]]

underground, you must inspect only those portions of the cover that 
extend to or above the ground surface, and those connections that are 
on such portions of the cover (e.g., fill ports, access hatches, gauge 
wells, etc.) and can be opened to the atmosphere.
    (ii) An initial inspection according to the test methods and 
procedures specified in paragraph (b) of this section, following 
installation of the cover to demonstrate that each cover operates with 
no identifiable emissions.
    (iii) Conduct AVO inspections in accordance with and at the same 
frequency as specified for fugitive emissions components designated 
facilities located at the same type of site as specified in Sec.  
60.5397b(g). Process unit equipment designated facilities must conduct 
annual AVO inspections concurrent with the inspections required by 
paragraph (a)(1)(ii) of this section.
    (iv) Inspections according to the test methods, procedures, and 
schedules specified in paragraph (b) of this section to demonstrate 
that each cover operates with no identifiable emissions.
    (4) For each bypass device, except as provided for in Sec.  
60.5411c(a)(4)(ii), you must meet the requirements of paragraph 
(a)(4)(i) or (ii) of this section.
    (i) Set the flow indicator to take a reading at least once every 15 
minutes at the inlet to the bypass device that could divert the stream 
away from the control device and to the atmosphere.
    (ii) If the bypass device valve installed at the inlet to the 
bypass device is secured in the non-diverting position using a car-seal 
or a lock-and-key type configuration, visually inspect the seal or 
closure mechanism at least once every month to verify that the valve is 
maintained in the non-diverting position and the vent stream is not 
diverted through the bypass device.
    (b) No identifiable emissions test methods and procedures. If you 
are required to conduct an inspection of a closed vent system and cover 
as specified in paragraph (a)(1), (2), or (3) of this section or Sec.  
60.5398c(b), you must meet the requirements of paragraphs (b)(1) 
through (9) of this section. You must meet the requirements of 
paragraphs (b)(1), (2), (4), and (9) of this section for each self-
contained process controller at your process controller designated 
facility as specified at Sec.  60.5394c(a)(2).
    (1) Initial and periodic inspection. You must conduct initial and 
periodic no identifiable emissions inspections as specified in 
paragraphs (b)(1)(i) through (iii) of this section, as applicable.
    (i) You must conduct inspections for no identifiable emissions from 
your closed vent systems and covers at your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, or 
storage vessel designated facility, using the procedures for conducting 
OGI inspections in Sec.  60.5397c(c)(7). As an alternative you may 
conduct inspections in accordance with Method 21 of appendix A-7 to 
this part. Monitoring must be conducted at the same frequency as 
specified for fugitive emissions components designated facilities 
located at the same type of site, as specified in Sec.  60.5397c(g).
    (ii) For closed vent systems and covers located at onshore natural 
gas processing plants, OGI inspections for no identifiable emissions 
must be conducted initially and bimonthly in accordance with appendix K 
to this part. As an alternative you must conduct quarterly inspections 
for no identifiable emissions in accordance with Method 21 of appendix 
A-7 to this part.
    (iii) For your self-contained process controller, you must conduct 
initial and quarterly inspections for no identifiable emissions using 
the procedures for conducting OGI inspections in Sec.  60.5397c(c)(7). 
As an alternative you may conduct quarterly inspections in accordance 
with Method 21 of appendix A-7 to this part.
    (2) OGI inspection. Where OGI is used, the closed vent system, 
cover, or self-contained process controller is determined to operate 
with no identifiable emissions if no emissions are imaged during the 
inspection. Emissions imaged by OGI constitute a deviation of the no 
identifiable emissions standard until an OGI inspection conducted in 
accordance with this paragraph (b)(2) of this section determines that 
the closed vent system, cover, or self-contained process controller, as 
applicable, operates with no identifiable emissions.
    (3) AVO inspection. Where AVO inspections are required, the closed 
vent system or cover is determined to operate with no identifiable 
emissions if no emissions are detected by AVO. Emissions detected by 
AVO constitute a deviation of the no identifiable emissions standard 
until an AVO inspection determines that the closed vent system or cover 
operates with no identifiable emissions.
    (4) Method 21 inspection. Where Method 21 of appendix A-7 to this 
part is used for the inspection, the requirements of paragraphs 
(b)(4)(i) through (vii) of this section apply.
    (i) The detection instrument must meet the performance criteria of 
Method 21 of appendix A-7 to this part, except that the instrument 
response factor criteria in section 8.1.1 of Method 21 must be for the 
average composition of the fluid and not for each individual organic 
compound in the stream.
    (ii) You must calibrate the detection instrument before use on each 
day of its use by the procedures specified in Method 21 of appendix A-7 
to this part.
    (iii) Calibration gases must be as specified in paragraphs 
(b)(4)(iii)(A) and (B) of this section.
    (A) Zero air (less than 10 parts per million by volume hydrocarbon 
in air).
    (B) A mixture of methane in air at a concentration less than 500 
ppmv.
    (iv) You may choose to adjust or not adjust the detection 
instrument readings to account for the background organic concentration 
level. If you choose to adjust the instrument readings for the 
background level, you must determine the background level value 
according to the procedures in Method 21 of appendix A-7 to this part.
    (v) Your detection instrument must meet the performance criteria 
specified in paragraphs (b)(4)(v)(A) and (B) of this section.
    (A) Except as provided in paragraph (b)(4)(v)(B) of this section, 
the detection instrument must meet the performance criteria of Method 
21 of appendix A-7 to this part, except the instrument response factor 
criteria in section 8.1.1 of Method 21 must be for the average 
composition of the process fluid, not each individual volatile organic 
compound in the stream. For process streams that contain nitrogen, air, 
or other inerts that are not organic hazardous air pollutants or 
volatile organic compounds, you must calculate the average stream 
response factor on an inert-free basis.
    (B) If no instrument is available that will meet the performance 
criteria specified in paragraph (b)(4)(v)(A) of this section, you may 
adjust the instrument readings by multiplying by the average response 
factor of the process fluid, calculated on an inert-free basis, as 
described in paragraph (b)(4)(v)(A) of this section.
    (vi) You must determine if a potential leak interface operates with 
no identifiable emissions, as applicable, using the applicable 
procedure specified in paragraph (b)(4)(vi)(A) or (B) of this section.
    (A) If you choose not to adjust the detection instrument readings 
for the background organic concentration level, then you must directly 
compare the maximum organic concentration value measured by the 
detection instrument to the applicable value for the potential leak 
interface as specified in paragraph (b)(4)(vii) of this section.

[[Page 17188]]

    (B) If you choose to adjust the detection instrument readings for 
the background organic concentration level, you must compare the value 
of the arithmetic difference between the maximum organic concentration 
value measured by the instrument and the background organic 
concentration value as determined in paragraph (b)(4)(iv) of this 
section with the applicable value for the potential leak interface as 
specified in paragraph (b)(4)(vii) of this section.
    (vii) A closed vent system, cover, or self-contained process 
controller is determined to operate with no identifiable emissions if 
the organic concentration value determined in paragraph (b)(4)(vi) of 
this section is less than 500 ppmv. An organic concentration value 
determined in paragraph (b)(4)(vi) of this section of greater than or 
equal to 500 ppmv constitutes a deviation of the no identifiable 
emissions standard until an inspection conducted in accordance with 
this paragraph (b)(4) of this section determines that the closed vent 
system, cover, or self-contained process controller, as applicable, 
operates with no identifiable emissions.
    (5) Repairs. Whenever emissions or a defect is detected, you must 
repair the emissions or defect as soon as practicable according to the 
requirements of paragraphs (b)(5)(i) through (iii) of this section, 
except as provided in paragraph (b)(6) of this section.
    (i) A first attempt at repair must be made no later than 5 calendar 
days after the emissions or defect is detected.
    (ii) Repair must be completed no later than 30 calendar days after 
the emissions or defect is detected.
    (iii) For covers, grease or another substance compatible with the 
gasket material must be applied to deteriorating or cracked gaskets to 
improve the seal while awaiting repair.
    (6) Delay of repair. Delay of repair of a closed vent system or 
cover for which emissions or defects have been detected is allowed if 
the repair is technically infeasible without a shutdown, or if you 
determine that emissions resulting from immediate repair would be 
greater than the emissions likely to result from delay of repair. You 
must complete repair of such equipment by the end of the next shutdown.
    (7) Unsafe to inspect requirements. You may designate any parts of 
the closed vent system or cover as unsafe to inspect if the 
requirements of paragraphs (b)(7)(i) and (ii) of this section are met. 
Unsafe to inspect parts are exempt from the inspection requirements of 
paragraphs (a)(1) through (3) of this section.
    (i) You determine that the equipment is unsafe to inspect because 
inspecting personnel would be exposed to an imminent or potential 
danger as a consequence of complying with paragraphs (a)(1), (2), or 
(3) of this section.
    (ii) You have a written plan that requires inspection of the 
equipment as frequently as practicable during safe-to-inspect times.
    (8) Difficult to inspect requirements. You may designate any parts 
of the closed vent system or cover as difficult to inspect if the 
requirements of paragraphs (b)(8)(i) and (ii) of this section are met. 
Difficult to inspect parts are exempt from the inspection requirements 
of paragraphs (a)(1) through (3) of this section.
    (i) You determine that the equipment cannot be inspected without 
elevating the inspecting personnel more than 2 meters above a support 
surface.
    (ii) You have a written plan that requires inspection of the 
equipment at least once every 5 years.
    (9) Records and reports. You must maintain records of all 
inspection results as specified in Sec.  60.5420c(c)(7) through (9). 
You must submit the reports as specified in Sec.  60.5420c(b)(10).


Sec.  60.5417c   What are the continuous monitoring requirements for my 
control devices?

    You must meet the requirements of this section to demonstrate 
continuous compliance for each control device used to meet emission 
standards for your well, centrifugal compressor, reciprocating 
compressor, process controller, storage vessel, and process unit 
equipment designated facilities.
    (a) For each control device used to comply with the emission 
reduction standard in Sec.  60.5391c(b) for well designated facilities, 
Sec.  60.5392c(a)(3) for centrifugal compressor designated facilities, 
Sec.  60.5393c(d)(2) for reciprocating compressor designated 
facilities, Sec.  60.5394c(b)(3) for your process controller designated 
facility in Alaska, Sec.  60.5393c(b)(1) for your pumps designated 
facility, Sec.  60.5396c(a)(2) for your storage vessel designated 
facility, or either Sec.  60.5400c(f) or Sec.  60.5401c(e) for your 
process equipment designated facility, you must install and operate a 
continuous parameter monitoring system for each control device as 
specified in paragraphs (c) through (h) of this section, except as 
provided for in paragraph (b) of this section. If you install and 
operate a flare in accordance with Sec.  60.5412c(a)(3), you are exempt 
from the requirements of paragraph (f) of this section. If you operate 
an enclosed combustion device or flare using an alternative test method 
approved under Sec.  60.5412c(d), you must operate the control device 
as specified in paragraph (i) of this section instead of using the 
procedures specified in paragraphs (c) through (h) of this section. You 
must keep records and report in accordance with paragraph (j) of this 
section.
    (b) You are exempt from the monitoring requirements specified in 
paragraphs (c) through (g) of this section for the control devices 
listed in paragraphs (b)(1) and (2) of this section.
    (1) A boiler or process heater in which all vent streams are 
introduced with the primary fuel or are used as the primary fuel.
    (2) A boiler or process heater with a design heat input capacity 
equal to or greater than 44 megawatts.
    (c) You must meet the specifications and requirements of paragraphs 
(c)(1) through (4) of this section.
    (1) Except for continuous parameter monitoring systems used to 
detect the presence of a pilot or combustion flame, each continuous 
parameter monitoring system must measure data values at least once 
every hour and record the values for each parameter as required in 
paragraphs (c)(1)(i) or (ii) of this section. Continuous parameter 
monitoring systems used to detect the presence of a pilot or combustion 
flame must record a reading at least once every 5 minutes.
    (i) Each measured data value.
    (ii) Each block average value for each 1-hour period or shorter 
periods calculated from all measured data values during each period.
    (2) You must prepare a monitoring plan that covers each control 
device for designated facilities within each company-defined area. The 
monitoring plan must address the monitoring system design, data 
collection, and the quality assurance and quality control elements 
outlined in paragraphs (c)(2)(i) through (v) of this section. You must 
install, calibrate, operate, and maintain each continuous parameter 
monitoring system in accordance with the procedures in your monitoring 
plan. Heat sensing monitoring devices that indicate the continuous 
ignition of a pilot or combustion flame are exempt from the 
calibration, quality assurance and quality control requirements of this 
section.
    (i) The performance criteria and design specifications for the 
monitoring system equipment, including the sample interface, detector 
signal analyzer, and data acquisition and calculations.
    (ii) Sampling interface (e.g., thermocouple) location such that the

[[Page 17189]]

monitoring system will provide representative measurements.
    (iii) Equipment performance checks, system accuracy audits, or 
other audit procedures.
    (iv) Ongoing operation and maintenance procedures in accordance 
with provisions in Sec.  60.13(b).
    (v) Ongoing recordkeeping procedures in accordance with provisions 
in Sec.  60.7(f).
    (3) You must conduct the continuous parameter monitoring system 
equipment performance checks, system accuracy audits, or other audit 
procedures specified in the monitoring plan at least once every 12 
months.
    (4) You must conduct a performance evaluation of each continuous 
parameter monitoring system in accordance with the monitoring plan. 
Heat sensing monitoring devices that indicate the continuous ignition 
of a pilot or combustion flame are exempt from the calibration, quality 
assurance and quality control requirements of this section.
    (d) You must install, calibrate, operate, and maintain a device 
equipped with a continuous recorder to measure the values of operating 
parameters appropriate for the control device as specified in 
paragraphs (d)(1) through (8) of this section, as applicable. Instead 
of complying with the requirements in paragraphs (d)(1) through (8) of 
this section, you may install an organic monitoring device equipped 
with a continuous recorder that measures the concentration level of 
organic compounds in the exhaust vent stream from the control device to 
demonstrate compliance with the applicable performance requirement 
specified in Sec.  60.5412c(a)(1). The monitor must meet the 
requirements of Performance Specification 8 or 9 of appendix B to this 
part. You must install, calibrate, and maintain the monitor according 
to the manufacturer's specifications and the requirements in 
Performance Specification 8 or 9. You may also request approval from 
the Administrator to monitor different operating parameters than those 
specified in paragraphs (d)(1) through (8) of this section in 
accordance with Sec.  60.13(i).
    (1) For an enclosed combustion device that demonstrates during the 
performance test conducted under Sec.  60.5413c(b) that combustion zone 
temperature is an accurate indicator of performance, a temperature 
monitoring device equipped with a continuous recorder. The monitoring 
device must have a minimum accuracy of <plus-minus>1 percent of the 
temperature being monitored in degrees Celsius, or <plus-minus>2.5 
[deg]C, whichever value is greater. You must install the temperature 
sensor at a location representative of the combustion zone temperature. 
You must also comply with the requirements of paragraphs (d)(8)(i), 
(iv), and (v) of this section.
    (2) For a catalytic vapor incinerator, a temperature monitoring 
device equipped with a continuous recorder. The device must be capable 
of monitoring temperature at two locations and have a minimum accuracy 
of <plus-minus>1 percent of the temperature being monitored in degrees 
Celsius, or <plus-minus>2.5 [deg]C, whichever value is greater. You 
must install one temperature sensor in the vent stream at the nearest 
feasible point to the catalyst bed inlet, and you must install a second 
temperature sensor in the vent stream at the nearest feasible point to 
the catalyst bed outlet.
    (3) For a boiler or process heater, a temperature monitoring device 
equipped with a continuous recorder. The temperature monitoring device 
must have a minimum accuracy of <plus-minus>1 percent of the 
temperature being monitored in degrees Celsius, or <plus-minus>2.5 
[deg]C, whichever value is greater. You must install the temperature 
sensor at a location representative of the combustion zone temperature.
    (4) For a condenser, a temperature monitoring device equipped with 
a continuous recorder. The temperature monitoring device must have a 
minimum accuracy of <plus-minus>1 percent of the temperature being 
monitored in degrees Celsius, or <plus-minus>2.5 [deg]C, whichever 
value is greater. You must install the temperature sensor at a location 
in the exhaust vent stream from the condenser.
    (5) For a regenerative-type carbon adsorption system, a continuous 
monitoring system that meets the specifications in paragraphs (d)(5)(i) 
and (ii) of this section. You also must monitor the design carbon 
service life established using a design analysis performed as specified 
in Sec.  60.5413c(c)(2).
    (i) The continuous parameter monitoring system must measure and 
record the average total regeneration stream mass flow or volumetric 
flow during each carbon bed regeneration cycle. The flow sensor must 
have a measurement sensitivity of 5 percent of the flow rate or 10 
cubic feet per minute, whichever is greater. You must check the 
mechanical connections for leakage at least every month, and you must 
perform a visual inspection at least every 3 months of all components 
of the flow continuous parameter monitoring system for physical and 
operational integrity and all electrical connections for oxidation and 
galvanic corrosion if your flow continuous parameter monitoring system 
is not equipped with a redundant flow sensor; and
    (ii) The continuous parameter monitoring system must measure and 
record the average carbon bed temperature for the duration of the 
carbon bed steaming cycle and measure the actual carbon bed temperature 
after regeneration and within 15 minutes of completing the cooling 
cycle. The temperature monitoring device must have a minimum accuracy 
of <plus-minus>1 percent of the temperature being monitored in degrees 
Celsius, or <plus-minus>2.5 [deg]C, whichever value is greater.
    (6) For a nonregenerative-type carbon adsorption system, you must 
monitor the design carbon replacement interval established using a 
design analysis performed as specified in Sec.  60.5413c(c)(3). The 
design carbon replacement interval must be based on the total carbon 
working capacity of the control device and source operating schedule.
    (7) For a combustion control device whose model is tested under 
Sec.  60.5413c(d), continuous monitoring systems as specified in 
paragraphs (d)(8)(i) through (iv) and (vi) of this section and visible 
emission observations conducted as specified in paragraph (d)(8)(v) of 
this section.
    (8) For an enclosed combustion device other than those listed in 
paragraphs (d)(1) through (3) and (7) of this section or for a flare, 
continuous monitoring systems as specified in paragraphs (d)(8)(i) 
through (iv) of this section and visible emission observations 
conducted as specified in paragraph (d)(8)(v) of this section. 
Additionally, for enclosed combustion devices or flares that are air-
assisted or steam-assisted, the continuous monitoring systems specified 
in paragraph (d)(8)(vi) of this section.
    (i) Continuously monitor at least once every five minutes for the 
presence of a pilot flame or combustion flame using a device 
(including, but not limited to, a thermocouple, ultraviolet beam 
sensor, or infrared sensor) capable of detecting that the pilot or 
combustion flame is present at all times. An alert must be sent to the 
nearest control room whenever the pilot or combustion flame is unlit. 
Continuous monitoring systems used for the presence of a pilot flame or 
combustion flame are not subject to a minimum accuracy requirement 
beyond being able to detect the presence or absence of a flame and are 
exempt from the calibration requirements of this section.
    (ii) Except as provided in this paragraph (d)(8)(ii) and paragraph 
(d)(8)(iii) of this section, use one of the following methods to 
continuously

[[Page 17190]]

determine the NHV of the inlet gas to the enclosed combustion device or 
flare at standard conditions. If the only inlet gas stream to the 
enclosed combustion device or flare is associated gas from a well 
designated facility, the NHV of the inlet stream is considered to be 
sufficiently above the minimum required NHV for the inlet gas, and you 
are not required to conduct the continuous monitoring in this paragraph 
(d)(8)(ii) or the demonstration in paragraph (d)(8)(iii) of this 
section.
    (A) A calorimeter with a minimum accuracy of <plus-minus>2 percent 
of span.
    (B) A gas chromatograph that meets the requirements in paragraphs 
(d)(8)(ii)(B)(1) through (5) of this section.
    (1) You must follow the procedure in Performance Specification 9 of 
appendix B to this part, except that a single daily mid-level 
calibration check can be used (rather than triplicate analysis), the 
multi-point calibration can be conducted quarterly (rather than 
monthly), and the sampling line temperature must be maintained at a 
minimum temperature of 60 [deg]C (rather than 120 [deg]C). Calibration 
gas cylinders must be certified to an accuracy of 2 percent and 
traceable to National Institute of Standards and Technology (NIST) 
standards.
    (2) You must meet the accuracy requirements in Performance 
Specification 9 of appendix B to this part.
    (3) You must use a calibration gas or multiple gases that includes 
the compounds that are reasonably expected to be present in the flare 
gas stream. If multiple calibration gases are necessary to cover all 
compounds, you must calibrate the instrument on all of the gases. You 
may only use the compounds used to calibrate the gas chromatograph in 
the calculation of the vent gas NHV.
    (4) In lieu of the calibration gas described in paragraph 
(d)(8)(ii)(B)(3) of this section, you may use a surrogate calibration 
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All 
of the calibration gases may be combined in one cylinder. If multiple 
calibration gases are necessary to cover all compounds, you must 
calibrate the instrument on all of the gases. Use the response factor 
for the nearest normal hydrocarbon (i.e., n-alkane) in the calibration 
mixture to quantify unknown components detected in the analysis. Use 
the response factor for n-pentane to quantify unknown components 
detected in the analysis that elute after n-pentane.
    (5) To determine the NHV of the vent gas, determine the product of 
the volume fraction of the individual component in the vent gas and the 
net heating value of that individual component. Sum the products for 
all components in the vent gas to determine the NHV for the vent gas. 
For the net heating value of each individual component, use the net 
heating value at 25 [deg]C and 1 atmosphere.
    (C) A mass spectrometer that meets the requirements in paragraphs 
(d)(8)(ii)(C)(1) through (6) of this section.
    (1) You must meet applicable requirements in Performance 
Specification 9 of appendix B of this part for continuous monitoring 
system acceptance including, but not limited to, performing an initial 
multi-point calibration check at three concentrations following the 
procedure in Section 10.1. A single daily mid-level calibration check 
can be used (rather than triplicate analysis), the multi-point 
calibration can be conducted quarterly (rather than monthly), and the 
sampling line temperature must be maintained at a minimum temperature 
of 60 [deg]C (rather than 120 [deg]C). Calibration gas cylinders must 
be certified to an accuracy of 2 percent and traceable to NIST 
standards.
    (2) The average instrument calibration error (CE) for each 
calibration compound at any calibration concentration must not differ 
by more than 10 percent from the certified cylinder gas value. The CE 
for each component in the calibration blend must be calculated using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.042

Where:

C<INF>m</INF> = Average instrument response (ppm).
C<INF>a</INF> = Certified cylinder gas value (ppm).

    (3) You must use a calibration gas or multiple gases that includes 
the compounds that are reasonably expected to be present in the flare 
gas stream. If multiple calibration gases are necessary to cover all 
compounds, you must calibrate the instrument on all of the gases. You 
may only use the compounds used to calibrate the mass spectrometer in 
the calculation of the vent gas NHV.
    (4) In lieu of the calibration gas described in paragraph 
(d)(8)(ii)(C)(3) of this section, you may use a surrogate calibration 
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All 
of the calibration gases may be combined in one cylinder. If multiple 
calibration gases are necessary to cover all compounds, you must 
calibrate the instrument on all of the gases. For unknown gas 
components that have similar analytical mass fragments to calibration 
compounds, you may report the unknowns as an increase in the overlapped 
calibration gas compound. For unknown compounds that produce mass 
fragments that do not overlap calibration compounds, you may use the 
response factor for the nearest molecular weight hydrocarbon in the 
calibration mix to quantify the unknown component. You may use the 
response factor for n-pentane to quantify any unknown components 
detected with a higher molecular weight than n-pentane.
    (5) You must perform an initial calibration to identify mass 
fragment overlap and response factors for the target compounds.
    (6) To determine the NHV of the vent gas, determine the product of 
the volume fraction of the individual component in the vent gas and the 
net heating value of that individual component. Sum the products for 
all components in the vent gas to determine the NHV for the vent gas. 
For the net heating value of each individual component, use the net 
heating value at 25 [deg]C and 1 atmosphere.
    (D) A grab sampling system capable of collecting an evacuated 
canister sample for subsequent compositional analysis at least once 
every eight hours. Subsequent compositional analysis of the samples 
must be performed according to ASTM D1945-14 (R2019) (incorporated by 
reference, see Sec.  60.17). To determine the NHV of the vent gas, 
determine the product of the volume fraction of the individual 
component in the vent gas and the net heating value of that

[[Page 17191]]

individual component. Sum the products for all components in the vent 
gas to determine the NHV for the vent gas. For the net heating value of 
each individual component, use the net heating value at 25 [deg]C and 1 
atmosphere.
    (iii) For an unassisted or pressure-assisted flare or enclosed 
combustion device, if you demonstrate according to the methods 
described in paragraphs (d)(8)(iii)(A) through (F) of this section that 
the NHV of the inlet gas to the enclosed combustion device or flare 
consistently exceeds the applicable operating limit specified in Sec.  
60.5415c(e)(1)(vii)(B) or (C)(1), continuous monitoring of the NHV is 
not required, but you must conduct the ongoing sampling in paragraph 
(d)(8)(iii)(G) of this section. For flares and enclosed combustion 
devices that use only perimeter assist air and do not use steam assist 
or premix assist air, if you demonstrate according to the methods 
described in paragraphs (d)(8)(iii)(A) through (F) of this section that 
the NHV of the inlet gas to the enclosed combustion device or flare 
consistently exceeds 300 Btu/scf, continuous monitoring of the NHV is 
not required, but you must conduct the ongoing sampling in paragraph 
(d)(8)(iii)(G) of this section. For an unassisted or pressure-assisted 
flare or enclosed combustion device, in lieu of conducting the 
demonstration outlined in paragraphs (d)(8)(iii)(A) through (D) of this 
section, you may conduct the demonstration outlined in paragraph 
(d)(8)(iii)(H) of this section, but you must still comply with 
paragraphs (d)(8)(iii)(E) through (G) of this section.
    (A) Continuously monitor or collect a sample of the inlet gas to 
the enclosed combustion device or flare twice daily to determine the 
average NHV of the gas stream for 14 consecutive operating days. If you 
do not continuously monitor the NHV, the minimum time of collection for 
each individual sample be at least one hour. Consecutive samples must 
be separated by at least 6 hours. If inlet gas flow is intermittent 
such that there are not at least 28 samples over the 14 operating day 
period, you must continue to collect samples of the inlet gas beyond 
the 14 operating day period until you collect a minimum of 28 samples.
    (B) If you collect samples twice per day, count the number of 
samples where the NHV value is less than 1.2 times the applicable 
operating limit specified in Sec.  60.5415c(e)(1)(vii)(B) or (C)(1), or 
paragraph (d)(8)(iii) of this section (i.e., values that are less than 
240, 360, or 960 Btu/scf, as applicable) during the sample collection 
period in paragraph (d)(8)(iii)(A) of this section.
    (C) If you continuously sample the inlet stream for 14 days, count 
the number of hourly average NHV values that are less than the 
applicable operating limit specified in Sec.  60.5415c(e)(1)(vii)(B) or 
(C)(1), or paragraph (d)(8)(iii) of this section (i.e., values that are 
less than 200, 300, or 800 Btu/scf, as applicable), during the sample 
collection period in paragraph (d)(8)(iii)(A) of this section.
    (D) If there are no samples counted under paragraph (d)(8)(iii)(B) 
of this section or there are no hourly values counted under paragraph 
(d)(8)(iii)(C) of this section, the gas stream is considered to 
consistently exceed the applicable NHV operating limit and on-going 
continuous monitoring is not required.
    (E) If process operations are revised that could impact the NHV of 
the gas sent to the enclosed combustion device or flare, such as the 
removal or addition of process equipment, and at any time the 
Administrator requires, re-evaluation of the gas stream must be 
performed according to paragraphs (d)(8)(iii)(A) through (D) of this 
section to ensure the gas stream still consistently exceeds the 
applicable operating limit specified in Sec.  60.5415c(e)(1)(vii)(B) or 
(C)(1), or paragraph (d)(8)(iii) of this section.
    (F) When collecting samples under paragraph (d)(8)(iii)(A) of this 
section, the owner or operator must account for any sources of inert 
gases that can be sent to the enclosed combustion device or flare 
(e.g., streams from compressors in acid gas service, streams from 
enhanced oil recovery facilities). The report in Sec.  
60.5420c(b)(10)(v)(I) and the records of the demonstration in Sec.  
60.5420c(c)(10)(vi) must note whether the enclosed combustion device or 
flare has the potential to receive inert gases, and if so, whether the 
sampling included periods where the highest percentage of inert gases 
were sent to the enclosed combustion device or flare. If the 
introduction of inerts is intermittent and does not occur during the 
initial demonstration, the introduction of inerts will be considered a 
revision to process operations that triggers a re-evaluation under 
paragraph (d)(8)(iii)(E) of this section. If conditions at the site did 
not allow sampling during periods where the introduction of inert gases 
was at the highest percentage possible, increasing the percentage of 
inerts will be considered a revision to process operations that 
triggers a re-evaluation under paragraph (d)(8)(iii)(E) of this 
section.
    (G) You must collect three samples of the inlet gas to the enclosed 
combustion device or flare at least once every 5 years. The minimum 
time of collection for each individual sample must be at least one 
hour. The samples must be taken during the period with the lowest 
expected NHV (i.e., the period with the highest percentage of inerts). 
The first set of periodic samples must be taken, or continuous 
monitoring commenced, no later than 60 calendar months following the 
last sample taken under paragraph (d)(8)(iii)(A) of this section. 
Subsequent periodic samples must be taken, or continuous monitoring 
commenced, no later than 60 calendar months following the previous 
sample. If any sample has an NHV value less than 1.2 times the 
applicable operating limit specified in Sec.  60.5415c(e)(1)(vii)(B) or 
(C)(1), or paragraph (d)(8)(iii) of this section (i.e., values that are 
less than 240, 360, or 960 Btu/scf, as applicable), you must conduct 
the monitoring required by paragraph (d)(8)(ii) of this section.
    (H) You may request an alternative test method under Sec.  
60.5412c(d) to demonstrate that the flare or enclosed combustion device 
reduces methane and VOC in the gases vented to the device by 95.0 
percent by weight or greater. You must use an alternative test method 
that demonstrates compliance with the combustion efficiency limit; you 
may not use an alternative test method that demonstrates compliance 
with NHV<INF>cz</INF> and NHV<INF>dil</INF> in lieu of measuring 
combustion efficiency directly. You must measure data values at the 
frequency specified in the alternative test method and conduct the 
quality assurance and quality control requirements outlined in the 
alternative test method at the frequency outlined in the alternative 
test method. You must monitor the combustion efficiency of the flare 
continuously for 14 days. If there are no values of the combustion 
efficiency measured by the alternative test method that are less than 
95.0 percent, the gas stream is considered to consistently exceed the 
applicable NHV operating limit, and you are not required to 
continuously monitor the NHV of the inlet gas to the flare or enclosed 
combustion device.
    (iv) Except as noted in paragraphs (d)(8)(iv)(A) through (E) of 
this section, a continuous parameter monitoring system for measuring 
the flow of gas to the enclosed combustion device or flare. You may use 
direct flow meters or other parameter monitoring systems combined with 
engineering calculations, such as inlet line pressure, line size, and 
burner nozzle dimensions, to satisfy this requirement. The

[[Page 17192]]

monitoring instrument must have an accuracy of <plus-minus>10 percent 
or better at the maximum expected flow rate.
    (A) Pressure-assisted flares and pressure-assisted enclosed 
combustion devices are not required to have a continuous parameter 
monitoring system for measuring the inlet flow of gas to the device if 
you install, calibrate, maintain, and operate a backpressure regulator 
valve calibrated to open at the minimum pressure set point 
corresponding to the minimum inlet gas flow rate. The set point must be 
consistent with manufacturer specifications for minimum flow or 
pressure and must be supported by an engineering evaluation. At least 
annually, you must confirm that the backpressure regulator valve set 
point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (B) Unassisted flares are not required to have a continuous 
parameter monitoring system for measuring the inlet flow of gas to the 
device if you meet the conditions in paragraphs (d)(8)(iv)(B)(1) and 
(2) of this section.
    (1) You must demonstrate, based on the maximum potential pressure 
of units manifolded to the flare and applicable engineering 
calculations for the manifolded closed vent system, that the maximum 
flow rate to the flare cannot cause the flare tip velocity to exceed 
18.3 meter/second (60 feet/second). If there are changes to the process 
or control device that can be reasonably expected to impact the maximum 
flow rate to the flare, you must conduct a new demonstration to 
determine whether the maximum flow rate to the flare is less than 18.3 
meter/second (60 feet/second).
    (2) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (C) Unassisted enclosed combustion devices are not required to have 
a continuous parameter monitoring system for measuring the inlet flow 
of gas to the device if you meet the conditions in paragraphs 
(d)(8)(iv)(C)(1) and (2) of this section.
    (1) You must demonstrate, based on the maximum potential pressure 
of units manifolded to the enclosed combustion device and applicable 
engineering calculations for the manifolded closed vent system, that 
the maximum flow rate to the enclosed combustion device cannot cause 
the maximum inlet flow rate established in accordance with paragraph 
(f)(1) of this section to be exceeded. If there are changes to the 
process or control device that can be reasonably expected to impact the 
maximum flow rate to the enclosed combustion device, you must conduct a 
new demonstration to determine whether the maximum flow rate to the 
enclosed combustor is less than the maximum inlet flow rate established 
in accordance with paragraph (f)(1) of this section.
    (2) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (D) Air-assisted flares or enclosed combustion devices that use 
only perimeter assist air and have no assist steam or premix assist air 
are not required to have a continuous parameter monitoring system for 
measuring the inlet flow of gas to the device or the flow of assist air 
if you meet the conditions in paragraphs (d)(8)(iv)(D)(1) and (2) of 
this section. For these flares and enclosed combustion devices, 
NHV<INF>cz</INF> is assumed to be equal to the vent gas NHV.
    (1) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (2) You must demonstrate, based on the maximum flow rate of 
perimeter assist air to the enclosed combustion device or flare and 
applicable engineering calculations, that the NHV<INF>dil</INF> can 
never be less than the minimum required NHV<INF>dil.</INF> The 
demonstration must clearly document why the maximum flow rate of 
perimeter assist air will never exceed the rate used in the 
demonstration. You must use the minimum flow rate of vent gas allowed 
by your backpressure regulator valve and the minimum expected value of 
the NHV of the inlet gas to the enclosed combustion device or flare 
based on previous sampling results or process knowledge of the streams 
sent to the enclosed combustion device or flare in your demonstration. 
You must update this demonstration if there are changes to the 
backpressure regulator valve, the backpressure regulator valve set 
point, or the maximum flow rate of perimeter assist air. You must also 
update this demonstration if any sampling results of the NHV of the 
inlet gas to the enclosed combustion device or flare under paragraphs 
(d)(8)(ii) or (iii) of this section are lower than the NHV vent gas 
value used in your demonstration.
    (E) Air-assisted flares or enclosed combustion devices that use 
only premix assist air and have no assist steam or perimeter assist air 
are not required to have a continuous parameter monitoring system for 
measuring the inlet flow of gas to the device or the flow of assist air 
if you meet the conditions in paragraphs (d)(8)(iv)(E)(1) and (2) of 
this section.
    (1) You must install, calibrate, maintain, and operate a 
backpressure regulator valve calibrated to open at the minimum pressure 
set point corresponding to the minimum inlet gas flow rate. The set 
point must be consistent with manufacturer specifications for minimum 
flow or pressure and must be supported by an engineering evaluation. At 
least annually, you must confirm that the backpressure regulator valve 
set point is correct and consistent with the engineering evaluation and 
manufacturer specifications and that the valve fully closes when not in 
the open position.
    (2) You must demonstrate, based on the maximum flow rate of premix 
assist air to the enclosed combustion device or flare and applicable 
engineering calculations, that the NHV<INF>cz</INF> will never be less 
than the minimum required NHV<INF>cz.</INF> The demonstration must 
clearly document why the maximum flow rate of premix assist air will 
never exceed

[[Page 17193]]

the rate used in the demonstration. You must use the minimum flow rate 
of vent gas allowed by your backpressure regulator valve in and the 
minimum expected value of the NHV of the inlet gas to the enclosed 
combustion device or flare based on previous sampling results or 
process knowledge of the streams sent to the enclosed combustion device 
or flare in your demonstration. You must update this demonstration if 
there are changes to the backpressure regulator valve, the backpressure 
regulator valve set point, or the maximum flow rate of premix assist 
air. You must also update this demonstration if any sampling results of 
the NHV of the inlet gas to the enclosed combustion device or flare 
under paragraphs (d)(8)(ii) or (iii) of this section are lower than the 
NHV vent gas value used in your demonstration.
    (v) Conduct inspections monthly and at other times as requested by 
the Administrator to monitor for visible emissions from the combustion 
device using section 11 of Method 22 of appendix A to this part or 
conduct visible emissions monitoring according to paragraph (h) of this 
section. The observation period shall be 15 minutes or once the amount 
of time visible emissions is present has exceeded 1 minute. Devices 
must be operated with no visible emissions, except for periods not to 
exceed a total of 1 minute during any 15-minute period.
    (vi) If you use a flare or enclosed combustion device that is air-
assisted or steam-assisted, you must also meet the following 
requirements.
    (A) Except as allowed by paragraph (d)(8)(iv)(E) of this section, 
you must monitor and calculate NHV<INF>cz</INF> as specified in Sec.  
63.670(m) of this chapter. Additionally, for flares and enclosed 
combustion devices that use only perimeter assist air and do not use 
steam assist or premix assist air, the NHV<INF>cz</INF> is equal to the 
vent gas NHV. When NHV<INF>cz</INF> is equal to the vent gas NHV, you 
are not required to continuously monitor NHV<INF>cz</INF> if you meet 
the requirements in paragraph (d)(8)(iii) of this section.
    (B) Except as allowed by paragraph (d)(8)(iv)(D) of this section, 
for each flare using perimeter assist air, you must also monitor and 
calculate NHV<INF>dil</INF> as specified in Sec.  63.670(n) of this 
chapter. If the only assist air provided to the flare or enclosed 
combustion control device is perimeter assist air intentionally 
entrained in lower and/or upper steam at the flare tip and the 
effective diameter is 9 inches or greater, you are only required to 
comply with the NHV<INF>cz</INF> limit specified in paragraph 
(f)(8)(vi)(A) of this section.
    (C) Except as allowed by paragraph (d)(8)(iv) of this section, you 
must monitor the flare vent gas and assist gas as specified in Sec.  
63.670(i) of this chapter.
    (D) You must determine the flare vent gas net heating value as 
specified in Sec.  63.670(l) of this chapter using one of the methods 
specified in paragraph (d)(8)(ii) of this section. Where the phrase 
``petroleum refinery'' is used, for purposes of this subpart, it will 
refer to flares controlling an affected facility under this subpart. If 
you are not required to continuously monitor the NHV of the inlet gas 
because you have demonstrated that it consistently exceeds the 
applicable operating limit as provided in paragraph (d)(8)(iii) of this 
section, you must use the lowest net heating value measured in the 
sampling program in paragraph (d)(8)(iii) of this section for the 
calculations performed in paragraphs (d)(8)(vi)(A) and (B) of this 
section. You must update this value if a subsequent sampling result of 
the NHV of the inlet gas to the enclosed combustion device or flare 
under paragraph (d)(8)(iii) of this section is lower than the NHV vent 
gas value used in your calculations.
    (e) Calculate the value of the applicable monitored parameter in 
accordance with paragraphs (e)(1) through (5) of this section.
    (1) You must calculate the daily average value for condenser outlet 
temperature for each operating day, using the data recorded by the 
monitoring system. If the emissions unit operation is continuous, the 
operating day is a 24-hour period. If the emissions unit operation is 
not continuous, the operating day is the total number of hours of 
control device operation per 24-hour period. Valid data points must be 
available for 75 percent of the operating hours in an operating day to 
compute the daily average.
    (2) You must use the 5-minute readings from the heat sensing 
devices to assess the presence of a pilot or combustion flame.
    (3) You must use the regeneration cycle time (i.e., duration of the 
carbon bed steaming cycle) for each regenerative-type carbon adsorption 
system to calculate the average parameter to compare with the maximum 
steam mass flow or volumetric flow during each carbon bed regeneration 
cycle and the maximum carbon bed temperature during the steaming cycle. 
The carbon bed temperature after the regeneration cycle should not be 
averaged; you must use the carbon bed temperature measured within 15 
minutes of completing the cooling cycle to compare with the minimum 
carbon bed temperature after the regeneration cycle.
    (4) You must use 15-minute blocks to calculate NHV<INF>cz</INF> and 
NHV<INF>dil</INF>.
    (5) For all operating parameters others than those described in 
paragraphs (e)(1) through (4) of this section, you must calculate the 
3-hour rolling average of each monitored parameter. For each operating 
hour, calculate the hourly value of the operating parameter from your 
continuous monitoring system. Average the three most recent hours of 
data to determine the 3-hour average. Determine the 3-hour rolling 
average by recalculating the 3-hour average each hour.
    (f) For each operating parameter monitor installed in accordance 
with the requirements of paragraph (d) of this section, you must comply 
with paragraph (f)(1) of this section for all control devices. When 
condensers are installed, you must also comply with paragraph (f)(2) of 
this section.
    (1) You must establish a minimum operating parameter value or a 
maximum operating parameter value, as appropriate for the control 
device, to define the conditions at which the control device must be 
operated to continuously achieve the applicable performance 
requirements of Sec.  60.5412c(a)(1) or (2). You must establish each 
minimum or maximum operating parameter value as specified in paragraphs 
(f)(1)(i) through (iv) of this section.
    (i) If you conduct performance tests in accordance with the 
requirements of Sec.  60.5413c(b) to demonstrate that the control 
device achieves the applicable performance requirements specified in 
Sec.  60.5412c(a)(1) or (2), then you must establish the minimum 
operating parameter value or the maximum operating parameter value 
based on values measured during the performance test and supplemented, 
as necessary, by a condenser or carbon adsorption system design 
analysis or control device manufacturer recommendations or a 
combination of both. If you operate an enclosed combustion device, you 
must establish the maximum inlet flow rate based on values measured 
during the performance test and you may establish the minimum inlet 
flow rate based on control device manufacturer recommendations.
    (ii) If you use a condenser or carbon adsorption system design 
analysis in accordance with the requirements of Sec.  60.5413c(c) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec.  60.5412c(a)(2), then you must establish 
the minimum operating

[[Page 17194]]

parameter value or the maximum operating parameter value based on the 
design analysis and supplemented, as necessary, by the manufacturer's 
recommendations.
    (iii) If you operate a control device where the performance test 
requirement was met under Sec.  60.5413c(d) to demonstrate that the 
control device achieves the applicable performance requirements 
specified in Sec.  60.5412c(a)(1), then your control device inlet gas 
flow rate must be equal to or greater than the minimum inlet gas flow 
rate and equal to or less than the maximum inlet gas flow rate 
determined by the manufacturer.
    (iv) If you operate an enclosed combustion device where the 
combustion zone temperature is not an indicator of destruction 
efficiency or a control device where the performance test requirement 
was met under Sec.  60.5413c(d), you must maintain the NHV of the gas 
sent to the enclosed combustion device, the NHV<INF>cz</INF>, and the 
NHV<INF>dil</INF> above the applicable limits specified in Sec.  
60.5412c(a)(1)(iv)(A) through (D).
    (2) If you use a condenser as specified in paragraph (d)(1)(v) of 
this section, you must establish a condenser performance curve showing 
the relationship between condenser outlet temperature and condenser 
control efficiency, according to the requirements of paragraphs 
(f)(2)(i) and (ii) of this section.
    (i) If you conduct a performance test in accordance with the 
requirements of Sec.  60.5413c(b) to demonstrate that the condenser 
achieves the applicable performance requirements of Sec.  
60.5412c(a)(2), then the condenser performance curve must be based on 
values measured during the performance test and supplemented as 
necessary by control device design analysis, or control device 
manufacturer's recommendations, or a combination or both.
    (ii) If you use a control device design analysis in accordance with 
the requirements of Sec.  60.5413c(c)(1) to demonstrate that the 
condenser achieves the applicable performance requirements specified in 
Sec.  60.5412c(a)(2), then the condenser performance curve must be 
based on the condenser design analysis and supplemented, as necessary, 
by the control device manufacturer's recommendations.
    (g) A deviation for a control device is determined to have occurred 
when the monitoring data or lack of monitoring data result in any one 
of the criteria specified in paragraphs (g)(1) through (7) of this 
section being met. If you monitor multiple operating parameters for the 
same control device during the same operating day and more than one of 
these operating parameters meets a deviation criterion specified in 
paragraphs (g)(1) through (7) of this section, then a single excursion 
is determined to have occurred for the control device for that 
operating day.
    (1) A deviation occurs when the average value of a monitored 
operating parameter determined in accordance with paragraph (e) of this 
section is less than the minimum operating parameter limit (and, if 
applicable, greater than the maximum operating parameter limit) 
established in paragraph (f)(1) of this section; for flares, when the 
average value of a monitored operating parameter determined in 
accordance with paragraph (e) of this section is above the limits 
specified in Sec.  60.5415c(e)(1)(vii)(B); or when the heat sensing 
device indicates that there is no pilot or combustion flame present for 
any time period. If you use a backpressure regulator valve to maintain 
the inlet gas flow to an enclosed combustion device or flare above the 
minimum value, a deviation occurs if the annual inspection finds that 
the backpressure regulator valve set point is not set correctly or 
indicates that the backpressure regulator valve does not fully close 
when not in the open position.
    (2) If you are subject to Sec.  60.5412c(a)(2), a deviation occurs 
when the 365-day average condenser efficiency calculated according to 
the requirements specified in Sec.  60.5415c(e)(1)(ix)(D) is less than 
95.0 percent.
    (3) If you are subject to Sec.  60.5412c(a)(2) and you have less 
than 365 days of data, a deviation occurs when the average condenser 
efficiency calculated according to the procedures specified in Sec.  
60.5415c(e)(1)(ix)(D)(1) or (2) is less than 95.0 percent.
    (4) A deviation occurs when the monitoring data are not available 
for at least 75 percent of the operating hours in a day.
    (5) If the closed vent system contains one or more bypass devices 
that could be used to divert all or a portion of the gases, vapors, or 
fumes from entering the control device, a deviation occurs when the 
requirements of paragraph (g)(5)(i) or (ii) of this section are met.
    (i) For each bypass line subject to Sec.  60.5411c(a)(4)(i)(A), the 
flow indicator indicates that flow has been detected and that the 
stream has been diverted away from the control device to the 
atmosphere.
    (ii) For each bypass line subject to Sec.  60.5411c(a)(4)(i)(B), if 
the seal or closure mechanism has been broken, the bypass line valve 
position has changed, the key for the lock-and-key type lock has been 
checked out, or the car-seal has broken.
    (6) For a combustion control device whose model is tested under 
Sec.  60.5413c(d), a deviation occurs when the conditions of paragraphs 
(g)(4), (g)(5), or (g)(6)(i) through (vi) of this section are met.
    (i) The hourly inlet gas flow rate is less than the minimum inlet 
gas flow rate or greater than the maximum inlet gas flow rate 
determined by the manufacturer. If you use a backpressure regulator 
valve to maintain the inlet gas flow above the minimum value, a 
deviation occurs if the annual inspection finds that the backpressure 
regulator valve set point is not set correctly or indicates that the 
backpressure regulator valve does not fully close when not in the open 
position.
    (ii) Results of the monthly visible emissions test conducted under 
Sec.  60.5413c(e)(3) or monitoring under paragraph (h) of this section 
indicate visible emissions exceed 1 minute in any 15-minute period.
    (iii) There is no indication of the presence of a pilot or 
combustion flame for any 5-minute time period.
    (iv) The control device is not maintained in a leak free condition.
    (v) The control device is not operated in accordance with the 
manufacturer's written operating instructions, procedures and 
maintenance schedule.
    (vi) The NHV of the vent gas, the NHV<INF>cz</INF>, or the 
NHV<INF>dil</INF> is below the applicable limit specified in Sec.  
60.5412c(a)(1)(iv).
    (7) For an enclosed combustion device or flare subject to paragraph 
(d)(8) of this section, a deviation occurs when any of the conditions 
described by paragraphs (g)(1), (4), or (5) of this section are met or 
when the results of the visible emissions monitoring conducted under 
paragraph (d)(8)(v) or (h) of this section exceed 1 minute in any 15-
minute period.
    (h) For enclosed combustion devices and flares, in lieu of 
conducting a visible emissions observation using Method 22 of appendix 
A-7 to this part, you may use a video surveillance camera to 
continuously monitor and record the flare flame according to the 
requirements in paragraphs (h)(1) through (6) of this section.
    (1) You must provide real-time high-definition video surveillance 
camera output (i.e., at least 720p) at a frame rate of at least 15 
frames per second to the control room or other continuously manned 
location where the camera

[[Page 17195]]

images may be viewed at the same resolution at any time.
    (2) You must record at least one frame every 15 seconds with date 
and time stamp.
    (3) The camera must be located at a reasonable distance above the 
flare flame at an angle suitable for visual emissions observations. The 
position of the camera should be such that the sun is not in the field 
of view.
    (4) The camera must be located no more than 400 m (0.25 miles) from 
the emission source.
    (5) Operators must look at the video feed at least once daily for 
an observation period of at least 1 minute to determine if visible 
emissions are present. If visible emissions are present during a daily 
observation, the operator must observe the video feed for 15 minutes or 
until the amount of time visible emissions is present has exceeded 1 
minute, whichever time period is less.
    (6) Enclosed combustion devices and flares must be operated with no 
visible emissions, except for periods not to exceed a total of 1 minute 
during any 15-minute period.
    (i) If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412c(d), you must 
comply with paragraphs (i)(1) through (6) of this section.
    (1) You must measure data values at the frequency specified in the 
alternative test method.
    (2) You must prepare a monitoring plan that covers each control 
device for designated facilities within each company-defined area. The 
monitoring plan must address the monitoring system design, data 
collection, and the quality assurance and quality control elements 
outlined in the alternative test method and in paragraphs (i)(2)(i) 
through (iii) of this section. You must operate and maintain each 
monitoring system in accordance with the procedures in your monitoring 
plan.
    (i) The performance criteria and design specifications for the 
monitoring system equipment.
    (ii) Location of monitoring system in relation to the monitored 
control device.
    (iii) Ongoing reporting and recordkeeping procedures.
    (3) You must conduct the quality assurance and quality control 
requirements outlined in the alternative test method at the frequency 
outlined in the alternative test method.
    (4) If required by Sec.  60.5412c(d)(4), you must conduct the 
inspections required by paragraph (d)(8)(v) of this section.
    (5) If required by Sec.  60.5412c(d)(5), you must install the pilot 
or combustion flame monitoring system required by paragraph (d)(8)(i) 
of this section.
    (6) A deviation for the control device is determined to have 
occurred when the monitoring data or lack of monitoring data result in 
any one of the criteria specified in paragraphs (i)(6)(i) through (v) 
of this section being met.
    (i) A deviation occurs if the combustion efficiency is less than 
95.0 percent, the combustion zone NHV is less than 270 Btu/scf, or the 
NHV dilution parameter is less than 22 Btu/sqft.
    (ii) A deviation occurs when the monitoring data are not available 
for at least 75 percent of the operating hours in a day.
    (iii) A deviation occurs when any of the conditions described by 
paragraph (g)(5) of this section are met.
    (iv) If required by paragraph (i)(4) of this section to conduct 
visible emissions inspections, a deviation occurs when the results of 
the visible emissions monitoring conducted under paragraph (d)(8)(v) or 
(h) of this section exceeds 1 minute in any 15-minute period.
    (v) If required by paragraph (i)(5) of this section to install a 
pilot or combustion flame monitoring system, a deviation occurs when 
there is no indication of the presence of a pilot or combustion flame 
for any 5-minute period.
    (j) You must submit annual reports for control devices as required 
in Sec.  60.5420c(b)(1) and (10). You must maintain records as 
specified in Sec.  60.5420c(c)(10).

Model Rule--Recordkeeping and Reporting


Sec.  60.5420c   What are my notification, reporting, and recordkeeping 
requirements?

    (a) Notifications. You must submit notifications according to 
paragraphs (a)(1) and (2) of this section if you own or operate one or 
more of the designated facilities specified in Sec.  60.5386c for which 
you commenced construction, modification, or reconstruction on or 
before December 6, 2022. You must submit the notification in paragraph 
(a)(4) of this section if you undertake well closure activities as 
specified in Sec.  60.5397c(l).
    (1) Notification of Compliance Report. For each designated facility 
subject to the requirements specified under this subpart, an owner or 
operator is required to submit a statement of compliance with the 
applicable requirements of this subpart on or before 60 days after the 
state plan compliance date. Where a designated facility's compliance 
status is consistent with what was specified in the final compliance 
plan increment of progress report, the notification of compliance 
report would include a statement indicating that compliance is 
consistent with what was specified in the designated facility's final 
compliance plan. Where a designated facility's compliance status 
differs from what was specified in the final compliance plan increment 
of progress report, the notification of compliance report would 
indicate how the designated facility's status differs from what was 
stated in the final compliance plan.
    (2) Notifications. If you own or operate a process unit equipment 
designated facility located at an onshore natural gas processing plant, 
you must submit the notifications required in Sec. Sec.  60.7(a)(1), 
(3), and (4) and 60.15(d). If you own or operate a well, centrifugal 
compressor, reciprocating compressor, process controller, pump, storage 
vessel, collection of fugitive emissions components at a well site, or 
collection of fugitive emissions components at a compressor station 
designated facility, you are not required to submit the notifications 
required in Sec. Sec.  60.7(a)(1), (3), and (4) and 60.15(d).
    (3) Notification to Administrator. An owner or operator who 
commences well closure activities must submit the following notices to 
the Administrator according to the schedule in paragraph (a)(4)(i) and 
(ii) of this section. The notification shall include contact 
information for the owner or operator; the United States Well Number; 
the latitude and longitude coordinates for each well at the well site 
in decimal degrees to an accuracy and precision of five (5) decimals of 
a degree using the North American Datum of 1983. You must submit 
notifications in portable document format (PDF) following the 
procedures specified in paragraph (d) of this section.
    (i) You must submit a well closure plan to the Administrator within 
30 days of the cessation of production from all wells located at the 
well site.
    (ii) You must submit a notification of the intent to close a well 
site 60 days before you begin well closure activities.
    (b) Reporting requirements. You must submit annual reports 
containing the information specified in paragraphs (b)(1) through (13) 
of this section following the procedure specified in paragraph (b)(14) 
of this section. You must submit performance test reports as specified 
in paragraph (b)(11) or (12) of this section, if applicable. The 
initial annual report is due no later than 90 days after the end of the 
initial compliance period as determined according to Sec.  60.5410c. 
Subsequent annual reports are due no later than the

[[Page 17196]]

same date each year as the initial annual report. If you own or operate 
more than one designated facility, you may submit one report for 
multiple designated facilities provided the report contains all of the 
information required as specified in paragraphs (b)(1) through (13) of 
this section. Annual reports may coincide with title V reports as long 
as all the required elements of the annual report are included. You may 
arrange with the Administrator a common schedule on which reports 
required by this part may be submitted as long as the schedule does not 
extend the reporting period. You must submit the information in 
paragraph (b)(1)(v) of this section, as applicable, for your well 
designated facility which undergoes a change of ownership during the 
reporting period, regardless of whether reporting under (b)(2) through 
(3) of this section is required for the well designated facility.
    (1) The general information specified in paragraphs (b)(1)(i) 
through (v) of this section is required for all reports.
    (i) The company name, facility site name associated with the 
designated facility, U.S. Well ID or U.S. Well ID associated with the 
designated facility, if applicable, and address of the designated 
facility. If an address is not available for the site, include a 
description of the site location and provide the latitude and longitude 
coordinates of the site in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using the North American Datum of 
1983.
    (ii) An identification of each designated facility being included 
in the annual report.
    (iii) Beginning and ending dates of the reporting period.
    (iv) A certification by a certifying official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete. If 
your report is submitted via CEDRI, the certifier's electronic 
signature during the submission process replaces the requirement in 
this paragraph (b)(1)(iv).
    (v) Identification of each well designated facility for which 
ownership changed due to sale or transfer of ownership including the 
United States Well Number; the latitude and longitude coordinates of 
the well designated facility in decimal degrees to an accuracy and 
precision of five (5) decimals of a degree using the North American 
Datum of 1983; and the information in paragraph (b)(1)(v)(A) or (B) of 
this section, as applicable.
    (A) The name and contact information, including the phone number, 
email address, and mailing address, of the owner or operator to which 
you sold or transferred ownership of the well designated facility 
identified in paragraph (b)(1)(v) of this section.
    (B) The name and contact information, including the phone number, 
email address, and mailing address, of the owner or operator from whom 
you acquired the well designated facility identified in paragraph 
(b)(1)(v) of this section.
    (2) For each well designated facility that is subject to Sec.  
60.5390c(a)(1) or (2), your annual report is required to include the 
information specified in paragraphs (b)(2)(i) and (ii) of this section, 
as applicable.
    (i) For each well designated facility where all gas well liquids 
unloading operations comply with Sec.  60.5390c(a)(1), your annual 
report must include the information specified in paragraphs 
(b)(2)(i)(A) through (C) of this section, as applicable.
    (A) Identification of each well designated facility (U.S. Well ID 
or U.S. Well ID associated with the well designated facility) that 
conducts a gas well liquid unloading operation during the reporting 
period using a method that does not vent to the atmosphere and the 
technology or technique used. If more than one non-venting technology 
or technique is used, you must identify all of the differing non-
venting liquids unloading methods used during the reporting period.
    (B) Number of gas well liquids unloading operations conducted 
during the year where the well designated facility identified in 
(b)(2)(i)(A) had unplanned venting to the atmosphere and best 
management practices were conducted according to your best management 
practice plan, as required by Sec.  60.5390c(c). If no venting events 
occurred, the number would be zero. Other reported information required 
to be submitted where unplanned venting occurs is specified in 
paragraphs (b)(2)(i)(B)(1) and (2) of this section.
    (1) Log of best management practice plan steps used during the 
unplanned venting to minimize emissions to the maximum extent possible.
    (2) The number of liquids unloading events during the year where 
deviations from your best management practice plan occurred, the date 
and time the deviation began, the duration of the deviation in hours, 
documentation of why best management practice plan steps were not 
followed, and what steps, in lieu of your best management practice plan 
steps, were followed to minimize emissions to the maximum extent 
possible.
    (C) The number of liquids unloading events where unplanned 
emissions are vented to the atmosphere during a gas well liquids 
unloading operation where you complied with best management practices 
to minimize emissions to the maximum extent possible.
    (ii) For each well designated facility where all gas well liquids 
unloading operations comply with Sec.  60.5390c(b) and (c) best 
management practices, your annual report must include the information 
specified in paragraphs (b)(2)(ii)(A) through (E) of this section.
    (A) Identification of each well designated facility that conducts a 
gas well liquids unloading during the reporting period.
    (B) Number of liquids unloading events conducted during the 
reporting period.
    (C) Log of best management practice plan steps used during the 
reporting period to minimize emissions to the maximum extent possible.
    (D) The number of liquids unloading events during the year that 
best management practices were conducted according to your best 
management practice plan.
    (E) The number of liquids unloading events during the year where 
deviations from your best management practice plan occurred, the date 
and time the deviation began, the duration of the deviation in hours, 
documentation of why best management practice plan steps were not 
followed, and what steps, in lieu of your best management practice plan 
steps, were followed to minimize emissions to the maximum extent 
possible.
    (3) For each associated gas well at your well designated facility 
that is subject to Sec.  60.5391c, your annual report is required to 
include the applicable information specified in paragraphs (b)(3)(i) 
through (v) of this section, as applicable.
    (i) For each associated gas well at your well designated facility 
that complies with Sec.  60.5391c(a)(1), (2), (3), or (4) your annual 
report is required to include the information specified in paragraphs 
(b)(3)(i)(A) and (B) of this section.
    (A) An identification of each existing associated gas well that 
complies with Sec.  60.5391c(a)(1), (2), (3), or (4).
    (B) The information specified in paragraphs (b)(3)(i)(B)(1) through 
(3) of this section for each incident when the associated gas was 
temporarily routed to a flare or control device in accordance with 
Sec.  60.5377c(c).
    (1) The reason in Sec.  60.5377c(c)(1), (2), (3), or (4) for each 
incident.

[[Page 17197]]

    (2) The start date and time of each incident of routing associated 
gas to the flare or control device, along with the total duration in 
hours of each incident.
    (3) Documentation that all CVS requirements specified in Sec.  
60.5411c(a) and (c) and all applicable flare or control device 
requirements specified in Sec.  60.5412c were met during each period 
when the associated gas is routed to the flare or control device.
    (ii) For all instances where you temporarily vent the associated 
gas in accordance with Sec.  60.5391c(d), you must report the 
information specified in paragraphs (b)(3)(ii)(A) through (D) of this 
section. This information is required to be reported if you are 
routinely complying with Sec.  60.5391c(a) or Sec.  60.5391c(b) or 
temporarily complying with Sec.  60.5391c(c). In addition to this 
information for each incident, you must report the cumulative duration 
in hours of venting incidents and the cumulative VOC and methane 
emissions in pounds for all incidents in the calendar year.
    (A) The reason in Sec.  60.5377c(d)(1), (2), or (3) for each 
incident.
    (B) The start date and time of each incident of venting the 
associated gas, along with the total duration in hours of each 
incident.
    (C) The methane emissions in pounds that were emitted during each 
incident.
    (D) The total duration of venting for all incidents in the year, 
along with the cumulative methane emissions in pounds that were 
emitted.
    (iii) For each associated gas well at your well designated facility 
that complies with the requirements of Sec.  60.5391c(b) by routing 
your associated gas to a control device that reduces methane emissions 
by at least 95.0 percent, your annual report must include the 
information specified in paragraphs (b)(3)(iii)(A) through (C) of this 
section, and paragraph (D) or (E) of this section. The information in 
paragraphs (b)(3)(iii)(A) and (B) of this section is only required in 
the initial annual report.
    (A) Identification of the associated gas well using the control 
device and the information in paragraphs (b)(10)(v) of this section.
    (B) The information specified in paragraphs (b)(10)(i) through (iv) 
of this section.
    (C) Identification of each instance when associated gas was vented 
and not routed to a control device that reduces methane emissions by at 
least 95.0 percent in accordance with paragraph (c)(3)(ii) of this 
section.
    (D) For each associated gas well that complies with the 
requirements of Sec.  60.5391c(b) because it has demonstrated that 
annual methane emissions are 40 tons per year or less, provide records 
of the calculation of annual methane emissions determined in accordance 
with Sec.  60.5391c(e)(1).
    (E) For each associated gas well facility that complies with the 
requirements of Sec.  60.5391c(c) because it has demonstrated that it 
is not feasible to comply with Sec.  60.5391c(a)(1), (2), (3), or (4) 
due to technical reasons, provide each annual demonstration and 
certification of the technical reason that it is not feasible to comply 
with Sec.  60.5377c(a)(1), (2), (3), and (4) in accordance with Sec.  
60.5377c(b)(2)(i), (ii), and (iii).
    (iv) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i) 
and (ii) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (v) For each deviation recorded as specified in paragraph 
(c)(2)(iii) of this section, the date and time the deviation began, the 
duration of the deviation in hours, and a description of the deviation. 
If no deviations occurred during the reporting period, you must include 
a statement that no deviations occurred during the reporting period.
    (4) For each centrifugal compressor equipped with a wet seal 
(including self-contained wet seal centrifugal compressors) and 
centrifugal compressor equipped with sour seal oil separator and 
capture system that is a designated facility, the information specified 
in paragraphs (b)(4)(i) through (vii) of this section, as applicable. 
For each centrifugal compressor equipped with a dry seal that is a 
designated facility, the information specified in paragraphs (b)(4)(i) 
through (xi) of this section.
    (i) An identification of each centrifugal compressor.
    (ii) For each deviation that occurred during the reporting period 
and recorded as specified in paragraph (c)(3) of this section, the date 
and time the deviation began, the duration of the deviation in hours, 
and a description of the deviation. If no deviations occurred during 
the reporting period, you must include a statement that no deviations 
occurred during the reporting period.
    (iii) If complying with Sec.  60.5392c(a)(1) and (2) wet and dry 
seal centrifugal compressor requirements, the cumulative number of 
hours of operation since initial startup, since 36 months after the 
state plan submittal deadline (as specified in Sec.  60.5362c(c)), or 
since the previous volumetric flow rate measurement, as applicable, 
which have elapsed prior to conducting your volumetric flow rate 
measurement or emissions screening.
    (iv) A description of the method used and the results of the 
volumetric emissions measurement or emissions screening, as applicable.
    (v) If required to comply with Sec.  60.5392c(a)(5), the 
information specified in paragraphs (b)(10)(i) through (iv) of this 
section.
    (vi) If complying with Sec.  60.5392c(a)(4) with a control device, 
identification of the centrifugal compressor with the control device 
and the information in paragraph (b)(10)(v) of this section.
    (vii) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i) 
and (ii) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (viii) Number and type of seals on delay of repair and explanation 
for each delay of repair.
    (ix) Date of planned shutdown(s) that occurred during the reporting 
period if there are any seals that have been placed on delay of repair.
    (5) For each reciprocating compressor designated facility, the 
information specified in paragraphs (b)(5)(i) through (vii) of this 
section, as applicable.
    (i) The cumulative number of hours of operation since initial 
startup, since 36 months after the state plan submittal deadline (as 
specified in Sec.  60.5362c(c)), since the previous volumetric flow 
rate measurement, or since the previous reciprocating compressor rod 
packing replacement, as applicable, which have elapsed prior to 
conducting your volumetric flow rate measurement or emissions 
screening. Alternatively, a statement that emissions from the rod 
packing are being routed to a process or control device through a 
closed vent system.
    (ii) If applicable, for each deviation that occurred during the 
reporting period and recorded as specified in paragraph (c)(4)(i) of 
this section, the date and time the deviation began, duration of the 
deviation in hours and a description of the deviation. If no deviations 
occurred during the reporting period, you must include a statement that 
no deviations occurred during the reporting period.
    (iii) A description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable.
    (iv) If complying with Sec.  60.5393c(d), the information in 
paragraphs (b)(10)(i) through (v) of this section.
    (v) Number and type of rod packing replacements/repairs on delay of 
repair and explanation for each delay of repair.

[[Page 17198]]

    (vi) Date of planned shutdown(s) that occurred during the reporting 
period if there are any rod packing replacements/repairs that have been 
placed on delay of repair.
    (vii) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i) 
and (ii) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (6) For each process controller designated facility, the 
information specified in paragraphs (b)(6)(i) through (iii) of this 
section in your initial annual report and in subsequent annual reports 
for each process controller designated facility that is constructed, 
modified, or reconstructed during the reporting period. Each annual 
report must contain the information specified in paragraphs (b)(6)(iv) 
through (x) of this section for each process controller designated 
facility.
    (i) An identification of each existing process controller that is 
driven by natural gas, as required by Sec.  60.5394c(d), that allows 
traceability to the records required in paragraph (c)(5)(i) of this 
section.
    (ii) For each process controller in the designated facility 
complying with Sec.  60.5394c(a), you must report the information 
specified in paragraphs (b)(6)(ii)(A) and (B) of this section, as 
applicable.
    (A) An identification of each process controller complying with 
Sec.  60.5394c(a)(1) by routing the emissions to a process.
    (B) An identification of each process controller complying with 
Sec.  60.5394c(a)(1) by using a self-contained natural gas-driven 
process controller.
    (iii) For each process controller designated facility located at a 
site in Alaska that does not have access to electrical power and that 
complies with Sec.  60.5394c(b), you must report the information 
specified in paragraphs (b)(6)(iii)(A), (B), or (C) of this section, as 
applicable.
    (A) For each process controller complying with Sec.  60.5394c(b)(1) 
process controller bleed rate requirements, you must report the 
information specified in paragraphs (b)(6)(iii)(A)(1) and (2) of this 
section.
    (1) The identification of process controllers designed and operated 
to achieve a bleed rate less than or equal to 6 scfh.
    (2) Where necessary to meet a functional need, the identification 
and demonstration of why it is necessary to use a process controller 
with a natural gas bleed rate greater than 6 scfh.
    (B) An identification of each intermittent vent process controller 
complying with the requirements in paragraph Sec.  60.5394c(b)(2).
    (C) An identification of each process controller complying with the 
requirements in Sec.  60.5394c(b) by routing emissions to a control 
device in accordance with Sec.  60.5394c(b)(3).
    (iv) Identification of each process controller which changes its 
method of compliance during the reporting period and the applicable 
information specified in paragraphs (b)(6)(v) through (ix) of this 
section for the new method of compliance.
    (v) For each process controller in the designated facility 
complying with the requirements of Sec.  60.5394c(a) by routing the 
emissions to a process, you must report the information specified in 
paragraphs (b)(10)(i) through (iii) of this section.
    (vi) For each process controller in the designated facility 
complying with the requirements of Sec.  60.5394c(a) by using a self-
contained natural gas-driven process controller, you must report the 
information specified in paragraphs (b)(6)(vi)(A) and (B) of this 
section.
    (A) Dates of each inspection required under Sec.  60.5416c(b); and
    (B) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and the date of 
repair or date of anticipated repair if repair is delayed.
    (vii) For each process controller in the designated facility 
complying with the requirements of Sec.  60.5394c(b)(2), you must 
report the information specified in paragraphs (b)(6)(vii)(A) and (B) 
of this section.
    (A) Dates and results of the intermittent vent process controller 
monitoring required by Sec.  60.5394c(b)(2)(ii).
    (B) For each instance in which monitoring identifies emissions to 
the atmosphere from an intermittent vent controller during idle 
periods, the date of repair or replacement or the date of anticipated 
repair or replacement if the repair or replacement is delayed, and the 
date and results of the re-survey after repair or replacement.
    (viii) For each process controller designated facility complying 
with Sec.  60.5394c(b)(3) by routing emissions to a control device, you 
must report the information specified in paragraph (b)(10) of this 
section.
    (ix) For each deviation that occurred during the reporting period, 
the date and time the deviation began, the duration of the deviation in 
hours, and a description of the deviation. If no deviations occurred 
during the reporting period, you must include a statement that no 
deviations occurred during the reporting period.
    (x) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs 
(b)(6)(ii)(B) and (b)(10)(i) and (ii) of this section, you must provide 
the information specified in Sec.  60.5424c.
    (7) For each storage vessel designated facility, the information in 
paragraphs (b)(7)(i) through (x) of this section.
    (i) An identification, including the location, of each existing 
storage vessel designated facility. The location of the storage vessel 
designated facility shall be in latitude and longitude coordinates in 
decimal degrees to an accuracy and precision of five (5) decimals of a 
degree using the North American Datum of 1983.
    (ii) Documentation of the methane emission rate determination 
according to Sec.  60.5386c(e)(1) for each tank battery that became a 
designated facility during the reporting period or is returned to 
service during the reporting period.
    (iii) For each deviation that occurred during the reporting period 
and recorded as specified in paragraph (c)(6)(iii) of this section, the 
date and time the deviation began, duration of the deviation in hours 
and a description of the deviation. If no deviations occurred during 
the reporting period, you must include a statement that no deviations 
occurred during the reporting period.
    (iv) For each storage vessel designated facility complying with 
Sec.  60.5396c(a)(2) with a control device, report the identification 
of the storage vessel designated facility with the control device and 
the information in paragraph (b)(10)(v) of this section.
    (v) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i) 
and (ii) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (vi) If required to comply with Sec.  60.5396c(b)(1), the 
information in paragraphs (b)(10)(i) through (iv) of this section.
    (vii) You must identify each storage vessel designated facility 
that is removed from service during the reporting period as specified 
in Sec.  60.5396c(c)(1)(ii), including the date the storage vessel 
designated facility was removed from service. You must identify each 
storage vessel that that is removed from service from a storage vessel 
designated facility during the reporting period as specified in Sec.  
60.5396c(c)(2)(iii), including identifying the impacted storage vessel 
designated facility and the date each

[[Page 17199]]

storage vessel was removed from service.
    (viii) You must identify each storage vessel designated facility or 
portion of a storage vessel designated facility returned to service 
during the reporting period as specified in Sec.  60.5396c(c)(4), 
including the date the storage vessel designated facility or portion of 
a storage vessel designated facility was returned to service.
    (ix) You must identify each storage vessel designated facility that 
no longer complies with Sec.  60.5396c(a)(3) and instead complies with 
Sec.  60.5396c(a)(2). You must identify whether the change in the 
method of compliance was due to fracturing or refracturing or whether 
the change was due to an increase in the monthly emissions 
determination. If the change was due to an increase in the monthly 
emissions determination, you must provide documentation of the 
emissions rate. You must identify the date that you complied with Sec.  
60.5396c(a)(2) and must submit the information in (b)(7)(iii) through 
(vii) of this section.
    (x) You must submit a statement that you are complying with Sec.  
60.112b(a)(1) or (2), if applicable, in your initial annual report.
    (8) For the fugitive emissions components designated facility, 
report the information specified in paragraphs (b)(8)(i) through (iv) 
of this section, as applicable.
    (i)(A) Designation of the type of site (i.e., well site, 
centralized production facility, or compressor station) at which the 
fugitive emissions components designated facility is located.
    (B) For the fugitive emissions components designated facility at a 
well site or centralized production facility that became a designated 
facility during the reporting period, you must include the date of the 
startup of production or the date of the first day of production after 
modification. For the fugitive emissions components designated facility 
at a compressor station that became a designated facility during the 
reporting period, you must include the date of startup or the date of 
modification.
    (C) For the fugitive emissions components designated facility at a 
well site, you must specify what type of well site it is (i.e., single 
wellhead only well site, small wellsite, multi-wellhead only well site, 
or a well site with major production and processing equipment).
    (D) For the fugitive emissions components designated facility at a 
well site where during the reporting period you complete the removal of 
all major production and processing equipment such that the well site 
contains only one or more wellheads, you must include the date of the 
change to status as a wellhead only well site.
    (E) For the fugitive emissions components designated facility at a 
well site where you previously reported under paragraph (b)(8)(i)(D) of 
this section the removal of all major production and processing 
equipment and during the reporting period major production and 
processing equipment is added back to the well site, the date that the 
first piece of major production and processing equipment is added back 
to the well site.
    (F) For the fugitive emissions components designated facility at a 
well site where during the reporting period you undertake well closure 
requirements, the date of the cessation of production from all wells at 
the well site, the date you began well closure activities at the well 
site, and the dates of the notifications submitted in accordance with 
paragraph (a)(5) of this section.
    (ii) For each fugitive emissions monitoring survey performed during 
the annual reporting period, the information specified in paragraphs 
(b)(8)(ii)(A) through (G) of this section.
    (A) Date of the survey.
    (B) Monitoring instrument or, if the survey was conducted by 
visual, audible, or olfactory methods, notation that AVO was used.
    (C) Any deviations from the monitoring plan elements under Sec.  
60.5397c(c)(1), (2), and (7), (c)(8)(i), or (d) or a statement that 
there were no deviations from these elements of the monitoring plan.
    (D) Number and type of components for which fugitive emissions were 
detected.
    (E) Number and type of fugitive emissions components that were not 
repaired as required in Sec.  60.5397c(h).
    (F) 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.
    (G) Date of planned shutdown(s) that occurred during the reporting 
period if there are any components that have been placed on delay of 
repair.
    (iii) For well closure activities which occurred during the 
reporting period, the information in paragraphs (b)(8)(iii)(A) and (B) 
of this section.
    (A) A status report with dates for the well closure activities 
schedule developed in the well closure plan. If all steps in the well 
closure plan are completed in the reporting period, the date that all 
activities are completed.
    (B) If an OGI survey is conducted during the reporting period, the 
information in paragraphs (b)(8)(iii)(B)(1) through (3) of this 
section.
    (1) Date of the OGI survey.
    (2) Monitoring instrument used.
    (3) A statement that no fugitive emissions were found, or if 
fugitive emissions were found, a description of the steps taken to 
eliminate those emissions, the date of the resurvey, the results of the 
resurvey, and the date of the final resurvey which detected no 
emissions.
    (iv) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i) 
and (ii) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (9) For each pump designated facility, the information specified in 
paragraphs (b)(9)(i) through (iv) of this section in your initial 
annual report. Each annual report must contain the information 
specified in paragraphs (b)(9)(v) through (ix) of this section for each 
pump designated facility.
    (i) The identification of each of your pumps that are driven by 
natural gas, as required by Sec.  60.5395c(a) that allows traceability 
to the records required by paragraph (c)(14)(i) of this section.
    (ii) For each pump designated facility for which there is a control 
device on site but it does not achieve a 95.0 percent emissions 
reduction, the certification that there is a control device available 
on site but it does not achieve a 95.0 percent emissions reduction 
required under Sec.  60.5395c(b)(5). You must also report the emissions 
reduction percentage the control device is designed to achieve.
    (iii) For each pump designated facility for which there is no 
control device or vapor recovery unit on site, the certification 
required under Sec.  60.5395c(b)(6) that there is no control device or 
vapor recovery unit on site.
    (iv) For each pump designated facility for which it is technically 
infeasible to route the emissions to a process or control device, the 
certification of technically infeasibility required under Sec.  
60.5395c(b)(7).
    (v) For any pump designated facility which has previously reported 
as required under paragraphs (b)(9)(i) through (iv) of this section and 
for which a change in the reported condition has occurred during the 
reporting period, provide the identification of the pump designated 
facility and the date that the pump designated facility meets one of 
the change conditions described in

[[Page 17200]]

paragraphs (b)(9)(v)(A) through (C) of this section.
    (A) If you install a control device or vapor recovery unit, you 
must report that a control device or vapor recovery unit has been added 
to the site and that the pump designated facility now is required to 
comply with Sec.  60.5395c(b)(1) or (3), as applicable.
    (B) If your pump designated facility previously complied with Sec.  
60.5395c(b)(1) or (3), as applicable. by routing emissions to a process 
or a control device and the process or control device is subsequently 
removed from the site or is no longer available such that there is no 
ability to route the emissions to a process or control device at the 
location, or that it is not technically feasible to capture and route 
the emissions to another control device or process located on site, 
report that you are no longer complying with the applicable 
requirements of Sec.  60.5395c(b)(1) or (3) and submit the information 
provided in paragraphs (b)(9)(v)(B)(1) or (2) of this section.
    (1) Certification that there is no control device or vapor recovery 
unit on site.
    (2) Certification of the engineering assessment that it is 
technically infeasible to capture and route the emissions to another 
control device or process located on site.
    (C) If any pump affected facility or individual natural gas-driven 
pump changes its method of compliance during the reporting period other 
than for the reasons specified in paragraphs (b)(9)(v)(A) and (B) of 
this section, identify the new compliance method for each natural gas-
driven pump within the affected facility which changes its method of 
compliance during the reporting period and provide the applicable 
information specified in paragraphs (b)(9)(ii) through (iv) and (vi) 
through (viii) of this section for the new method of compliance.
    (vi) For each pump designated facility complying with the 
requirements of Sec.  60.5395c(a) or (b)(2) by routing the emissions to 
a process, you must report the information specified in paragraphs 
(b)(11)(i) through (iv) of this section.
    (vii) For each pump designated facility complying with the 
requirements of Sec.  60.5395c(b)(3) by routing the emissions to a 
control device, you must report the information required under 
paragraph (b)(11) of this section.
    (viii) For each deviation that occurred during the reporting 
period, the date and time the deviation began, the duration of the 
deviation in hours, and a description of the deviation. If no 
deviations occurred during the reporting period, you must include a 
statement that no deviations occurred during the reporting period.
    (ix) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i) 
and (ii) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (10) For each well, centrifugal compressor, reciprocating 
compressor, storage vessel, process controller, pump, or process unit 
equipment designated facility which uses a closed vent system routed to 
a control device to meet the emissions reduction standard, you must 
submit the information in paragraphs (b)(10)(i) through (v) of this 
section. For each centrifugal compressor, reciprocating compressor, 
process controller, pump, storage vessel, or process unit equipment 
which uses a closed vent system to route to a process, you must submit 
the information in paragraphs (b)(10)(i) through (iv) of this section. 
For each centrifugal compressor and storage vessel equipped with a 
cover, you must submit the information in paragraphs (b)(10)(i) and 
(ii).
    (i) Dates of each inspection required under Sec.  60.5416c(a) and 
(b).
    (ii) Each defect or emissions identified during each inspection and 
the date of repair or the date of anticipated repair if the repair is 
delayed.
    (iii) Date and time of each bypass alarm or each instance the key 
is checked out if you are subject to the bypass requirements of Sec.  
60.5416c(a)(4).
    (iv) You must submit the certification signed by the qualified 
professional engineer or in-house engineer according to Sec.  
60.5411c(c) for each closed vent system routing to a control device or 
process in the reporting year in which the certification is signed.
    (v) If you comply with the emissions standard for your well, 
centrifugal compressor, reciprocating compressor, storage vessel, 
process controller, pump, or process unit equipment designated facility 
with a control device, the information in paragraphs (b)(10)(v)(A) 
through (L) of this section, unless you use an enclosed combustion 
device or flare using an alternative test method approved under Sec.  
60.5412c(d). If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412c(d), the 
information in paragraphs (b)(10)(v)(A) through (C) and (L) through (P) 
of this section.
    (A) Identification of the control device.
    (B) Make, model, and date of installation of the control device.
    (C) Identification of the designated facility controlled by the 
device.
    (D) For each continuous parameter monitoring system used to 
demonstrate compliance for the control device, a unique continuous 
parameter monitoring system identifier and the make, model number, and 
date of last calibration check of the continuous parameter monitoring 
system.
    (E) For each instance where there is a deviation of the control 
device in accordance with Sec.  60.5417c(g)(1) through (3) or (5) 
through (7) include the date and time the deviation began, the duration 
of the deviation in hours, the type of the deviation (e.g., NHV 
operating limit, lack of pilot or combustion flame, condenser 
efficiency, bypass line flow, visible emissions), and cause of the 
deviation.
    (F) For each instance where there is a deviation of the continuous 
parameter monitoring system in accordance with Sec.  60.5417c(g)(4) 
include the date and time the deviation began, the duration of the 
deviation in hours, and cause of the deviation.
    (G) For each visible emissions test following return to operation 
from a maintenance or repair activity, the date of the visible 
emissions test or observation of the video surveillance output, the 
length of the observation in minutes, and the number of minutes for 
which visible emissions were present.
    (H) If a performance test was conducted on the control device 
during the reporting period, provide the date the performance test was 
conducted. Submit the performance test report following the procedures 
specified in paragraph (b)(11) of this section.
    (I) If a demonstration of the NHV of the inlet gas to the enclosed 
combustion device or flare was conducted during the reporting period in 
accordance with Sec.  60.5417c(d)(8)(iii), an indication of whether 
this is a re-evaluation of vent gas NHV and the reason for the re-
evaluation; the applicable required minimum vent gas NHV; if twice 
daily samples of the vent stream were taken, the number of hourly 
average NHV values that are less than 1.2 times the applicable required 
minimum NHV; if continuous NHV sampling of the vent stream was 
conducted, the number of hourly average NHV values that are less than 
the required minimum vent gas NHV; if continuous combustion efficiency 
monitoring was conducted using an alternative test method approved 
under Sec.  60.5412c(d), the number of values of the combustion 
efficiency that were less than 95.0 percent; the resulting 
determination of whether NHV monitoring is required or not in 
accordance with

[[Page 17201]]

Sec.  60.5417c(d)(8)(iii)(D) or (H); and an indication of whether the 
enclosed combustion device or flare has the potential to receive inert 
gases, and if so, whether the sampling included periods where the 
highest percentage of inert gases were sent to the enclosed combustion 
device or flare.
    (J) If a demonstration was conducted in accordance with Sec.  
60.5417c(d)(8)(iv) that the maximum potential pressure of units 
manifolded to an enclosed combustion device or flare cannot cause the 
maximum inlet flow rate established in accordance with Sec.  
60.5417c(f)(1) or a flare tip velocity limit of 18.3 meter/second (60 
feet/second) to be exceeded, an indication of whether this is a re-
evaluation of the gas flow and the reason for the re-evaluation; the 
demonstration conducted; and applicable engineering calculations.
    (K) For each periodic sampling event conducted under Sec.  
60.5417c(d)(8)(iii)(G), provide the date of the sampling, the required 
minimum vent gas NHV, and the NHV value for each vent gas sample.
    (L) For each flare and enclosed combustion device, provide the date 
each device is observed with OGI in accordance with Sec.  
60.5415c(e)(x) and whether uncombusted emissions were present. Provide 
the date each device was visibly observed during an AVO inspection in 
accordance with Sec.  60.5415c(e)(x), whether the pilot or combustion 
flame was lit at the time of observation, and whether the device was 
found to be operating properly.
    (M) An identification of the alternative test method used.
    (N) For each instance where there is a deviation of the control 
device in accordance with Sec.  60.5417c(i)(6)(i) or (iii) through (v) 
include the date and time the deviation began, the duration of the 
deviation in hours, the type of the deviation (e.g., NHV<INF>cz</INF> 
operating limit, lack of pilot or combustion flame, visible emissions), 
and cause of the deviation.
    (O) For each instance where there is a deviation of the data 
availability in accordance with Sec.  60.5417c(i)(6)(ii) include the 
date of each operating day when monitoring data are not available for 
at least 75 percent of the operating hours.
    (P) If no deviations occurred under paragraphs (b)(11)(v)(N) or (O) 
of this section, a statement that there were no deviations for the 
control device during the annual report period.
    (Q) Any additional information required to be reported as specified 
by the Administrator as part of the alternative test method approval 
under Sec.  60.5412c(d).
    (11) Within 60 days after the date of completing each performance 
test (see Sec.  60.8) required by this subpart, except testing 
conducted by the manufacturer as specified in Sec.  60.5413c(d), you 
must submit the results of the performance test following the 
procedures specified in paragraph (d) of this section. Data collected 
using test methods that are supported by the EPA's Electronic Reporting 
Tool (ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at 
the time of the test must be submitted in a file format generated using 
the EPA's ERT. Alternatively, you may submit an electronic file 
consistent with the extensible markup language (XML) schema listed on 
the EPA's ERT website. Data collected using test methods that are not 
supported by the EPA's ERT as listed on the EPA's ERT website at the 
time of the test must be included as an attachment in the ERT or 
alternate electronic file.
    (12) For combustion control devices tested by the manufacturer in 
accordance with Sec.  60.5413c(d), an electronic copy of the 
performance test results required by Sec.  60.5413c(d) shall be 
submitted via email to <a href="/cdn-cgi/l/email-protection#76391f1a29291718122929311705292926223633263758313920"><span class="__cf_email__" data-cfemail="612e080d3e3e000f053e3e2600123e3e3135212431204f262e37">[email protected]</span></a> unless the test 
results for that model of combustion control device are posted at the 
following website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
    (13) If you had a super-emitter event during the reporting period, 
the start date of the super-emitter event, the duration of the super-
emitter event in hours, and the designated facility associated with the 
super-emitter event, if applicable.
    (14) You must submit your annual report using the appropriate 
electronic report template on the Compliance and Emissions Data 
Reporting Interface (CEDRI) website for this subpart and following the 
procedure specified in paragraph (d) of this section. If the reporting 
form specific to this subpart is not available on the CEDRI website at 
the time that the report is due, you must submit the report to the 
Administrator at the appropriate address listed in Sec.  60.4. Once the 
form has been available on the CEDRI website for at least 90 calendar 
days, you must begin submitting all subsequent reports via CEDRI. The 
date reporting forms become available will be listed on the CEDRI 
website. Unless the Administrator or delegated state agency or other 
authority has approved a different schedule for submission of reports, 
the report must be submitted by the deadline specified in this subpart, 
regardless of the method in which the report is submitted.
    (c) Recordkeeping requirements. You must maintain the records 
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1) 
through (14) of this section. All records required by this subpart must 
be maintained either onsite or at the nearest local field office for at 
least 5 years. Any records required to be maintained by this subpart 
that are submitted electronically via the EPA's CEDRI may be maintained 
in electronic format. This ability to maintain electronic copies does 
not affect the requirement for facilities to make records, data, and 
reports available upon request to a delegated air agency or the EPA as 
part of an on-site compliance evaluation.
    (1) For each gas well liquids unloading operation at your well 
designated facility that is subject to Sec.  60.5390c(a)(1) or (2), the 
records of each gas well liquids unloading operation conducted during 
the reporting period, including the information specified in paragraphs 
(c)(1)(i) through (iii) of this section, as applicable.
    (i) For each gas well liquids unloading operation that complies 
with Sec.  60.5390c(a)(1) by performing all liquids unloading events 
without venting of methane emissions to the atmosphere, comply with the 
recordkeeping requirements specified in paragraphs (c)(1)(i)(A) and (B) 
of this section.
    (A) Identification of each well (i.e., U.S. Well ID or U.S. Well ID 
associated with the well designated facility) that conducts a gas well 
liquids unloading operation during the reporting period without venting 
of methane emissions and the non-venting gas well liquids unloading 
method used. If more than one non-venting method is used, you must 
maintain records of all the differing non-venting liquids unloading 
methods used at the well designated facility complying with Sec.  
60.5376c(a)(1).
    (B) Number of events where unplanned emissions are vented to the 
atmosphere during a gas well liquids unloading operation where you 
complied with best management practices to minimize emissions to the 
maximum extent possible.
    (ii) For each gas well liquids unloading operation that complies 
with Sec.  60.5390c(b) and (c) best management practices, maintain 
records documenting information specified in paragraphs (c)(1)(ii)(A) 
through (D) of this section.
    (A) Identification of each well designated facility that conducts 
liquids unloading during the reporting period

[[Page 17202]]

that employs best management practices to minimize emissions to the 
maximum extent possible.
    (B) Documentation of your best management practice plan developed 
under paragraph Sec.  60.5390c(c). You may update your best management 
practice plan to include additional steps which meet the criteria in 
Sec.  60.5390c(c).
    (C) A log of each best management practice plan step taken minimize 
emissions to the maximum extent possible for each gas well liquids 
unloading event.
    (D) Documentation of each gas well liquids unloading event where 
deviations from your best management practice plan steps occurred, the 
date and time the deviation began, the duration of the deviation, 
documentation of best management practice plans steps were not 
followed, and the steps taken in lieu of your best management practice 
plan steps during those events to minimize emissions to the maximum 
extent possible.
    (iii) For each well designated facility that reduces methane 
emissions from well designated facility gas wells that unload liquids 
by 95.0 percent by routing emissions to a control device through closed 
vent system under Sec.  60.5390c(g), you must maintain the records in 
paragraphs (c)(1)(iii)(A) through (E) of this section.
    (A) If you comply with the emission reduction standard with a 
control device, the information for each control device in paragraph 
(c)(10) of this section.
    (B) Records of the closed vent system inspection as specified 
paragraph (c)(7) of this section.
    (C) Records of the cover inspections as specified in paragraph 
(c)(8) of this section.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(9) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(11) of this section.
    (2) For each associated gas well, you must maintain the applicable 
records specified in paragraphs (c)(2)(i) or (ii) and (vi) of this 
section, as applicable.
    (i) For each associated gas well that complies with the 
requirements of Sec.  60.5391c(a)(1), (2), (3), or (4), you must keep 
the records specified in paragraphs (c)(2)(i)(A) and (B) of this 
section.
    (A) Documentation of the specific method(s) in Sec.  
60.5391c(a)(1), (2), (3), or (4) that was used.
    (B) For instances where you temporarily route the associated gas to 
a flare or control device in accordance with Sec.  60.5377c(c), you 
must keep the records specified in paragraphs (c)(2)(i)(B)(1) through 
(3) of this section.
    (1) The reason in Sec.  60.5377c(c)(1), (2), (3), or (4) for each 
incident.
    (2) The date of each incident, along with the times when routing 
the associated gas to the flare or control device started and ended, 
along with the total duration of each incident.
    (3) Documentation that all CVS requirements specified in Sec.  
60.5411c(a) and (c) and all applicable flare or control device 
requirements specified in Sec.  60.5412c are met during each period 
when the associated gas is routed to the flare or control device.
    (ii) For instances where you temporarily vent the associated gas in 
accordance with Sec.  60.5377c(d), you must keep the records specified 
in paragraphs (c)(2)(ii)(A) through (D) of this section. These records 
are required if you are routinely complying with Sec.  60.5391c(a) or 
Sec.  60.5391c(b) or temporarily complying with Sec.  60.5391c(c).
    (A) The reason in Sec.  60.5391c(d)(1), (2), or (3) for each 
incident.
    (B) The date of each incident, along with the times when venting 
the associated gas started and ended, along with the total duration of 
each incident.
    (C) The methane emissions that were emitted during each incident.
    (D) The cumulative duration of venting incidents and methane 
emissions for all incidents in each calendar year.
    (iii) For each associated gas well that complies with the 
requirements of Sec.  60.5391c(b) because it has demonstrated that 
annual methane emissions are 40 tons per year or less at the initial 
compliance date, maintain records of the calculation of annual methane 
emissions determined in accordance with Sec.  60.5391c(e)(1).
    (iv) For each associated gas well at your well that complies with 
the requirements of Sec.  60.5391c(b) because it has demonstrated that 
it is not feasible to comply with Sec.  60.5391c(a)(1), (2), (3), or 
(4) due to technical reasons, records of each annual demonstration and 
certification of the technical reason that it is not feasible to comply 
with Sec.  60.5377c(a)(1), (2), (3), and (4) in accordance with Sec.  
60.5377c(b)(2)(i), (ii), and (iii), as well as the records required by 
paragraph (c)(2)(v) of this section.
    (v) For each associated gas well that complies with the 
requirements of Sec.  60.5391c(b) by routing your associated gas to a 
flare or control device that achieves a 95.0 reduction in methane 
emissions, the records in paragraphs (c)(2)(v)(A) through (E) of this 
section.
    (A) Identification of each instance when associated gas was vented 
and not routed to a control device that reduces methane emissions by at 
least 95.0 percent in accordance with paragraph (c)(2)(iii) of this 
section.
    (B) If you comply with the emission reduction standard in Sec.  
60.5392c with a control device, the information for each control device 
in paragraph (c)(10) of this section.
    (C) Records of the closed vent system inspection as specified 
paragraph (c)(7) of this section. If you comply with an alternative GHG 
standard under Sec.  60.5398c, in lieu of the information specified in 
paragraphs (c)(7) of this section, you must maintain records of the 
information specified in Sec.  60.5424c.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(9) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(11) of this section.
    (vi) Records of each deviation, the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation.
    (3) For each centrifugal compressor designated facility, you must 
maintain the records specified in paragraphs (c)(3)(i) through (iii) of 
this section.
    (i) For each centrifugal compressor designated facility, you must 
maintain records of deviations in cases where the centrifugal 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5392c, including a description of each deviation, 
the date and time each deviation began and the duration of each 
deviation.
    (ii) For each wet seal compressor complying with the emissions 
reduction standard in Sec.  60.5392c(a)(3) and (4), you must maintain 
the records in paragraphs (c)(3)(ii)(A) through (F) of this section. 
For each wet seal compressor complying with the alternative standard in 
Sec.  60.5392c(a)(3) and (5) by routing the closed vent system to a 
process, you must maintain the records in paragraphs (c)(3)(ii)(C) 
through (E) of this section.
    (A) If you comply with the emission reduction standard in with a 
control device, the information for each control device in paragraph 
(c)(10) of this section.
    (B) Records of the closed vent system inspection as specified 
paragraph (c)(7) of this section. If you comply with an alternative GHG 
standard under Sec.  60.5398c, in lieu of the information specified in 
paragraphs (c)(7) of this section, you must maintain records of the 
information specified in Sec.  60.5424c.
    (C) Records of the cover inspections as specified in paragraph 
(c)(8) of this section. If you comply with an alternative GHG standard 
under Sec.  60.5398c, in lieu of the information

[[Page 17203]]

specified in paragraph (c)(8) of this section, you must maintain the 
information specified in Sec.  60.5424c.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(9) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(11) of this section.
    (iii) For each centrifugal compressor designated facility using dry 
seals or wet seals and each self-contained wet seal centrifugal 
compressor and complying with the standard in Sec.  60.5392c(a)(1) and 
(2), you must maintain the records specified in paragraphs 
(c)(3)(iii)(A) through (H) of this section.
    (A) Records of the cumulative number of hours of operation since 
initial startup, since 36 months after the state plan submittal 
deadline (as specified in Sec.  60.5362c(c)), or since the previous 
volumetric flow rate measurement, as applicable.
    (B) A description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable.
    (C) Records for all flow meters, composition analyzers and pressure 
gauges used to measure volumetric flow rates as specified in paragraphs 
(c)(3)(iii)(C)(1) through (7) of this section.
    (1) Description of standard method published by a consensus-based 
standards organization or industry standard practice.
    (2) Records of volumetric flow rate emissions calculations 
conducted according to Sec.  60.5392c(a)(2), as applicable.
    (3) Records of manufacturer operating procedures and measurement 
methods.
    (4) Records of manufacturer's recommended procedures or an 
appropriate industry consensus standard method for calibration and 
results of calibration, recalibration and accuracy checks.
    (5) Records which demonstrate that measurements at the remote 
location(s) can, when appropriate correction factors are applied, 
reliably and accurately represent the actual temperature or total 
pressure at the flow meter under all expected ambient conditions. You 
must include the date of the demonstration, the data from the 
demonstration, the mathematical correlation(s) between the remote 
readings and actual flow meter conditions derived from the data, and 
any supporting engineering calculations. If adjustments were made to 
the mathematical relationships, a record and description of such 
adjustments.
    (6) Record of each initial calibration or a recalibration which 
failed to meet the required accuracy specification and the date of the 
successful recalibration.
    (D) Date when performance-based volumetric flow rate is exceeded.
    (E) The date of successful repair of the compressor seal, including 
follow-up performance-based volumetric flow rate measurement to confirm 
successful repair.
    (F) Identification of each compressor seal placed on delay of 
repair and explanation for each delay of repair.
    (G) For each compressor seal or part needed for repair placed on 
delay of repair because of replacement seal or part unavailability, the 
operator must document: the date the seal or part was added to the 
delay of repair list, the date the replacement seal or part was 
ordered, the anticipated seal or part delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the seal or part.
    (H) Date of planned shutdowns that occur while there are any seals 
or parts that have been placed on delay of repair.
    (4) For each reciprocating compressor designated facility, you must 
maintain the records in paragraphs (c)(4)(i) through (vi), (7), (9) and 
(11) of this section, as applicable. If you comply with an alternative 
GHG standard under Sec.  60.5398c, in lieu of the information specified 
in paragraph (c)(7) of this section, you must provide the information 
specified in Sec.  60.5424c.
    (i) For each reciprocating compressor designated facility, you must 
maintain records of deviations in cases where the reciprocating 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5393c, including a description of each deviation, 
the date and time each deviation began and the duration of each 
deviation in hours.
    (ii) Records of the date of installation of a rod packing emissions 
collection system and closed vent system as specified in Sec.  
60.5393c(d).
    (iii) Records of the cumulative number of hours of operation since 
initial startup, since 36 months after the state plan submittal 
deadline (as specified in Sec.  60.5362c(c)), or since the previous 
volumetric flow rate measurement, as applicable. Alternatively, a 
record that emissions from the rod packing are being routed to a 
process through a closed vent system.
    (iv) A description of the method used and the results of the 
volumetric flow rate measurement or emissions screening, as applicable.
    (v) Records for all flow meters, composition analyzers and pressure 
gauges used to measure volumetric flow rates as specified in paragraphs 
(c)(4)(v)(A) through (F) of this section.
    (A) Description of standard method published by a consensus-based 
standards organization or industry standard practice.
    (B) Records of volumetric flow rate calculations conducted 
according to paragraphs Sec.  60.5393c(b) or (c), as applicable.
    (C) Records of manufacturer's operating procedures and measurement 
methods.
    (D) Records of manufacturer's recommended procedures or an 
appropriate industry consensus standard method for calibration and 
results of calibration, recalibration and accuracy checks.
    (E) Records which demonstrate that measurements at the remote 
location(s) can, when appropriate correction factors are applied, 
reliably and accurately represent the actual temperature or total 
pressure at the flow meter under all expected ambient conditions. You 
must include the date of the demonstration, the data from the 
demonstration, the mathematical correlation(s) between the remote 
readings and actual flow meter conditions derived from the data, and 
any supporting engineering calculations. If adjustments were made to 
the mathematical relationships, a record and description of such 
adjustments.
    (F) Record of each initial calibration or a recalibration which 
failed to meet the required accuracy specification and the date of the 
successful recalibration.
    (vi) Date when performance-based volumetric flow rate is exceeded.
    (vii) The date of successful replacement or repair of reciprocating 
compressor rod packing, including follow-up performance-based 
volumetric flow rate measurement to confirm successful repair.
    (viii) Identification of each reciprocating compressor placed on 
delay of repair because of rod packing or part unavailability and 
explanation for each delay of repair.
    (ix) For each reciprocating compressor that is placed on delay of 
repair because of replacement rod packing or part unavailability, the 
operator must document: the date the rod packing or part was added to 
the delay of repair list, the date the replacement rod packing or part 
was ordered, the anticipated rod packing or part delivery date 
(including any estimated shipment or delivery date provided by the 
vendor), and the actual arrival date of the rod packing or part.
    (x) Date of planned shutdowns that occur while there are any 
reciprocating

[[Page 17204]]

compressors that have been placed on delay of repair due to the 
unavailability of rod packing or parts to conduct repairs.
    (5) For each process controller designated facility, you must 
maintain the records specified in paragraphs (c)(5)(i) through (vii) of 
this section.
    (i) Records identifying each process controller that is driven by 
natural gas and that does not function as an emergency shutdown device.
    (ii) For each process controller designated facility complying with 
Sec.  60.5394c(a), you must maintain records of the information 
specified in paragraphs (c)(5)(ii)(A) and (B) of this section, as 
applicable.
    (A) If you are complying with Sec.  60.5390c(a) by routing process 
controller vapors to a process through a closed vent system, you must 
report the information specified in paragraphs (c)(5)(ii)(A)(1) and (2) 
of this section.
    (1) An identification of all the natural gas-driven process 
controllers in the process controller designated facility for which you 
collect and route vapors to a process through a closed vent system.
    (2) The records specified in paragraphs (c)(7), (9), and (11) of 
this section. If you comply with an alternative GHG standard under 
Sec.  60.5398c, in lieu of the information specified in paragraph 
(c)(7) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (B) If you are complying with Sec.  60.5394c(a) by using a self-
contained natural gas-driven process controller, you must report the 
information specified in paragraphs (c)(5)(ii)(B)(1) through (3) of 
this section.
    (1) An identification of each process controller complying with 
Sec.  60.5394c(a) by using a self-contained natural gas-driven process 
controller;
    (2) Dates of each inspection required under Sec.  60.5416c(b); and
    (3) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and date of repair 
or date of anticipated repair if repair is delayed.
    (iii) For each process controller designated facility complying 
with Sec.  60.5394c(b)(1) process controller bleed rate requirements, 
you must maintain records of the information specified in paragraphs 
(c)(5)(iii)(A) and (B) of this section.
    (A) The identification of process controllers designed and operated 
to achieve a bleed rate less than or equal to 6 scfh and records of the 
manufacturer's specifications indicating that the process controller is 
designed with a natural gas bleed rate of less than or equal to 6 scfh.
    (B) Where necessary to meet a functional need, the identification 
of the process controller and demonstration of why it is necessary to 
use a process controller with a natural gas bleed rate greater than 6 
scfh.
    (iv) For each intermittent vent process controller in the 
designated facility complying with the requirements in Sec.  
60.5394c(b)(2), you must keep records of the information specified in 
paragraphs (c)(5)(iv)(A) through (C) of this section.
    (A) The identification of each intermittent vent process 
controller.
    (B) Dates and results of the intermittent vent process controller 
monitoring required by Sec.  60.5394c(b)(2)(ii).
    (C) For each instance in which monitoring identifies emissions to 
the atmosphere from an intermittent vent controller during idle 
periods, the date of repair or replacement, or the date of anticipated 
repair or replacement if the repair or replacement is delayed and the 
date and results of the re-survey after repair or replacement.
    (v) For each process controller designated facility complying with 
Sec.  60.5394c(b)(3), you must maintain the records specified in 
paragraphs (c)(5)(v)(A) and (B) of this section.
    (A) An identification of each process controller for which 
emissions are routed to a control device.
    (B) Records specified in paragraphs (c)(7) and (9) through (12) of 
this section. If you comply with an alternative GHG standard under 
Sec.  60.5398c, in lieu of the information specified in paragraphs 
(c)(7) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (vi) Records of each change in compliance method, including 
identification of each natural gas-driven process controller which 
changes its method of compliance, the new method of compliance, and the 
date of the change in compliance method.
    (vii) Records of each deviation, the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation.
    (6) For each storage vessel designated facility, you must maintain 
the records identified in paragraphs (c)(6)(i) through (vii) of this 
section.
    (i) You must maintain records of the identification and location in 
latitude and longitude coordinates in decimal degrees to an accuracy 
and precision of five (5) decimals of a degree using the North American 
Datum of 1983 of each storage vessel designated facility.
    (ii) Records of each methane emissions determination for each 
storage vessel designated facility made under Sec.  60.5396c(e) 
including identification of the model or calculation methodology used 
to calculate the methane emission rate.
    (iii) For each instance where the storage vessel was not operated 
in compliance with the requirements specified in Sec.  60.5396c, a 
description of the deviation, the date and time each deviation began, 
and the duration of the deviation.
    (iv) If complying with the emissions reduction standard in Sec.  
60.5396c(a)(1), you must maintain the records in paragraphs 
(c)(6)(iv)(A) through (E) of this section.
    (A) If you comply with the emission reduction standard with a 
control device, the information for each control device in paragraph 
(c)(10) of this section.
    (B) Records of the closed vent system inspection as specified 
paragraph (c)(7) of this section. If you comply with an alternative GHG 
standard under Sec.  60.5398c, in lieu of the information specified in 
paragraph (c)(7) of this section, you must provide the information 
specified in Sec.  60.5424c.
    (C) Records of the cover inspections as specified in paragraph 
(c)(8) of this section. If you comply with an alternative GHG standard 
under Sec.  60.5398c, in lieu of the information specified in paragraph 
(c)(8) of this section, you must provide the information specified in 
Sec.  60.5424c.
    (D) If applicable, the records of bypass monitoring as specified in 
paragraph (c)(9) of this section.
    (E) Records of the closed vent system assessment as specified in 
paragraph (c)(11) of this section.
    (v) For storage vessels that are skid-mounted or permanently 
attached to something that is mobile (such as trucks, railcars, barges, 
or ships), records indicating the number of consecutive days that the 
vessel is located at a site in the crude oil and natural gas source 
category. If a storage vessel is removed from a site and, within 30 
days, is either returned to the site or replaced by another storage 
vessel at the site to serve the same or similar function, then the 
entire period since the original storage vessel was first located at 
the site, including the days when the storage vessel was removed, will 
be added to the count towards the number of consecutive days.
    (vi) Records of the date that each storage vessel designated 
facility or portion of a storage vessel designated facility is removed 
from service and returned to service, as applicable.
    (vii) Records of the date that liquids from the well following 
fracturing or refracturing are routed to the storage

[[Page 17205]]

vessel designated facility; or the date that you comply with paragraph 
Sec.  60.5396c(a)(2), following a monthly emissions determination which 
indicates that methane emissions increase to 14 tpy or greater and the 
increase is not associated with fracturing or refracturing of a well 
feeding the storage vessel designated facility, and records of the 
methane emissions rate and the model or calculation methodology used to 
calculate the methane emission rate.
    (7) Records of each closed vent system inspection required under 
Sec.  60.5416c(a)(1) and (2) and (b) for your well, centrifugal 
compressor, reciprocating compressor, process controller, pump, storage 
vessel, and process unit equipment designated facility as required in 
paragraphs (c)(7)(i) through (iv) of this section.
    (i) A record of each closed vent system inspection or no 
identifiable emissions monitoring survey. You must include an 
identification number for each closed vent system (or other unique 
identification description selected by you), the date of the 
inspection, and the method used to conduct the inspection (i.e., 
visual, AVO, OGI, Method 21 of appendix A-7 to this part).
    (ii) For each defect or emissions detected during inspections 
required by Sec.  60.5416c(a)(1) and (2), or (b) you must record the 
location of the defect or emissions; a description of the defect; the 
maximum concentration reading obtained if using Method 21 of appendix 
A-7 to this part; the indication of emissions detected by AVO if using 
AVO; the date of detection; the date of each attempt to repair the 
emissions or defect; the corrective action taken during each attempt to 
repair the defect; and the date the repair to correct the defect or 
emissions is completed.
    (iii) If repair of the defect is delayed as described in Sec.  
60.5416c(b)(6), you must record the reason for the delay and the date 
you expect to complete the repair.
    (iv) Parts of the closed vent system designated as unsafe to 
inspect as described in Sec.  60.5416c(b)(7) or difficult to inspect as 
described in Sec.  60.5416c(b)(8), the reason for the designation, and 
written plan for inspection of that part of the closed vent system.
    (8) A record of each cover inspection required under Sec.  
60.5416c(a)(3) for your centrifugal compressor, reciprocating 
compressor, or storage vessel as required in paragraphs (c)(8)(i) 
through (iv) of this section.
    (i) A record of each cover inspection. You must include an 
identification number for each cover (or other unique identification 
description selected by you), the date of the inspection, and the 
method used to conduct the inspection (i.e., AVO, OGI, Method 21 of 
appendix A-7 to this part).
    (ii) For each defect detected during the inspection you must record 
the location of the defect; a description of the defect; the date of 
detection; the maximum concentration reading obtained if using Method 
21 of appendix A-7 to this part; the indication of emissions detected 
by AVO if using AVO; the date of each attempt to repair the defect; the 
corrective action taken during each attempt to repair the defect; and 
the date the repair to correct the defect is completed.
    (iii) If repair of the defect is delayed as described in Sec.  
60.5416c(b)(5), you must record the reason for the delay and the date 
you expect to complete the repair.
    (iv) Parts of the cover designated as unsafe to inspect as 
described in Sec.  60.5416c(b)(7) or difficult to inspect as described 
in Sec.  60.5416c(b)(8), the reason for the designation, and written 
plan for inspection of that part of the cover.
    (9) For each bypass subject to the bypass requirements of Sec.  
60.5416c(a)(4), you must maintain a record of the following, as 
applicable: readings from the flow indicator; each inspection of the 
seal or closure mechanism; the date and time of each instance the key 
is checked out; date and time of each instance the alarm is sounded.
    (10) Records for each control device used to comply with the 
emission reduction standard in Sec.  60.5391c(b) for associated gas 
wells, Sec.  60.5392c(a)(4) for centrifugal compressor designated 
facilities, Sec.  60.5393c(d)(2) for reciprocating compressor 
designated facilities, Sec.  60.5394c(b)(3) for your process controller 
designated facility in Alaska, Sec.  60.5395c(b)(1) for your pump 
designated facility, Sec.  60.5396c(a)(2) for your storage vessel 
designated facility, Sec.  60.5390c(f) for well designated facility gas 
well liquids unloading, or Sec.  60.5400c(f) or 60.5401c(e) for your 
process equipment designated facility, as required in paragraphs 
(c)(10)(i) through (viii) of this section. If you use an enclosed 
combustion device or flare using an alternative test method approved 
under Sec.  60.5412c(d), keep records of the information in paragraphs 
(c)(10)(ix) of this section, in lieu of the records required by 
paragraphs (c)(10)(i) through (iv) and (vi) through (viii) of this 
section.
    (i) For a control device tested under Sec.  60.5413c(d) which meets 
the criteria in Sec.  60.5413c(d)(11) and (e), keep records of the 
information in paragraphs (c)(10)(i)(A) through (E) of this section, in 
addition to the records in paragraphs (c)(10)(ii) through (ix) of this 
section, as applicable.
    (A) Serial number of purchased device and copy of purchase order.
    (B) Location of the designated facility associated with the control 
device in latitude and longitude coordinates in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using the North 
American Datum of 1983.
    (C) Minimum and maximum inlet gas flow rate specified by the 
manufacturer.
    (D) Records of the maintenance and repair log as specified in Sec.  
60.5413c(e)(4), for all inspection, repair, and maintenance activities 
for each control device failing the visible emissions test.
    (E) Records of the manufacturer's written operating instructions, 
procedures, and maintenance schedule to ensure good air pollution 
control practices for minimizing emissions.
    (ii) For all control devices, keep records of the information in 
paragraphs (c)(10)(ii)(A) through (G) of this section, as applicable.
    (A) Make, model, and date of installation of the control device, 
and identification of the designated facility controlled by the device.
    (B) Records of deviations in accordance with Sec.  60.5417c(g)(1) 
through (7), including a description of the deviation, the date and 
time the deviation began, the duration of the deviation, and the cause 
of the deviation.
    (C) The monitoring plan required by Sec.  60.5417c(c)(2).
    (D) Make and model number of each continuous parameter monitoring 
system.
    (E) Records of minimum and maximum operating parameter values, 
continuous parameter monitoring system data (including records that the 
pilot or combustion flame is present at all times), calculated averages 
of continuous parameter monitoring system data, and results of all 
compliance calculations.
    (F) Records of continuous parameter monitoring system equipment 
performance checks, system accuracy audits, performance evaluations, or 
other audit procedures and results of all inspections specified in the 
monitoring plan in accordance with Sec.  60.5417c(c)(2). Records of 
calibration gas cylinders, if applicable.

[[Page 17206]]

    (G) Periods of monitoring system malfunctions, repairs associated 
with monitoring system malfunctions and required monitoring system 
quality assurance or quality control activities Records of repairs on 
the monitoring system.
    (iii) For each carbon adsorption system, records of the schedule 
for carbon replacement as determined by the design analysis 
requirements of Sec.  60.5413c(c)(2) and (3) and records of each carbon 
replacement as specified in Sec.  60.5412c(c)(1) and Sec.  
60.5415c(e)(1)(viii).
    (iv) For enclosed combustion devices and flares, records of visible 
emissions observations as specified in paragraph (c)(10)(iv)(A) or (B) 
of this section.
    (A) Records of observations with Method 22 of appendix A-7 to this 
part, including observations required following return to operation 
from a maintenance or repair activity, which include: company, 
location, company representative (name of the person performing the 
observation), sky conditions, process unit (type of control device), 
clock start time, observation period duration (in minutes and seconds), 
accumulated emission time (in minutes and seconds), and clock end time. 
You may create your own form including the above information or use 
Figure 22-1 in Method 22 of appendix A-7 to this part.
    (B) If you monitor visible emissions with a video surveillance 
camera, location of the camera and distance to emission source, records 
of the video surveillance output, and documentation that an operator 
looked at the feed daily, including the date and start time of 
observation, the length of observation, and length of time visible 
emissions were present.
    (v) For enclosed combustion devices and flares, video of the OGI 
inspection conducted in accordance with Sec.  60.5415c(e)(x). Records 
documenting each enclosed combustion device and flare was visibly 
observed during each inspection conducted under Sec.  60.5397c using 
AVO in accordance with Sec.  60.5415c(e)(x).
    (vi) For enclosed combustion devices and flares, records of each 
demonstration of the NHV of the inlet gas to the enclosed combustion 
device or flare conducted in accordance with Sec.  60.5417c(d)(8)(iii). 
For each re-evaluation of the NHV of the inlet gas, records of process 
changes and explanation of the conditions that led to the need to re-
evaluation the NHV of the inlet gas. For each demonstration, record 
information on whether the enclosed combustion device or flare has the 
potential to receive inert gases, and if so, the highest percentage of 
inert gases that can be sent to the enclosed combustion device or flare 
and the highest percent of inert gases sent to the enclosed combustion 
device or flare during the NHV demonstration. Records of periodic 
sampling conducted under Sec.  60.5417c(d)(8)(iii)(G).
    (vii) For enclosed combustion devices and flares, if you use a 
backpressure regulator valve, the make and model of the valve, date of 
installation, and record of inlet flow rating. Maintain records of the 
engineering evaluation and manufacturer specifications that identify 
the pressure set point corresponding to the minimum inlet gas flow 
rate, the annual confirmation that the backpressure regulator valve set 
point is correct and consistent with the engineering evaluation and 
manufacturer specifications, and the annual confirmation that the 
backpressure regulator valve fully closes when not in open position.
    (viii) For enclosed combustion devices and flares, records of each 
demonstration required under Sec.  60.5417c(d)(8)(iv).
    (ix) If you use an enclosed combustion device or flare using an 
alternative test method approved under Sec.  60.5412c(d), keep records 
of the information in paragraphs (c)(10)(ix)(A) through (H) of this 
section, in lieu of the records required by paragraphs (c)(10)(i) 
through (iv) and (vi) through (viii) of this section.
    (A) An identification of the alternative test method used.
    (B) Data recorded at the intervals required by the alternative test 
method.
    (C) Monitoring plan required by Sec.  60.5417c(i)(2).
    (D) Quality assurance and quality control activities conducted in 
accordance with the alternative test method.
    (E) If required by Sec.  60.5412c(d)(4) to conduct visible 
emissions observations, records required by paragraph (c)(10)(iv) of 
this section.
    (F) If required by Sec.  60.5412c(d)(5) to conduct pilot or 
combustion flame monitoring, record indicating the presence of a pilot 
or combustion flame and periods when the pilot or combustion flame is 
absent.
    (G) For each instance where there is a deviation of the control 
device in accordance with Sec.  60.5417c(i)(6)(i) through (v), the date 
and time the deviation began, the duration of the deviation in hours, 
and cause of the deviation.
    (H) Any additional information required to be recorded as specified 
by the Administrator as part of the alternative test method approval 
under Sec.  60.5412c(d).
    (11) For each closed vent system routing to a control device or 
process, the records of the assessment conducted according to Sec.  
60.5411c(c):
    (i) A copy of the assessment conducted according to Sec.  
60.5411c(c)(1); and
    (ii) A copy of the certification according to Sec.  
60.5411c(c)(1)(i) and (ii).
    (12) A copy of each performance test submitted under paragraphs 
(b)(11) or (12) of this section.
    (13) For the fugitive emissions components designated facility, 
maintain the records identified in paragraphs (c)(13)(i) through (vii) 
of this section.
    (i) The date of the startup of production or the date of the first 
day of production after modification for the fugitive emissions 
components designated facility at a well site and the date of startup 
or the date of modification for the fugitive emissions components 
designated facility at a compressor station.
    (ii) For the fugitive emissions components designated facility at a 
well site, you must maintain records specifying what type of well site 
it is (i.e., single wellhead only well site, small wellsite, multi-
wellhead only well site, or a well site with major production and 
processing equipment.)
    (iii) For the fugitive emissions components designated facility at 
a well site where you complete the removal of all major production and 
processing equipment such that the well site contains only one or more 
wellheads, record the date the well site completes the removal of all 
major production and processing equipment from the well site, and, if 
the well site is still producing, record the well ID or separate tank 
battery ID receiving the production from the well site. If major 
production and processing equipment is subsequently added back to the 
well site, record the date that the first piece of major production and 
processing equipment is added back to the well site.
    (iv) The fugitive emissions monitoring plan as required in Sec.  
60.5397c(b), (c), and (d).
    (v) The records of each monitoring survey as specified in 
paragraphs (c)(13)(v)(A) through (I) of this section.
    (A) Date of the survey.
    (B) Beginning and end time of the survey.
    (C) Name of operator(s), training, and experience of the 
operator(s) performing the survey.
    (D) Monitoring instrument or method used.

[[Page 17207]]

    (E) Fugitive emissions component identification when Method 21 of 
appendix A-7 to this part is used to perform the monitoring survey.
    (F) Ambient temperature, sky conditions, and maximum wind speed at 
the time of the survey. For compressor stations, operating mode of each 
compressor (i.e., operating, standby pressurized, and not operating-
depressurized modes) at the station at the time of the survey.
    (G) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (H) Records of calibrations for the instrument used during the 
monitoring survey.
    (I) Documentation of each fugitive emission detected during the 
monitoring survey, including the information specified in paragraphs 
(c)(13)(v)(I)(1) through (9) of this section.
    (1) Location of each fugitive emission identified.
    (2) Type of fugitive emissions component, including designation as 
difficult-to-monitor or unsafe-to-monitor, if applicable.
    (3) If Method 21 of appendix A-7 to this part is used for 
detection, record the component ID and instrument reading.
    (4) For each repair that cannot be made during the monitoring 
survey when the fugitive emissions are initially found, a digital 
photograph or video must be taken of that component or the component 
must be tagged for identification purposes. The digital photograph must 
include the date that the photograph was taken and must clearly 
identify the component by location within the site (e.g., the latitude 
and longitude of the component or by other descriptive landmarks 
visible in the picture). The digital photograph or identification 
(e.g., tag) may be removed after the repair is completed, including 
verification of repair with the resurvey.
    (5) The date of first attempt at repair of the fugitive emissions 
component(s).
    (6) The date of successful repair of the fugitive emissions 
component, including the resurvey to verify repair and instrument used 
for the resurvey.
    (7) Identification of each fugitive emission component placed on 
delay of repair and explanation for each delay of repair.
    (8) For each fugitive emission component placed on delay of repair 
for reason of replacement component unavailability, the operator must 
document: the date the component was added to the delay of repair list, 
the date the replacement fugitive component or part thereof was 
ordered, the anticipated component delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the component.
    (9) Date of planned shutdowns that occur while there are any 
components that have been placed on delay of repair.
    (vi) For well closure activities, you must maintain the information 
specified in paragraphs (c)(13)(vi)(A) through (G) of this section.
    (A) The well closure plan developed in accordance with Sec.  
60.5397c(l) and the date the plan was submitted.
    (B) The notification of the intent to close the well site and the 
date the notification was submitted.
    (C) The date of the cessation of production from all wells at the 
well site.
    (D) The date you began well closure activities at the well site.
    (E) Each status report for the well closure activities reported in 
paragraph (b)(8)(iv)(A) of this section.
    (F) Each OGI survey reported in paragraph (b)(8)(iv)(B) of this 
section including the date, the monitoring instrument used, and the 
results of the survey or resurvey.
    (G) The final OGI survey video demonstrating the closure of all 
wells at the site. The video must include the date that the video was 
taken and must identify the well site location by latitude and 
longitude.
    (vii) If you comply with an alternative GHG standard under Sec.  
60.5398c, in lieu of the information specified in paragraphs 
(c)(13)(iv) and (v) of this section, you must maintain the records 
specified in Sec.  60.5424c.
    (14) For each pump designated facility, you must maintain the 
records identified in paragraphs (c)(14)(i) through (viii) of this 
section.
    (i) Identification of each pump that is driven by natural gas and 
that is in operation 90 days or more per calendar year.
    (ii) If you are complying with Sec.  60.5395c(a) or (b)(1) by 
routing pump vapors to a process through a closed vent system, 
identification of all the natural gas-driven pumps in the pump 
designated facility for which you collect and route vapors to a process 
through a closed vent system and the records specified in paragraphs 
(c)(7), (9), and (11) of this section. If you comply with an 
alternative GHG and VOC standard under Sec.  60.5398c, in lieu of the 
information specified in paragraph (c)(7) of this section, you must 
provide the information specified in Sec.  60.5424c.
    (iii) If you are complying with Sec.  60.5395c(b)(1) by routing 
pump vapors to control device achieving a 95.0 percent reduction in 
methane emissions, you must keep the records specified in paragraphs 
(c)(7) and (c)(9) through (c)(12) of this section. If you comply with 
an alternative GHG and VOC standard under Sec.  60.5398c, in lieu of 
the information specified in paragraph (c)(7) of this section, you must 
provide the information specified in Sec.  60.5424c.
    (iv) If you are complying with Sec.  60.5395c(b)(3) by routing pump 
vapors to a control device achieving less than a 95.0 percent reduction 
in methane emissions, you must maintain records of the certification 
that there is a control device on site but it does not achieve a 95.0 
percent emissions reduction and a record of the design evaluation or 
manufacturer's specifications which indicate the percentage reduction 
the control device is designed to achieve.
    (v) If you have less than three natural gas-driven diaphragm pumps 
in the pump designated facility, and you do not have a vapor recovery 
unit or control device installed on site by the compliance date, you 
must retain a record of your certification required under Sec.  
60.5395c(b)(4), certifying that there is no vapor recovery unit or 
control device on site. If you subsequently install a control device or 
vapor recovery unit, you must maintain the records required under 
paragraphs (c)(14)(ii) and (iii) or (iv) of this section, as 
applicable.
    (vi) If you determine, through an engineering assessment, that it 
is technically infeasible to route the pump designated facility 
emissions to a process or control device, you must retain records of 
your demonstration and certification that it is technically infeasible 
as required under Sec.  60.5395c(b)(7).
    (vii) If the pump is routed to a process or control device that is 
subsequently removed from the location or is no longer available such 
that there is no option to route to a process or control device, you 
are required to retain records of this change and the records required 
under paragraph (c)(14)(vi) of this section.
    (viii) Records of each change in compliance method, including 
identification of each natural gas-driven pump which changes its method 
of compliance, the new method of compliance, and the date of the change 
in compliance method.
    (ix) Records of each deviation, the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation.
    (d) Electronic reporting. If you are required to submit 
notifications or reports following the procedure specified in this 
paragraph (d), you must

[[Page 17208]]

submit notifications or reports to the EPA via CEDRI, which can be 
accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). The EPA will make all the information submitted through 
CEDRI available to the public without further notice to you. Do not use 
CEDRI to submit information you claim as CBI. Although we do not expect 
persons to assert a claim of CBI, if you wish to assert a CBI claim for 
some of the information in the report or notification, you must submit 
a complete file in the format specified in this subpart, including 
information claimed to be CBI, to the EPA following the procedures in 
paragraphs (g)(1) and (2) of this section. Clearly mark the part or all 
of the information that you claim to be CBI. Information not marked as 
CBI may be authorized for public release without prior notice. 
Information marked as CBI will not be disclosed except in accordance 
with procedures set forth in 40 CFR part 2. All CBI claims must be 
asserted at the time of submission. Anything submitted using CEDRI 
cannot later be claimed CBI. Furthermore, under CAA section 114(c), 
emissions data is not entitled to confidential treatment, and the EPA 
is required to make emissions data available to the public. Thus, 
emissions data will not be protected as CBI and will be made publicly 
available. You must submit the same file submitted to the CBI office 
with the CBI omitted to the EPA via the EPA's CDX as described earlier 
in this paragraph (d).
    (1) The preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol, or 
other online file sharing services. Electronic submissions must be 
transmitted directly to the OAQPS CBI Office at the email address 
<a href="/cdn-cgi/l/email-protection#234c4252535040414a634653420d444c55"><span class="__cf_email__" data-cfemail="1b747a6a6b687879725b7e6b7a357c746d">[email protected]</span></a>, and as described above, should include clear CBI 
markings. ERT files should be flagged to the attention of the Group 
Leader, Measurement Policy Group; all other files should be flagged to 
the attention of the Oil and Natural Gas Sector Lead. 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 <a href="/cdn-cgi/l/email-protection#57383626272434353e1732273679303821"><span class="__cf_email__" data-cfemail="38575949484b5b5a51785d4859165f574e">[email protected]</span></a> to request a file 
transfer link.
    (2) If you cannot transmit the file electronically, you may send 
CBI information through the postal service to the following address: 
U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109 
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should 
be sent to the secondary attention of the Group Leader, Measurement 
Policy Group, and all other files should be sent to the secondary 
attention of the Oil and Natural Gas Sector Lead. The mailed CBI 
material should be double wrapped and clearly marked. Any CBI markings 
should not show through the outer envelope.
    (e) Claims of EPA system outage. If you are required to 
electronically submit a notification or report through CEDRI in the 
EPA's CDX, you may assert a claim of EPA system outage for failure to 
timely comply with that requirement. To assert a claim of EPA system 
outage, you must meet the requirements outlined in paragraphs (e)(1) 
through (7) of this section.
    (1) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (2) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.
    (3) The outage may be planned or unplanned.
    (4) You must submit notification to the Administrator in writing as 
soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (5) You must provide to the Administrator a written description 
identifying:
    (i) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (ii) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (iii) A description of measures taken or to be taken to minimize 
the delay in reporting; and
    (iv) The date by which you propose to report, or if you have 
already met the reporting requirement at the time of the notification, 
the date you reported.
    (6) The decision to accept the claim of EPA system outage and allow 
an extension to the reporting deadline is solely within the discretion 
of the Administrator.
    (7) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (f) Claims of force majeure. If you are required to electronically 
submit a report or notification through CEDRI in the EPA's CDX, you may 
assert a claim of force majeure for failure to timely comply with that 
requirement. To assert a claim of force majeure, you must meet the 
requirements outlined in paragraphs (f)(1) through (5) of this section.
    (1) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the designated facility, 
its contractors, or any entity controlled by the designated facility 
that prevents you from complying with the requirement to submit a 
report electronically within the time period prescribed. Examples of 
such events are acts of nature (e.g., hurricanes, earthquakes, or 
floods), acts of war or terrorism, or equipment failure or safety 
hazard beyond the control of the designated facility (e.g., large scale 
power outage).
    (2) You must submit notification to the Administrator in writing as 
soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (3) You must provide to the Administrator:
    (i) A written description of the force majeure event;
    (ii) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (iii) A description of measures taken or to be taken to minimize 
the delay in reporting; and
    (iv) The date by which you propose to report, or if you have 
already met the reporting requirement at the time of the notification, 
the date you reported.
    (4) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (5) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.


Sec.  60.5421c   What are my additional recordkeeping requirements for 
process unit equipment designated facilities?

    You must maintain a record of each equipment leak monitoring 
inspection and each leak identified under Sec.  60.5400c and Sec.  
60.5401c as specified in paragraphs (b)(1) through (16) of this 
section. The record must be maintained either onsite or at the nearest 
local field office for at least 5 years. Any records required to be 
maintained that are submitted electronically via the EPA's CEDRI may be 
maintained in electronic format. This ability to maintain electronic 
copies does not affect the requirement for facilities to make records, 
data, and reports available

[[Page 17209]]

upon request to a delegated air agency or the EPA as part of an on-site 
compliance evaluation.
    (a) You may comply with the recordkeeping requirements for multiple 
process unit equipment designated facilities in one recordkeeping 
system if the system identifies each record by each facility.
    (b) You must maintain the monitoring inspection records specified 
in paragraphs (b)(1) through (16) of this section.
    (1) Note that connectors need not be individually identified if all 
connectors in a designated area or length of pipe subject to the 
provisions of this subpart are identified as a group, and the number of 
connectors subject is indicated.
    (2) Date and start and end times of the monitoring inspection.
    (3) Inspector name.
    (4) Leak determination method used for the monitoring inspection 
(i.e., OGI, Method 21, or AVO).
    (5) Monitoring instrument identification (OGI and Method 21 only).
    (6) Type of equipment monitored.
    (7) Process unit identification.
    (8) The records specified in Section 12 of appendix K to this part, 
for each monitoring inspection conducted with OGI.
    (9) The records in paragraph (b)(9)(i) through (vii) of this 
section, for each monitoring inspection conducted with Method 21 of 
appendix A-7 to this part.
    (i) Instrument reading.
    (ii) Date and time of instrument calibration and initials of 
operator performing the calibration.
    (iii) Calibration gas cylinder identification, certification date, 
and certified concentration.
    (iv) Instrument scale used.
    (v) A description of any corrective action taken if the meter 
readout could not be adjusted to correspond to the calibration gas 
value in accordance with section 10.1 of Method 21 of appendix A-7 to 
this part.
    (vi) Results of the daily calibration drift assessment.
    (vii) If you make your own calibration gas, a description of the 
procedure used.
    (10) For visual inspections of pumps in light liquid service, keep 
the records specified in paragraphs (b)(10)(i) through (iii) of this 
section, for each monitored equipment:
    (i) Date of inspection.
    (ii) Inspector name.
    (iii) Result of inspection (i.e., visual indications of liquids 
dripping from the pump seal or no visual indications of liquids 
dripping from the pump seal).
    (11) For each leak detected, the records specified in paragraphs 
(b)(11)(i) through (v) of this section:
    (i) The instrument and operator identification numbers and the 
process unit and equipment identification numbers. For leaks identified 
via visual, olfactory, audible methods, enter the specific sensory 
method for instrument identification number.
    (ii) The date the leak was detected.
    (iii) For each attempt to repair the leak, record:
    (A) The date.
    (B) The repair method applied.
    (C) Indication of whether a leak was still detected following each 
attempt to repair the leak.
    (vi) The date of successful repair of the leak and the method of 
monitoring used to confirm the repair, as specified in paragraph 
(b)(11)(vi)(A) through (C) of this section.
    (A) If Method 21 of appendix A-7 to this part is used to confirm 
the repair, maintain a record of the maximum instrument reading 
measured by Method 21 of appendix A-7 to this part.
    (B) If OGI conducted in accordance with appendix K to this part is 
used to confirm the repair, maintain a record of video footage of the 
repair confirmation.
    (C) If the leak is repaired by eliminating AVO indications of a 
leak, maintain a record of the specific sensory method used to confirm 
that the evidence of the leak is eliminated.
    (v) For each repair delayed beyond 15 calendar days after detection 
of the leak, record:
    (A) ``Repair delayed'' and the reason for the delay.
    (B) The signature of the certifying official who made the decision 
that repair could not be completed without a process shutdown.
    (C) The expected date of successful repair of the leak.
    (D) Dates of process unit shutdowns that occur while the equipment 
is unrepaired.
    (12) A list of identification numbers for equipment that are 
designated for no detectable emissions complying with the provisions of 
Sec.  60.5401c.
    (13) A list of identification numbers for valves, pumps, and 
connectors that are designated as unsafe-to-monitor, an explanation for 
each valve, pump, or connector stating why the valve, pump, or 
connector is unsafe-to-monitor, and the plan for monitoring each valve, 
pump, or connector.
    (14) A list of identification numbers for valves that are 
designated as difficult-to-monitor, an explanation for each valve 
stating why the valve is difficult-to-monitor, and the schedule for 
monitoring each valve.
    (15) A list of identification numbers for equipment that is in 
vacuum service.
    (16) A list of identification numbers for equipment you designate 
as having the potential to emit methane less than 300 hr/yr.
    (17) A list of identification numbers for valves where it was 
infeasible to replace leaking valves with low-e valves or repack 
existing valves with low-e packing technology, including the reasoning 
for why it was infeasible.


Sec.  60.5422c   What are my additional reporting requirements for 
process unit equipment designated facilities?

    (a) You must submit semiannual reports using the appropriate 
electronic report template on the CEDRI website for this subpart and 
following the procedure specified in Sec.  60.5420c(d). If the 
reporting form specific to this subpart is not available on the CEDRI 
website at the time that the report is due, submit the report to the 
Administrator at the appropriate address listed in Sec.  60.4. Once the 
form has been available on the CEDRI website for at least 90 calendar 
days, you must begin submitting all subsequent reports via CEDRI. The 
date reporting forms become available will be listed on the CEDRI 
website. Unless the Administrator or delegated state agency or other 
authority has approved a different schedule for submission of reports, 
the report must be submitted within 45 days after the end of the 
semiannual reporting period, regardless of the method in which the 
report is submitted.
    (b) The initial semiannual report must include the following 
information:
    (1) The general information specified in paragraph (c)(1) of this 
section.
    (2) For each process unit:
    (i) Process unit identification.
    (ii) Number of valves subject to the monitoring requirements of 
Sec.  60.5400c(b) and Sec.  60.5401c(f).
    (iii) Number of pumps subject to the monitoring requirements of 
Sec.  60.5400c(b) and Sec.  60.5401c(b).
    (iv) Number of connectors subject to the monitoring requirements of 
Sec.  60.5400c(b) and Sec.  60.5401c(h).
    (v) Number of pressure relief devices subject to the monitoring 
requirements of Sec.  60.5400c(b) and Sec.  60.5401c(c).
    (vi) The information in paragraphs (c)(3) and (4) of this section.
    (c) All subsequent semiannual reports must include the following 
information:
    (1) The general information specified in paragraphs (c)(1)(i) 
through (iii) of this section.
    (i) The company name, facility site name, and address of the 
designated facility.

[[Page 17210]]

    (ii) Beginning and ending dates of the reporting period.
    (iii) A certification by a certifying official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete. If 
your report is submitted via CEDRI, the certifier's electronic 
signature during the submission process replaces the requirement in 
this paragraph (c)(1)(iii).
    (2) Process unit identification for each process unit.
    (3) For each month during the semiannual reporting period for each 
process unit report:
    (i) Number of valves for which leaks were detected as described in 
Sec.  60.5400c(b) or Sec.  60.5401c(f).
    (ii) Number of valves for which leaks were not repaired as required 
in Sec.  60.5400c(h) or Sec.  60.5401c(i) and the number of instances 
where it was technically infeasible to replace leaking valves with low-
e valves or repack existing valves with low-e packing technology, 
including the reasoning for why it was technically infeasible.
    (iii) Number of pumps for which leaks were detected as described 
Sec.  60.5400c(b) or Sec.  60.5401c(b).
    (iv) Number of pumps for which leaks were not repaired as required 
in Sec.  60.5400c(h) or Sec.  60.5401c(i).
    (v) Number of connectors for which leaks were detected as described 
in Sec.  60.5400c(b) or Sec.  60.5401c(h).
    (vi) Number of connectors for which leaks were not repaired as 
required in Sec.  60.5400c(h) or Sec.  60.5401c(i).
    (vii) Number of pressure relief devices for which leaks were 
detected as described in Sec.  60.5400c(b) or Sec.  60.5401c(c).
    (viii) Number of pressure relief devices for which leaks were not 
repaired as required in Sec.  60.5400c(h) or Sec.  60.5401c(i).
    (ix) Number of open-ended valves or lines for which leaks were 
detected as described in Sec.  60.5400c(e) of Sec.  60.5401c(d).
    (x) Number of open-ended valves or lines for which leaks were not 
repaired as required in Sec.  60.5400c(h) or Sec.  60.5401c(i).
    (xi) Number of pumps, valves, or connectors in heavy liquid service 
or pressure relief device in light liquid or heavy liquid service for 
which leaks were detected as described in Sec.  60.5400c(g) or Sec.  
60.5401c(g).
    (xii) Number of pumps, valves, or connectors in heavy liquid 
service or pressure relief device in light liquid or heavy liquid 
service for which leaks were not repaired as required in Sec.  
60.5400c(h) or Sec.  60.5401c(i).
    (xiii) The facts that explain each delay of repair and, where 
appropriate, why a process unit shutdown was technically infeasible.
    (4) Dates of process unit shutdowns which occurred within the 
semiannual reporting period.
    (5) Revisions to items reported according to paragraph (b) of this 
section if changes have occurred since the initial report or subsequent 
revisions to the initial report.


Sec.  60.5424c  What are my additional recordkeeping and reporting 
requirements if I comply with the alternative GHG standards for 
fugitive emissions components designated facilities and covers and 
closed vent systems?

    This section provides notification, reporting, and recordkeeping 
requirements for owners and operators who choose to comply with an 
alternative GHG standard as specified in Sec.  60.5398c for fugitive 
emissions components designated facilities and the alternative 
continuous inspection and monitoring requirements for covers and closed 
vent systems. You must submit an annual report in accordance with the 
schedule in Sec.  60.5420c(b) which includes the information in 
paragraphs (a)(1), (b), and (d) of this section, as applicable. You 
must submit the notification in paragraph (a)(2) of this section and 
maintain the records in paragraphs (c) and (e) of this section, as 
applicable.
    (a) Notifications. If you choose to comply with an alternative GHG 
standard as specified in Sec.  60.5398c for fugitive emissions 
components designated facilities and the alternative continuous 
inspection and monitoring requirements for covers and closed vent 
systems, you must submit the notification in paragraph (a)(1) of this 
section. If you are required by Sec.  60.5398c(c)(8) to develop a mass 
emission rate reduction plan, you must submit the notification in 
paragraph (a)(2) of this section.
    (1) A notification to the Administrator of adoption of the 
alternative standards in the annual report required by Sec.  
60.5420c(b)(3) through (10).
    (2) A notification, which includes the submittal of the mass 
emission rate reduction plan required by Sec.  60.5398c(c)(8). You must 
submit the mass emission rate reduction plan to the Administrator 
within 60 days of the initial exceedance of the action level.
    (b) If you comply with the periodic screening requirements of Sec.  
60.5398c(b), you must submit the information in paragraphs (b)(1) 
through (6) of this section in the annual report required by Sec.  
60.5420c(b)(3) through (10).
    (1) Date of each periodic screening during the reporting period and 
date that results of the periodic screening were received.
    (2) Alternative test method and technology used for each screening 
and the spatial resolution of the technology (i.e., facility-level, 
area-level, or component level).
    (3) Any deviations from the monitoring plan developed under Sec.  
60.5398c(b)(1) or a statement that there were no deviations from the 
monitoring plan.
    (4) Results from each periodic screening during the reporting 
period. If the results of the periodic screening indicate a confirmed 
detection of emissions from a designated facility, you must submit the 
information in paragraphs (b)(4)(i) through (iv) of this section.
    (i) The date that the monitoring survey of your entire or the 
required portion of your fugitive emissions components designated 
facility was conducted.
    (ii) The date that you completed the instrument inspections of all 
required covers and closed vent systems(s).
    (iii) The date that you conducted the visual inspection for 
emissions of all required closed vent systems and covers.
    (iv) For each fugitive emission from a fugitive emissions 
components designated facility and all emissions or defects of each 
cover and closed vent system, you must submit the information in 
paragraphs (b)(4)(iv)(A) through (D) of this section.
    (A) Number and type of components for which fugitive emissions were 
detected.
    (B) Each emission or defect identified during the inspection for 
each cover and closed vent system.
    (C) Date of repair for each fugitive emission from a fugitive 
emissions components designated facility or each emission or defect for 
each cover and closed vent system.
    (D) Number and type of fugitive emission components and 
identification of each cover or closed vent system placed on delay of 
repair and an explanation for each delay of repair.
    (5) The information in paragraphs (b)(5)(i) through (iv) of this 
section if you are required to conduct OGI surveys in accordance with 
Sec.  60.5398c(b)(1)(i) or if you replace a periodic screening event 
with an OGI survey in accordance with Sec.  60.5398c(b)(1)(iv).
    (i) The date of the OGI survey.

[[Page 17211]]

    (ii) Number and type of components for which fugitive emissions 
were detected.
    (iii) Number and type of fugitive emissions components that were 
not repaired as required in Sec.  60.5397c(h).
    (iv) Number and type of fugitive emission components placed on 
delay of repair and an explanation for each delay of repair.
    (6) Any additional information regarding the performance of the 
periodic screening technology as specified by the Administrator, as 
part of the alternative test method approval described in Sec.  
60.5398b(d).
    (c) If you comply with the periodic screening requirements of Sec.  
60.5398c(b), you must maintain the records in paragraphs (c)(1) through 
(11) of this section in addition to the records as specified in Sec.  
60.5420c(c)(2) through (8) and (c)(13) and (14).
    (1) The monitoring plan as required in Sec.  60.5398c(b)(2).
    (2) Date of each periodic screening and date that results of the 
periodic screening were received.
    (3) Name of screening operator.
    (4) Alternative test method and technology used for screening, as 
well as the aggregate detection threshold for the technology and the 
spatial resolution of the technology (i.e., facility-level, area-level, 
or component-level).
    (5) Records of calibrations for technology used during the 
screening, if calibration is required by the alternative test method 
approved in accordance with Sec.  60.5398b(d).
    (6) Results from periodic screening. If the results of the periodic 
screening indicate a confirmed detection of emissions from a designated 
facility, you must maintain the records in paragraphs (c)(6)(i) through 
(v) of this section.
    (i) The date of the inspection of the fugitive emissions components 
and inspection of covers and closed vent system, as specified in Sec.  
60.5398c(b)(5).
    (ii) Name of operator(s) performing the survey or inspection.
    (iii) For surveys and instrument inspections, identification of the 
monitoring instrument(s) used.
    (iv) Records of calibrations for the instrument(s) used during the 
survey or instrument inspection, as applicable.
    (v) For each fugitive emission from a fugitive emissions components 
designated facility and each leak or defect for each cover and closed 
vent system inspection, you must maintain the records in paragraphs 
(c)(6)(v)(A) through (F) of this section.
    (A) The location of the fugitive emissions identified using a 
unique identifier for the source of the emissions and the type of 
fugitive emissions component.
    (B) The location of the emission or defect from a cover or closed 
vent system using a unique identifier for the source of the emission or 
defect.
    (C) If a defect of a closed vent system, cover, or control device 
is identified, a description of the defect.
    (D) The date of repair for each fugitive emission from a fugitive 
emissions components designated facility or each emission or defect for 
each cover and closed vent system.
    (E) Number and type of fugitive emission components and 
identification of each cover or closed vent system placed on delay of 
repair and an explanation for each delay of repair.
    (F) For each fugitive emission component placed on delay of repair 
for reason of replacement component unavailability, the operator must 
document: the date the component was added to the delay of repair list, 
the date the replacement fugitive component or part thereof was 
ordered, the anticipated component delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the component.
    (7) The date the investigative analysis was initiated, and the 
result of the investigative analysis conducted in accordance with Sec.  
60.5398c(b)(5)(vi) and (vii), as applicable.
    (8) Dates of implementation and completion of action(s) taken as a 
result of the investigative analysis and a description of the action(s) 
taken in accordance with Sec.  60.5398c(b)(5)(vi) and (vii), as 
applicable.
    (9) The information in paragraphs (c)(9)(i) through (vii) of this 
section if you are required to conduct OGI surveys in accordance with 
Sec.  60.5398c(b)(1)(i) or if you replace a periodic screening event 
with an OGI survey in accordance with Sec.  60.5398c(b)(1)(iv).
    (i) The date of the OGI survey.
    (ii) Location of each fugitive emission identified.
    (iii) Type of fugitive emissions component for which fugitive 
emissions were detected.
    (iv) The date of first attempt at repair of the fugitive emissions 
component(s).
    (v) The date of successful repair of the fugitive emissions 
component(s), including the resurvey to verify the repair.
    (vi) Identification of each fugitive emissions component placed on 
delay of repair and an explanation for each delay of repair.
    (vii) For each fugitive emission component placed on delay of 
repair for reason of replacement component unavailability, the operator 
must document: the date the component was added to the delay of repair 
list, the date the replacement fugitive component or part thereof was 
ordered, the anticipated component delivery date (including any 
estimated shipment or delivery date provided by the vendor), and the 
actual arrival date of the component.
    (10) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (11) All records required by the alternative approved in accordance 
with Sec.  60.5398b(d).
    (d) If you comply with the continuous monitoring system 
requirements of Sec.  60.5398c(c), you must submit the information in 
paragraphs (d)(1) through (6) of this section in the annual report 
required by Sec.  60.5420c(b)(3) through (10).
    (1) The start date and end date for each period where the emissions 
rate determined in accordance with Sec.  60.5398c(c)(6) exceeded one of 
the action levels determined in accordance with Sec.  60.5398c(c)(4). 
Include which action level was exceeded (the 7-day or 90-day rolling 
average), the numerical value of the action level, and the mass 
emission rate calculated by the continuous monitoring system in the 
report.
    (2) The date the investigative analysis was initiated, and the 
result of the investigative analysis conducted in accordance with Sec.  
60.5398c(c)(7), as applicable.
    (3) Dates of implementation and completion of action(s) taken to 
reduce the mass emission rate and a description of the action(s) taken 
in accordance with Sec.  60.5398c(c)(7), as applicable.
    (4) If there are no instances reported under paragraph (d)(1) of 
this section, report your numerical action levels and the highest 7-day 
rolling average and highest 90-day rolling average determined by your 
continuous monitoring system during the reporting period.
    (5) The start date for each instance where the 12-month rolling 
average operational downtime of the system exceeded 10 percent and the 
value of the 12-month rolling average operational downtime during the 
period. If there were no instances during the reporting period where 
the 12-month rolling average operational downtime of the system 
exceeded 10 percent, report the highest value of the 12-month rolling 
average operational downtime during the reporting period.
    (6) Any additional information regarding the performance of the 
continuous monitoring system as

[[Page 17212]]

specified by the Administrator, as part of the alternative test method 
approval described in Sec.  60.5398b(d).
    (e) If you comply with the continuous monitoring system 
requirements of Sec.  60.5398c(c), you must maintain the records in 
paragraphs (e)(1) through (15) of this section.
    (1) The monitoring plan required by Sec.  60.5398c(c)(2).
    (2) Date of commencement of continuous monitoring with your 
continuous monitoring system.
    (3) The detection threshold of the continuous monitoring system.
    (4) The results of checks for power and function in accordance with 
Sec.  60.5398c(c)(1)(ii).
    (5) The beginning and end of each period of operational downtime 
for the system.
    (6) Each rolling 12-month average operational downtime for the 
system, calculated in accordance with Sec.  60.5398c(c)(1)(ii)(D).
    (7) The 7-day rolling average and 90-day rolling average action 
levels for the site determined in accordance with Sec.  60.5398c(c)(4).
    (8) The information in paragraphs (e)(8)(i) through (v) of this 
section each time you establish site-specific baseline emissions in 
accordance with Sec.  60.5398c(c)(5).
    (i) Records of inspections of fugitive emissions components, 
covers, and closed vent systems required by Sec.  60.5398c(c)(5)(i), 
including the date of inspection, location of each emission or defect 
identified, date of successful repair of each fugitive emissions 
component, cover, or closed vent system.
    (ii) Records of inspections of control devices required by Sec.  
60.5398c(c)(5)(ii), including the date of the inspection and the 
results of the inspection.
    (iii) The start date and time and end date and time of any 
maintenance activities that occurred during the 30 operating day 
period.
    (iv) The site-level emission rate for each day during the 30 
operating day period.
    (v) The calculated site-specific baseline emission rate.
    (9) Each methane mass emission rate reading determined by the 
system.
    (10) Each daily, 7-day, and 90-day average mass emission rate which 
was determined in accordance with Sec.  60.5398c(c)(6). If you exceed 
the 90-day action level, you must also keep records of the 30-day 
average mass emission rate following completion of the initial actions 
to reduce the average mass emission rate, in accordance with Sec.  
60.5398c(c)(8)(i).
    (11) The results of each comparison of the emissions rate 
determined in accordance with Sec.  60.5398c(c)(6) to the action level 
determined in accordance with Sec.  60.5398c(c)(4).
    (12) The date the investigative analysis was initiated, and the 
result of the investigative analysis conducted in accordance with Sec.  
60.5398c(c)(7), as applicable.
    (13) Dates of implementation and completion of action(s) taken to 
reduce the mass emission rate below the action level and a description 
of the action(s) taken in accordance with Sec.  60.5398c(c)(7), as 
applicable.
    (14) Each mass emission rate reduction plan developed in accordance 
with Sec.  60.5398c(c)(8), as applicable. You must keep records of the 
actions taken in accordance with the plan and the date such actions are 
taken.
    (15) Any additional information regarding the performance of the 
continuous monitoring technology as specified by the Administrator, as 
part of the alternative test method approval described in Sec.  
60.5398b(d).


Sec.  60.5425c   What parts of the General Provisions apply to me?

    Table 4 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  60.1 through 60.19 apply to you.

Model Rule--Definitions


Sec.  60.5430c   What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein shall have 
the meaning given them in the Act or in subpart A of this part; and the 
following terms shall have the specific meanings given them.
    Access to electrical power means commercial line power is available 
onsite, with sufficient capacity to support the required power loading 
of onsite equipment, and which provides reliable and consistent power.
    Acid gas means a gas stream of hydrogen sulfide (H<INF>2</INF>S) 
and carbon dioxide (CO<INF>2</INF>) that has been separated from sour 
natural gas by a sweetening unit.
    Alaskan North Slope means the approximately 69,000 square-mile area 
extending from the Brooks Range to the Arctic Ocean.
    API Gravity means the weight per unit volume of hydrocarbon liquids 
as measured by a system recommended by the American Petroleum Institute 
(API) and is expressed in degrees.
    Artificial lift equipment means mechanical pumps including, but not 
limited to, rod pumps and electric submersible pumps used to flowback 
fluids from a well.
    Associated gas means the natural gas from wells operated primarily 
for oil production that is released from the liquid hydrocarbon during 
the initial stage of separation after the wellhead. Associated gas 
production begins at the startup of production after the flow back 
period ends. Gas from wildcat or delineation wells is not associated 
gas.
    Average aggregate detection threshold means:
    (1) For the purposes of Sec.  60.5398c, the average of all site-
level detection thresholds from a single deployment (e.g., a singular 
flight that surveys multiple well sites, centralized production 
facility, and/or compressor stations) of a technology; and
    (2) For the purposes of Sec.  60.5388c, the average of all site-
level detection thresholds from a single deployment in the same basin 
and field.
    Bleed rate means the rate in standard cubic feet per hour at which 
natural gas is continuously vented (bleeds) from a process controller.
    Capital expenditure means, as an alternative to the definition in 
Sec.  60.2, an expenditure for a physical or operational change to an 
existing facility that:
    (1) Exceeds P, the product of the facility's replacement cost, R, 
and an adjusted annual asset guideline repair allowance, A, as 
reflected by the following equation: P = R x A, where:
    (i) The adjusted annual asset guideline repair allowance, A, is the 
product of the percent of the replacement cost, Y, and the applicable 
basic annual asset guideline repair allowance, B, divided by 100 as 
reflected by the following equation: A = Y x (B / 100);
    (ii) The percent Y is determined from the following equation: Y = 
(CPI of date of construction/most recently available CPI of date of 
project), where the ``CPI-U, U.S. city average, all items'' must be 
used for each CPI value; and
    (iii) The applicable basic annual asset guideline repair allowance, 
B, is 4.5.
    (2) [Reserved]
    Centralized production facility means one or more storage vessels 
and all equipment at a single surface site used to gather, for the 
purpose of sale or processing to sell, crude oil, condensate, produced 
water, or intermediate hydrocarbon liquid from one or more offsite 
natural gas or oil production wells. This equipment includes, but is 
not limited to, equipment used for storage, separation, treating, 
dehydration, artificial lift, combustion, compression, pumping, 
metering, monitoring, and flowline. Process vessels and process tanks 
are not considered storage vessels or storage tanks. A centralized 
production facility is located upstream of the natural gas

[[Page 17213]]

processing plant or the crude oil pipeline breakout station and is a 
part of producing operations.
    Centrifugal compressor means any machine for raising the pressure 
of a natural gas by drawing in low pressure natural gas and discharging 
significantly higher-pressure natural gas by means of mechanical 
rotating vanes or impellers. Screw, sliding vane, and liquid ring 
compressors are not centrifugal compressors for the purposes of this 
subpart.
    Centrifugal compressor equipped with sour seal oil separator and 
capture system means a wet seal centrifugal compressor system which has 
an intermediate closed process that degasses most of the gas entrained 
in the sour seal oil and sends that gas to either another process or 
combustion device (i.e., degassed emissions are recovered). The de-gas 
emissions are routed back to a process or combustion device directly 
from the intermediate closed degassing process; after the intermediate 
closed process the oil is ultimately recycled for recirculation in the 
seals to the lube oil tank where any small amount of residual gas is 
released through a vent.
    Certifying official means one of the following:
    (1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business 
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized 
representative of such person if the representative is responsible for 
the overall operation of one or more manufacturing, production, or 
operating facilities with a designated facility subject to this subpart 
and either:
    (i) The facilities employ more than 250 persons or have gross 
annual sales or expenditures exceeding $25 million (in second quarter 
1980 dollars); or
    (ii) The Administrator is notified of such delegation of authority 
prior to the exercise of that authority. The Administrator reserves the 
right to evaluate such delegation;
    (2) For a partnership (including but not limited to general 
partnerships, limited partnerships, and limited liability partnerships) 
or sole proprietorship: A general partner or the proprietor, 
respectively. If a general partner is a corporation, the provisions of 
paragraph (1) of this definition apply;
    (3) For a municipality, State, Federal, or other public agency: 
Either a principal executive officer or ranking elected official. For 
the purposes of this part, a principal executive officer of a Federal 
agency includes the chief executive officer having responsibility for 
the overall operations of a principal geographic unit of the agency 
(e.g., a Regional Administrator of EPA); or
    (4) For designated facilities:
    (i) The designated representative in so far as actions, standards, 
requirements, or prohibitions under title IV of the CAA or the 
regulations promulgated thereunder are concerned; or
    (ii) The designated representative for any other purposes under 
this part.
    Closed vent system means a system that is not open to the 
atmosphere and that is composed of hard-piping, ductwork, connections, 
and, if necessary, flow-inducing devices that transport gas or vapor 
from a piece or pieces of equipment to a control device or back to a 
process.
    Coil tubing cleanout means the process where an operator runs a 
string of coil tubing to the packed proppant within a well and jets the 
well to dislodge the proppant and provide sufficient lift energy to 
flow it to the surface. Coil tubing cleanout includes mechanical 
methods to remove solids and/or debris from a wellbore.
    Collection system means any infrastructure that conveys gas or 
liquids from the well site to another location for treatment, storage, 
processing, recycling, disposal, or other handling.
    Completion combustion device means any ignition device, installed 
horizontally or vertically, used in exploration and production 
operations to combust otherwise vented emissions from completions. 
Completion combustion devices include pit flares.
    Compressor mode means the operational and pressurized status of a 
compressor. For both centrifugal compressors and reciprocating 
compressors, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
    Compressor station means any permanent combination of one or more 
compressors that move natural gas at increased pressure through 
gathering or transmission pipelines, or into or out of storage. This 
includes, but is not limited to, gathering and boosting stations and 
transmission compressor stations. The combination of one or more 
compressors located at a well site, centralized production facility, or 
an onshore natural gas processing plant, is not a compressor station 
for purposes of Sec.  60.5386c(e) and Sec.  60.5397c.
    Condensate means hydrocarbon liquid separated from natural gas that 
condenses due to changes in the temperature, pressure, or both, and 
remains liquid at standard conditions.
    Connector means flanged, screwed, or other joined fittings used to 
connect two pipe lines or a pipe line and a piece of process equipment 
or that close an opening in a pipe that could be connected to another 
pipe. Joined fittings welded completely around the circumference of the 
interface are not considered connectors for the purpose of this 
regulation.
    Continuous bleed means a continuous flow of pneumatic supply 
natural gas to a process controller.
    Crude oil and natural gas source category means:
    (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.
    Custody meter means the meter where natural gas or hydrocarbon 
liquids are measured for sales, transfers, and/or royalty 
determination.
    Custody meter assembly means an assembly of fugitive emissions 
components, including the custody meter, valves, flanges, and 
connectors necessary for the proper operation of the custody meter.
    Custody transfer means the transfer of crude oil or natural gas 
after processing and/or treatment in the producing operations, or from 
storage vessels or automatic transfer facilities or other such 
equipment, including product loading racks, to pipelines or any other 
forms of transportation.
    Dehydrator means a device in which an absorbent directly contacts a 
natural gas stream and absorbs water in a contact tower or adsorption 
column (absorber).
    Delineation well means a well drilled in order to determine the 
boundary of a field or producing reservoir.
    Deviation means any instance in which a designated source subject 
to this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, or work practice standard;
    (2) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any designated source required to 
obtain such a permit; or
    (3) Fails to meet any emission limit, operating limit, or work 
practice

[[Page 17214]]

standard of this subpart during startup, shutdown, or malfunction, 
regardless of whether or not such failure is permitted by this subpart.
    Distance piece means an open or enclosed casing through which the 
piston rod travels, separating the compressor cylinder from the 
crankcase.
    Double block and bleed system means two block valves connected in 
series with a bleed valve or line that can vent the line between the 
two block valves.
    Duct work means a conveyance system such as those commonly used for 
heating and ventilation systems. It is often made of sheet metal and 
often has sections connected by screw or crimping. Hard-piping is not 
ductwork.
    Emergency shutdown device means a device which functions 
exclusively to protect personnel and/or prevent physical damage to 
equipment by shutting down equipment or gas flow during unsafe 
conditions resulting from an unexpected event, such as a pipe break or 
fire. For the purposes of this subpart, an emergency shutdown device is 
not used for routine control of operating conditions.
    Equipment, as used in the standards and requirements of this 
subpart relative to the process unit equipment designated facility at 
onshore natural gas processing plants, means each pump, pressure relief 
device, open-ended valve or line, valve, and flange or other connector 
that has the potential to emit methane and any device or system 
required by those same standards and requirements of this subpart.
    Field gas means feedstock gas entering the natural gas processing 
plant.
    Field gas gathering means the system used transport field gas from 
a field to the main pipeline in the area.
    First attempt at repair 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.
    Flare means a thermal oxidation system using an open (without 
enclosure) flame. Completion combustion devices as defined in this 
section are not considered flares.
    Flow line means a pipeline used to transport oil and/or gas to a 
processing facility or a mainline pipeline.
    Flowback means the process of allowing fluids and entrained solids 
to flow from a well following a treatment, either in preparation for a 
subsequent phase of treatment or in preparation for cleanup and 
returning the well to production. The term flowback also means the 
fluids and entrained solids that emerge from a well during the flowback 
process. The flowback period begins when material introduced into the 
well during the treatment returns to the surface following hydraulic 
fracturing or refracturing. The flowback period ends when either the 
well is shut in and permanently disconnected from the flowback 
equipment or at the startup of production. The flowback period includes 
the initial flowback stage and the separation flowback stage. 
Screenouts, coil tubing cleanouts, and plug drill-outs are not 
considered part of the flowback process.
    Fuel gas means gases that are combusted to derive useful work or 
heat.
    Fuel gas system means the offsite and onsite piping and flow and 
pressure control system that gathers gaseous stream(s) generated by 
onsite operations, may blend them with other sources of gas, and 
transports the gaseous stream for use as fuel gas in combustion devices 
or in-process combustion equipment, such as furnaces and gas turbines, 
either singly or in combination.
    Fugitive emissions means, for the purposes of Sec.  60.5397c, any 
indication of emissions observed from a fugitive emissions component 
using AVO, an indication of visible emissions observed from an OGI 
instrument, or an instrument reading of 500 ppmv or greater using 
Method 21 of appendix A-7 to this part.
    Fugitive emissions component means any component that has the 
potential to emit fugitive emissions of methane at a well site, 
centralized production facility, or compressor station, such as valves 
(including separator dump valves), connectors, pressure relief devices, 
open-ended lines, flanges, covers and closed vent systems not subject 
to Sec.  60.5411c, thief hatches or other openings on a storage vessel 
not subject to Sec.  60.5396c, compressors, instruments, meters, and 
yard piping.
    Gas to oil ratio (GOR) means the ratio of the volume of gas at 
standard temperature and pressure that is produced from a volume of oil 
when depressurized to standard temperature and pressure.
    Hard-piping means pipe or tubing that is manufactured and properly 
installed using good engineering judgment and standards such as ASME 
B31.3, Process Piping (available from the American Society of 
Mechanical Engineers, P.O. Box 2300, Fairfield, NJ 07007-2300).
    Hydraulic fracturing means the process of directing pressurized 
fluids containing any combination of water, proppant, and any added 
chemicals to penetrate tight formations, such as shale or coal 
formations, that subsequently require high rate, extended flowback to 
expel fracture fluids and solids during completions.
    Hydraulic refracturing means conducting a subsequent hydraulic 
fracturing operation at a well that has previously undergone a 
hydraulic fracturing operation.
    In gas/vapor service means that the piece of equipment contains 
process fluid that is in the gaseous state at operating conditions.
    In heavy liquid service means that the piece of equipment is not in 
gas/vapor service or in light liquid service.
    In light liquid service means that the piece of equipment contains 
a liquid that meets the conditions specified in Sec.  60.5402c(d)(2) or 
Sec.  60.5406c.
    In vacuum service means that equipment is operating at an internal 
pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient 
pressure.
    In wet gas service means that a compressor or piece of equipment 
contains or contacts the field gas before the extraction step at a gas 
processing plant process unit.
    Initial calibration value, as used in the standards and 
requirements of this subpart relative to the process unit equipment 
designated facility at onshore natural gas processing plants, means the 
concentration measured during the initial calibration at the beginning 
of each day required in Sec.  60.5403c, or the most recent calibration 
if the instrument is recalibrated during the day (i.e., the calibration 
is adjusted) after a calibration drift assessment.
    Initial flowback stage means the period during a well completion 
operation which begins at the onset of flowback and ends at the 
separation flowback stage.
    Intermediate hydrocarbon liquid means any naturally occurring, 
unrefined petroleum liquid.
    Intermittent vent natural gas-driven process controller means a 
process controller that is not designed to have a continuous bleed rate 
but is instead designed to only release natural gas to the atmosphere 
as part of the actuation cycle.
    Liquefied natural gas unit means a unit used to cool natural gas to 
the point at which it is condensed into a liquid which is colorless, 
odorless, non-corrosive and non-toxic.
    Liquid collection system means tankage and/or lines at a well site 
to contain liquids from one or more wells or to convey liquids to 
another site.

[[Page 17215]]

    Liquids dripping means any visible leakage from the seal, including 
spraying, misting, clouding, and ice formation.
    Liquids unloading means the unloading of liquids that have 
accumulated over time in gas wells, which are impeding or halting 
production. Routine well maintenance activities, including workovers, 
screenouts, coil tubing cleanouts, or any other activity that requires 
a rig or other machinery are not considered liquids unloading.
    Local distribution company (LDC) custody transfer station means a 
metering station where the LDC receives a natural gas supply from an 
upstream supplier, which may be an interstate transmission pipeline or 
a local natural gas producer, for delivery to customers through the 
LDC's intrastate transmission or distribution lines.
    Low-e valve means a valve (including its specific packing assembly) 
for which the manufacturer has issued a written warranty or performance 
guarantee that it will not emit fugitives at greater than 100 ppm in 
the first five years. A valve may qualify as a low-e valve if it is as 
an extension of another valve that has qualified as a low-e valve.
    Low-e packing means a valve packing product for which the 
manufacturer has issued a written warranty or performance guarantee 
that it will not emit fugitives at greater than 100 ppm in the first 
five years. Low-e injectable packing is a type of low-e packing product 
for which the manufacturer has also issued a written warranty or 
performance guarantee and that can be injected into a valve during a 
``drill-and-tap'' repair of the valve.
    Major production and processing equipment means reciprocating or 
centrifugal compressors, glycol dehydrators, heater/treaters, 
separators, control devices, natural gas-driven process controllers, 
natural gas-driven pumps, and storage vessels or tank batteries 
collecting crude oil, condensate, intermediate hydrocarbon liquids, or 
produced water, for the purpose of determining whether a well site is a 
wellhead only well site.
    Maximum average daily throughput means the following:
    (1) The earliest calculation of daily average throughput, 
determined as described in paragraph (2) or (3) of this definition, to 
a tank battery over the days that production is routed to that tank 
battery during the 30-day PTE evaluation period employing generally 
accepted methods specified in Sec.  60.5386c(e)(2).
    (2) If throughput to the tank battery is measured on a daily basis 
(e.g., via level gauge automation or daily manual gauging), the maximum 
average daily throughput is the average of all daily throughputs for 
days on which throughput was routed to the tank battery during the 30-
day evaluation period; or
    (3) If throughput to the tank battery is not measured on a daily 
basis (e.g., via manual gauging at the start and end of loadouts), the 
maximum average daily throughput is the highest, of the average daily 
throughputs, determined for any production period to that tank battery 
during the 30-day evaluation period, as determined by averaging total 
throughput to that tank battery over each production period. A 
production period begins when production begins to be routed to a tank 
battery and ends either when throughput is routed away from that tank 
battery or when a loadout occurs from that tank battery, whichever 
happens first. Regardless of the determination methodology, operators 
must not include days during which throughput is not routed to the tank 
battery when calculating maximum average daily throughput for that tank 
battery.
    Multi-wellhead only well site means a well site that contains two 
or more wellheads and no major production and processing equipment.
    Natural gas-driven diaphragm pump means a positive displacement 
pump powered by pressurized natural gas that uses the reciprocating 
action of flexible diaphragms in conjunction with check valves to pump 
a fluid. A pump in which a fluid is displaced by a piston driven by a 
diaphragm is not considered a diaphragm pump for purposes of this 
subpart. A lean glycol circulation pump that relies on energy exchange 
with the rich glycol from the contactor is not considered a diaphragm 
pump.
    Natural gas-driven piston pump means a positive displacement pump 
powered by pressurized natural gas that moves and pressurizes fluid by 
using one or more reciprocating pistons. A pump in which a fluid is 
displaced by a piston driven by a diaphragm is considered a piston pump 
for purposes of this subpart. A lean glycol circulation pump that 
relies on energy exchange with the rich glycol from the contactor is 
not considered a piston pump.
    Natural gas-driven process controller means a process controller 
powered by pressurized natural gas.
    Natural gas liquids means the hydrocarbons, such as ethane, 
propane, butane, and pentane that are extracted from field gas.
    Natural gas processing plant (gas plant) means any processing site 
engaged in the extraction of natural gas liquids from field gas, 
fractionation of mixed natural gas liquids to natural gas products, or 
both. A Joule-Thompson valve, a dew point depression valve, or an 
isolated or standalone Joule-Thompson skid is not a natural gas 
processing plant.
    Natural gas transmission means the pipelines used for the long-
distance transport of natural gas (excluding processing). Specific 
equipment used in natural gas transmission includes the land, mains, 
valves, meters, boosters, regulators, storage vessels, dehydrators, 
compressors, and their driving units and appurtenances, and equipment 
used for transporting gas from a production plant, delivery point of 
purchased gas, gathering system, storage area, or other wholesale 
source of gas to one or more distribution area(s).
    No detectable emissions means, for the purposes of Sec. Sec.  
60.5401c and 60.5406c, that the equipment is operating with an 
instrument reading of less than 500 ppmv above background, as 
determined by Method 21 of appendix A-7 to this part.
    No identifiable emissions means, for the purposes of covers, closed 
vent systems, and self-contained natural gas-driven process controllers 
and as determined according to the provisions of Sec.  60.5416c, that 
no emissions are detected by AVO means when inspections are conducted 
by AVO; no emissions are imaged with an OGI camera when inspections are 
conducted with OGI; and equipment is operating with an instrument 
reading of less than 500 ppmv above background, as determined by Method 
21 of appendix A-7 to this part when inspections are conducted with 
Method 21.
    Nonfractionating plant means any gas plant that does not 
fractionate mixed natural gas liquids into natural gas products.
    Non-natural gas-driven process controller means an instrument that 
is actuated using other sources of power than pressurized natural gas; 
examples include solar, electric, and instrument air.
    Onshore means all facilities except those that are located in the 
territorial seas or on the outer continental shelf.
    Open-ended valve or line or open-ended vent line means any valves, 
except safety relief valves, having one side of the valve seat in 
contact with process fluid and one side open to the atmosphere, either 
directly or through open piping.
    Plug drill-out means the removal of a plug (or plugs) that was used 
to isolate different sections of the well.
    Process controller means an automated instrument used for

[[Page 17216]]

maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
    Pressure release means the emission of materials resulting from 
system pressure being greater than set pressure of the pressure relief 
device.
    Pressure vessel means a storage vessel that is used to store 
liquids or gases and is designed not to vent to the atmosphere as a 
result of compression of the vapor headspace in the pressure vessel 
during filling of the pressure vessel to its design capacity.
    Pressurized mode means when the compressor contains natural gas 
that is maintained at a pressure higher than the atmospheric pressure.
    Process improvement means routine changes made for safety and 
occupational health requirements, for energy savings, for better 
utility, for ease of maintenance and operation, for correction of 
design deficiencies, for bottleneck removal, for changing product 
requirements, or for environmental control.
    Process unit means components assembled for the extraction of 
natural gas liquids from field gas, the fractionation of the liquids 
into natural gas products, or other operations associated with the 
processing of natural gas products. A process unit can operate 
independently if supplied with sufficient feed or raw materials and 
sufficient storage facilities for the products.
    Process unit shutdown means a work practice or operational 
procedure that stops production from a process unit or part of a 
process unit during which it is technically feasible to clear process 
material from a process unit or part of a process unit consistent with 
safety constraints and during which repairs can be accomplished. The 
following are not considered process unit shutdowns:
    (1) An unscheduled work practice or operational procedure that 
stops production from a process unit or part of a process unit for less 
than 24 hours.
    (2) An unscheduled work practice or operational procedure that 
would stop production from a process unit or part of a process unit for 
a shorter period of time than would be required to clear the process 
unit or part of the process unit of materials and start up the unit, 
and would result in greater emissions than delay of repair of leaking 
components until the next scheduled process unit shutdown.
    (3) The use of spare equipment and technically feasible bypassing 
of equipment without stopping production.
    Produced water means water that is extracted from the earth from an 
oil or natural gas production well, or that is separated from crude 
oil, condensate, or natural gas after extraction.
    Qualified Professional Engineer means an individual who is licensed 
by a state as a Professional Engineer to practice one or more 
disciplines of engineering and who is qualified by education, technical 
knowledge and experience to make the specific technical certifications 
required under this subpart. Professional engineers making these 
certifications must be currently licensed in at least one state in 
which the certifying official is located.
    Quarter means a 3-month period. For purposes of standards for 
process unit equipment designated facilities at onshore natural gas 
processing plants, the first quarter concludes on the last day of the 
last full month during the 180 days following initial startup.
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process gas by positive displacement, employing 
linear movement of the driveshaft.
    Reciprocating compressor rod packing means a series of flexible 
rings in machined metal cups that fit around the reciprocating 
compressor piston rod to create a seal limiting the amount of 
compressed natural gas that escapes to the atmosphere, or other 
mechanism that provides the same function.
    Recovered gas means gas recovered through the separation process 
during flowback.
    Recovered liquids means any crude oil, condensate or produced water 
recovered through the separation process during flowback.
    Reduced emissions completion means a well completion following 
fracturing or refracturing where gas flowback that is otherwise vented 
is captured, cleaned, and 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 other useful purpose that a purchased fuel or 
raw material would serve, with no direct release to the atmosphere.
    Reduced sulfur compounds means H<INF>2</INF>S, carbonyl sulfide 
(COS), and carbon disulfide (CS<INF>2</INF>).
    Removed from service means that a storage vessel designated 
facility has been physically isolated and disconnected from the process 
for a purpose other than maintenance in accordance with Sec.  
60.5396c(c)(1).
    Repaired means the following:
    (1) For the purposes of fugitive emissions components designated 
facilities, that fugitive emissions components are adjusted, replaced, 
or otherwise altered, in order to eliminate fugitive emissions as 
defined in Sec.  60.5397c and resurveyed as specified in Sec.  
60.5397c(h)(4) and it is verified that emissions from the fugitive 
emissions components are below the applicable fugitive emissions 
definition.
    (2) For the purposes of process unit equipment designated 
facilities, that equipment is adjusted, or otherwise altered, in order 
to eliminate a leak as defined in Sec. Sec.  60.5400c and 60.5401c and 
is re-monitored as specified in Sec.  60.5400c(b) and (b)(1) or Sec.  
60.5403c, respectively, to verify that emissions from the equipment are 
below the applicable leak definition. Pumps in light liquid service 
subject to Sec.  60.5400c(c)(2) or Sec.  60.5401c(b)(1)(ii) are not 
subject to re-monitoring.
    Replacement cost means the capital needed to purchase all the 
depreciable components in a facility.
    Returned to service means that a storage vessel designated facility 
that was removed from service has been:
    (1) Reconnected to the original source of liquids or has been used 
to replace any storage vessel designated facility; or
    (2) Installed in any location covered by this subpart and 
introduced with crude oil, condensate, intermediate hydrocarbon liquids 
or produced water.
    Routed to a process or route to a process means the emissions are 
conveyed via a closed vent system to any 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 and/or transformed by chemical reaction into 
materials that are not regulated materials and/or incorporated into a 
product; and/or recovered.
    Salable quality gas means natural gas that meets the flow line or 
collection system operator specifications, regardless of whether such 
gas is sold.
    Screenout means an attempt to clear proppant from the wellbore to 
dislodge the proppant out of the well.
    Self-contained process controller means a natural gas-driven 
process controller that releases gas into the downstream piping and not 
to the atmosphere, resulting in zero methane emissions.
    Self-contained wet seal centrifugal compressor means:
    (1) A wet seal centrifugal 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) or 
which has an intermediate closed process that degasses most of the gas 
entrained in the seal oil and sends that gas to another process. The 
de-gas

[[Page 17217]]

emissions are routed back to suction or process directly from the 
closed or intermediate closed degassing process; after the closed or 
intermediate closed degassing process the oil is ultimately recycled 
for recirculation in the seals to the lube oil tank where any small 
amount of residual gas is released through a vent.
    (2) A wet seal centrifugal compressor equipped with mechanical wet 
seals, where (1) a differential pressure is maintained on the system 
and there is no off gassing of the lube oil, and (2) the mechanical 
seal is integrated into the compressor housing.
    Sensor means a device that measures a physical quantity or the 
change in a physical quantity such as temperature, pressure, flow rate, 
pH, or liquid level.
    Separation flowback stage means the period during a well completion 
operation when it is technically feasible for a separator to function. 
The separation flowback stage ends either at the startup of production, 
or when the well is shut in and permanently disconnected from the 
flowback equipment.
    Separator dump valve means, for purposes of the fugitive emission 
standards in Sec. Sec.  60.5397c and 60.5398c, a liquid-control valve 
in a separator that controls the liquid level within the separator 
vessel.
    Single wellhead only well site means a wellhead only well site that 
contains only one wellhead and no major production and processing 
equipment.
    Small well site means, for purposes of the fugitive emissions 
standards in Sec. Sec.  60.5397c and 60.5398c, 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. Small well sites cannot include any controlled storage vessels 
(or controlled tank batteries), control devices, or natural gas-driven 
process controllers, or natural gas-driven pumps.
    Startup of production means the beginning of initial flow following 
the end of flowback when there is continuous recovery of salable 
quality gas and separation and recovery of any crude oil, condensate, 
or produced water, except as otherwise provided in this definition. For 
the purposes of the fugitive monitoring requirements of Sec.  60.5397c, 
startup of production means the beginning of the continuous recovery of 
salable quality gas and separation and recovery of any crude oil, 
condensate, or produced water.
    Storage vessel means a tank or other vessel that contains an 
accumulation of crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water, and that is constructed primarily of 
nonearthen materials (such as wood, concrete, steel, fiberglass, or 
plastic) which provide structural support. A well completion vessel 
that receives recovered liquids from a well after startup of production 
following flowback for a period which exceeds 60 days is considered a 
storage vessel under this subpart. A tank or other vessel shall not be 
considered a storage vessel if it has been removed from service in 
accordance with the requirements of Sec.  60.5396c(c)(1) until such 
time as such tank or other vessel has been returned to service. For the 
purposes of this subpart, the following are not considered storage 
vessels:
    (1) Vessels that are skid-mounted or permanently attached to 
something that is mobile (such as trucks, railcars, barges or ships), 
and are intended to be located at a site for less than 180 consecutive 
days. If you do not keep or are not able to produce records, as 
required by Sec.  60.5420c(c)(4)(iv), showing that the vessel has been 
located at a site for less than 180 consecutive days, the vessel 
described herein is considered to be a storage vessel from the date the 
original vessel was first located at the site. This exclusion does not 
apply to a well completion vessel as described above.
    (2) Process vessels such as surge control vessels, bottoms 
receivers or knockout vessels.
    (3) Pressure vessels designed to operate in excess of 204.9 
kilopascals and without emissions to the atmosphere.
    Sulfur production rate means the rate of liquid sulfur accumulation 
from the sulfur recovery unit.
    Sulfur recovery unit means a process device that recovers element 
sulfur from acid gas.
    Surface site means any combination of one or more graded pad sites, 
gravel pad sites, foundations, platforms, or the immediate physical 
location upon which equipment is physically affixed.
    Sweetening unit means a process device that removes hydrogen 
sulfide and/or carbon dioxide from the sour natural gas stream.
    Tank battery means a group of all storage vessels that are 
manifolded together for liquid transfer. A tank battery may consist of 
a single storage vessel if only one storage vessel is present.
    Total Reduced Sulfur (TRS) means the sum of the sulfur compounds 
hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl 
disulfide as measured by Method 16 of appendix A-6 to this part.
    Total SO2 equivalents means the sum of volumetric or mass 
concentrations of the sulfur compounds obtained by adding the quantity 
existing as SO<INF>2</INF> to the quantity of SO<INF>2</INF> that would 
be obtained if all reduced sulfur compounds were converted to 
SO<INF>2</INF> (ppmv or kg/dscm (lb/dscf)).
    UIC Class I oilfield disposal well means a well with a UIC Class I 
permit that meets the definition in 40 CFR 144.6(a)(2) and receives 
eligible fluids from oil and natural gas exploration and production 
operations.
    UIC Class II oilfield disposal well means a well with a UIC Class 
II permit where wastewater resulting from oil and natural gas 
production operations is injected into underground porous rock 
formations not productive of oil or gas, and sealed above and below by 
unbroken, impermeable strata.
    Underground storage vessel means a storage vessel stored below 
ground.
    Well means a hole drilled for the purpose of producing oil or 
natural gas, or a well into which fluids are injected.
    Well completion means the process that allows for the flowback of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and tests the reservoir flow characteristics, which 
may vent produced hydrocarbons to the atmosphere via an open pit or 
tank.
    Well completion operation means any well completion with hydraulic 
fracturing or refracturing occurring at a well completion designated 
facility.
    Well completion vessel means a vessel that contains flowback during 
a well completion operation following hydraulic fracturing or 
refracturing. A well completion vessel may be a lined earthen pit, a 
tank or other vessel that is skid-mounted or portable. A well 
completion vessel that receives recovered liquids from a well after 
startup of production following flowback for a period which exceeds 60 
days is considered a storage vessel under this subpart.
    Well site means one or more surface sites that are constructed for 
the drilling and subsequent operation of any oil well, natural gas 
well, or injection well. For the purposes of the fugitive emissions 
standards at Sec.  60.5397c, a well site does not include:
    (1) UIC Class II oilfield disposal wells and disposal facilities;
    (2) UIC Class I oilfield disposal wells; and
    (3) The flange immediately upstream of the custody meter assembly 
and equipment, including fugitive emissions components, located 
downstream of this flange.

[[Page 17218]]

    Wellhead means the piping, casing, tubing and connected valves 
protruding above the earth's surface for an oil and/or natural gas 
well. The wellhead ends where the flow line connects to a wellhead 
valve. The wellhead does not include other equipment at the well site 
except for any conveyance through which gas is vented to the 
atmosphere.
    Wellhead only well site means, for the purposes of the fugitive 
emissions standards at Sec.  60.5397c and the standards in Sec.  
60.5398c, a well site that contains one or more wellheads and no major 
production and processing equipment.
    Wildcat well means a well outside known fields or the first well 
drilled in an oil or gas field where no other oil and gas production 
exists.
    Yard piping means hard-piping at a well site, centralized 
production facility, or compressor station that is not part of a closed 
vent system.


Sec. Sec.  60.5431c-60.5439c  [Reserved]

  Table 1 to Subpart OOOOc of Part 60--Designated Facility Presumptive
             Standards and Regulated Entity Compliance Dates
------------------------------------------------------------------------
                                Model rule presumptive  Regulated entity
      Designated facility          standards section    compliance dates
------------------------------------------------------------------------
Wells.........................  a. Gas wells liquids    36 months after
                                 unloading events--      the state plan
                                 Sec.   60.5390c.        submittal
                                b. Associated gas        deadline
                                 wells--Sec.             specified in
                                 60.5391c..              Sec.
                                                         60.5362c(c).
Centrifugal Compressors.......  Sec.   60.5392c.......
Reciprocating Compressors.....  Sec.   60.5393c.......
Process Controller............  Sec.   60.5394c.......
Pump..........................  Sec.   60.5395c.......
Storage Vessels...............  Sec.   60.5396c.......
Fugitive Emissions Components.  a. Primary standards--
                                 Sec.   60.5397c.
                                b. Alternative
                                 standards for
                                 fugitive emissions
                                 components and covers
                                 and closed vent
                                 systems--Sec.
                                 60.5398c.
Super Emitter Emissions Events  Sec.   60.5388c.......
Process Unit Equipment........  a. Onshore natural gas
                                 processing plants--
                                 Sec.   60.5400c.
                                b. Process unit
                                 equipment alternative
                                 standards--Sec.
                                 60.5401c.
                                c. Process unit
                                 equipment requirement
                                 exceptions--Sec.
                                 60.5401c.
------------------------------------------------------------------------


  Table 2 to Subpart OOOOc of Part 60--Alternative Technology Periodic
  Screening Frequency at Well Sites, Centralized Production Facilities,
and Compressor Stations Subject to AVO Inspections With Quarterly OGI or
                        EPA Method 21 Monitoring
------------------------------------------------------------------------
                                             Minimum detection threshold
        Minimum screening frequency           of screening technology *
                                                       (kg/hr)
------------------------------------------------------------------------
Quarterly..................................                          <=1
Bimonthly..................................                          <=2
Bimonthly + Annual OGI.....................                         <=10
Monthly....................................                          <=5
Monthly + Annual OGI.......................                         <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%.


  Table 3 to Subpart OOOOc of Part 60--Alternative Technology Periodic
 Screening Frequency at Well Sites and Centralized Production Facilities
    Subject to AVO Inspections and/or Semiannual OGI or EPA Method 21
                               Monitoring
------------------------------------------------------------------------
                                             Minimum detection threshold
        Minimum screening frequency           of screening technology *
                                                       (kg/hr)
------------------------------------------------------------------------
Semiannual.................................                          <=1
Triannual..................................                          <=2
Triannual + Annual OGI.....................                         <=10
Quarterly..................................                          <=5
Quarterly + Annual OGI.....................                         <=15
Bimonthly..................................                         <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%.


            Table 4 to Subpart OOOOc of Part 60--Applicability of General Provisions to Subpart OOOOc
----------------------------------------------------------------------------------------------------------------
 General provisions citation     Subject of citation        Applies to subpart?             Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1.................  General applicability of   Yes.....................
                               the General Provisions.
Sec.   60.2.................  Definitions..............  Yes.....................  Additional terms defined in
                                                                                    Sec.   60.5430c.
Sec.   60.3.................  Units and abbreviations..  Yes.....................

[[Page 17219]]

 
Sec.   60.4.................  Address..................  Yes.....................
Sec.   60.5.................  Determination of           Yes.....................
                               construction or
                               modification.
Sec.   60.6.................  Review of plans..........  Yes.....................
Sec.   60.7.................  Notification and record    Yes.....................  Except that Sec.   60.7 only
                               keeping.                                             applies as specified in Sec.
                                                                                     Sec.   60.5417c(c) and
                                                                                    60.5420c(a).
Sec.   60.8.................  Performance tests........  Yes.....................  Except that the format and
                                                                                    submittal of performance
                                                                                    test reports is described in
                                                                                    Sec.   60.5420c(b) and (d).
                                                                                    Performance testing is
                                                                                    required for control devices
                                                                                    used on storage vessels,
                                                                                    centrifugal compressors, and
                                                                                    pumps, except that
                                                                                    performance testing is not
                                                                                    required for a control
                                                                                    device used solely on
                                                                                    pump(s).
Sec.   60.9.................  Availability of            Yes.....................
                               information.
Sec.   60.10................  State authority..........  Yes.....................
Sec.   60.11................  Compliance with standards  No......................  Requirements are specified in
                               and maintenance                                      subpart OOOOc.
                               requirements.
Sec.   60.12................  Circumvention............  Yes.....................
Sec.   60.13................  Monitoring requirements..  Yes.....................  Continuous monitors are
                                                                                    required for storage
                                                                                    vessels.
Sec.   60.14................  Modification.............  Yes.....................  To the extent any provision
                                                                                    in Sec.   60.14 conflicts
                                                                                    with specific provisions in
                                                                                    subpart OOOOc, it is
                                                                                    superseded by subpart OOOOc
                                                                                    provisions.
Sec.   60.15................  Reconstruction...........  Yes.....................  Except that Sec.   60.15(d)
                                                                                    does not apply to wells
                                                                                    (i.e., well completions,
                                                                                    well liquids unloading,
                                                                                    associated gas wells),
                                                                                    process controllers, pumps,
                                                                                    centrifugal compressors,
                                                                                    reciprocating compressors,
                                                                                    storage vessels, or fugitive
                                                                                    emissions components
                                                                                    designated facilities.
Sec.   60.16................  Priority list............  Yes.....................
Sec.   60.17................  Incorporations by          Yes.....................
                               reference.
Sec.   60.18................  General control device     Yes.....................
                               and work practice
                               requirements.
Sec.   60.19................  General notification and   Yes.....................
                               reporting requirement.
----------------------------------------------------------------------------------------------------------------


0
34. Add appendix J and appendix K to part 60 to read as follows:

Appendix J to Part 60 [Reserved]

Appendix K to Part 60--Determination of Volatile Organic Compound and 
Greenhouse Gas Leaks Using Optical Gas Imaging

1.0 Scope and Application

    1.1 Analytes.

------------------------------------------------------------------------
                 Analytes                              CAS No.
------------------------------------------------------------------------
Volatile Organic Compounds (VOCs).........  No CAS number assigned.
Methane...................................  74-82-8.
Ethane....................................  74-84-0.
------------------------------------------------------------------------

    1.1.1 This protocol is applicable to the detection of VOCs, 
including hazardous air pollutants, and hydrocarbons, such as 
methane and ethane.
    1.2 Scope. This protocol covers surveys of process equipment 
using Optical Gas Imaging (OGI) cameras in sectors where the 
majority of constituents (>75 percent by volume) in the emissions 
streams have a response factor of at least 0.25 when compared to the 
response factor of propane and can be imaged by the equipment 
specified in Section 6.0. The specific component focus for the 
surveys is determined by the referencing subpart, and can include, 
but is not limited to, valves, flanges, connectors, pumps, 
compressors, open-ended lines, pressure relief devices, and seal 
systems.
    1.3 Applicability. This protocol is applicable to facilities 
when specified in a referencing subpart. This protocol is intended 
to help determine the presence and location of leaks and is not 
currently applicable for use in direct emission rate measurements 
from sources.

2.0 Summary

    2.1 A field portable infrared (IR) camera capable of imaging the 
target gas species is employed to survey process equipment and 
locate fugitive or leaking gas emissions. By restricting the amount 
of incoming thermal radiation to a small bandwidth corresponding to 
a region of interaction for the gas species of interest, the camera 
provides an image of an invisible gas to the camera operator. The 
camera type and manufacturer are not specified in this protocol, but 
the camera used must meet the specifications and performance 
criteria presented in Section 6. The keys to becoming proficient and 
maintaining leak detection proficiency using OGI cameras are proper 
camera operator training with sufficient field experience and 
conducting OGI surveys frequently throughout the year.

3.0 Definitions

    Ambient air temperature means the air temperature in the general 
location of the component being surveyed.
    Camera configuration means different ways of setting up an OGI 
camera that affect its detection capability. Examples of camera 
configurations that can be changed include the operating mode (e.g., 
standard versus high sensitivity or enhanced), the lens, the 
portability (e.g., handheld versus tripod), and the viewer (e.g., 
OGI camera screen versus an external device like a tablet).
    Delta temperature (delta-T or [Delta]T) means the difference in 
temperature between the emitted process gas temperature and the 
surrounding background temperature. It is an acceptable practice in 
the field to assume that the emitted process gas temperature is 
equal to the ambient air temperature.
    Dwell time means the minimum amount of time required to survey a 
scene in order to provide adequate probability of leak detection. 
The dwell time is the active time the operator is looking for 
potential leaks and does not begin until the scene is in focus and 
steady.
    Fugitive emission or leak means any emissions observed using OGI 
from components regulated by the referencing subpart.
    Imaging is the process of producing a visual representation of 
emissions that may otherwise be invisible to the naked eye.
    Monitoring survey means imaging equipment with an OGI camera at 
one site on one day. Changing the site being surveyed or changing 
the day of imaging constitutes a new monitoring survey.
    OGI camera operator is someone who has completed the training 
required in Section 10 and passed the final survey test in Section 
10.2.2.4.
    Operating envelope means the range of conditions (i.e., wind 
speed, delta-T, viewing distance) within which a survey must be 
conducted to achieve the quality objective.
    Optical gas imaging camera means any field portable 
instrumentation that makes

[[Page 17220]]

visible emissions that may otherwise be invisible to the naked eye.
    Persistent leak is any leak that is not intermittent in nature.
    Referencing subpart means a subpart in this part or in 40 CFR 
part 61, 62, 63, or 65 that requires the monitoring of regulated 
equipment for fugitive emissions or leaks, for which this protocol 
is referenced.
    Response factor means the OGI camera's response to a compound of 
interest relative to a reference compound at a concentration path-
length of 10,000 parts per million-meter. Response factors are 
specific to the OGI camera model and can be obtained from peer 
reviewed articles or may be developed according to procedures 
specified in Annex 1 of this appendix K.
    Senior OGI camera operator is a camera operator who has 
conducted OGI surveys for a minimum of 1400 survey hours over the 
entirety of his/her career, including at least 40 survey hours in 
the past 12 months, and has completed or developed the classroom 
camera operator training as defined in Section 10.2.1. Previous 12 
months means the 365-calendar days prior to the day of the activity 
that requires a senior OGI camera operator. The survey 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 his/her career and the 
past 12 months.
    Simple scene is defined as a scene that contains 10 or fewer 
components in the field of view.
    Survey hour is 60 minutes of observation conducted with an OGI 
camera. Survey hours do not include periods of time when the OGI 
camera operator is on a rest break. The 60 minutes do not need to be 
consecutive but are cumulative.

4.0 Interferences

    4.1 Interferences from atmospheric conditions can impact the 
operator's ability to detect gas leaks. It is recommended that 
conditions involving steam, fog, mist, rain, solar glint, high 
particulate matter concentrations, and extremely hot backgrounds are 
avoided for a survey of acceptable quality.

5.0 Safety

    5.1 Site Hazards. Prior to applying this protocol in the field, 
the potential hazards at the survey site should be considered; 
advance coordination with the site is critical to understand the 
conditions and applicable safety policies. Users should be aware of 
safety concerns with viewing equipment through a camera while 
walking around an industrial setting. Users should also be aware of 
hazards related to eye strain, eye fatigue, and mental fatigue that 
may occur from prolonged periods of viewing equipment with an OGI 
camera. This protocol does not address all of the safety concerns 
associated with its use. It is the responsibility of the user of 
this protocol to establish appropriate health and safety practices 
and determine the applicability of regulatory limitations prior to 
implementing this protocol.
    5.2 Hazardous Pollutants. Several of the compounds encountered 
over the course of implementing this protocol may be irritating or 
corrosive to tissues (e.g., heptane) or may be toxic (e.g., benzene, 
methyl alcohol, hydrogen sulfide). Nearly all are fire hazards. 
Chemical compounds in gaseous emissions should be determined from 
process knowledge of the source. Appropriate precautions can be 
found in reference documents, such as reference 13.1.

6.0 Equipment and Supplies

    6.1 An OGI camera model meeting the following specifications is 
required. This testing can be performed by the owner or operator, 
the camera manufacturer, or a third party. As required by Section 
8.1, this testing must be performed initially, prior to using the 
OGI camera to conduct surveys. The determination in Section 6.1.1 
must also be made any time the OGI camera will be used to survey 
components on equipment that was not previously included in 
monitoring surveys or whenever there are process changes that are 
expected to cause the gaseous emissions composition to change. The 
determination in Section 6.1.2 is only required initially and is 
required for each camera operating mode (e.g., standard versus high 
sensitivity or enhanced).
    6.1.1 The spectral range of infrared radiation measured by the 
OGI camera must overlap with a major absorption peak for the 
chemical target of interest, meaning the OGI camera must be 
sensitive with a response factor of at least 0.25 when compared to 
the response factor of propane for the majority of constituents (>75 
percent by volume) of the expected gaseous emissions composition.
    6.1.2 The OGI camera must be capable of detecting (or producing 
a detectable image of) methane emissions of 19 grams per hour (g/hr) 
and either n-butane emissions of 29 g/hr or propane emissions of 22 
g/hr at a viewing distance of 2.0 meters and a delta-T of 5.0 [deg]C 
in an environment of calm wind conditions around 1 meter per second 
(m/s) or less, unless the referencing subpart provides detection 
rates for a different compound(s) for that subpart.
    6.2 The following items are needed for the initial specification 
confirmation of each OGI camera model, as required by Sections 
6.1.2, and development of operating envelopes, as required by 
Section 8:
    6.2.1 Methane test gas, chemically pure grade (99.5 percent) or 
higher.
    6.2.2 n-Butane test gas or propane test gas, chemically pure 
grade (99 percent) or higher.
    6.2.3 Release orifice, \1/4\ inch (64 millimeter) inner 
diameter.
    6.2.4 Mass flow controller or rotameter, capable of controlling 
the gas emission rate within an accuracy of 5 percent and traceable 
to the International System of Units (SI) through an unbroken chain 
of comparisons, i.e., calibrations.
    6.2.5 An industrial fan, capable of adjusting the sustained 
nominal wind speeds at regular intervals, with the ability to 
maintain a spatially uniform set speed within 20 percent of the 
target wind speed over the area of detection.
    6.2.6 A meteorological station capable of providing 
representative data on ambient temperature, ambient pressure, 
relative humidity, and wind speed and direction at least once every 
hour. Follow the calibration and standardization requirements for 
meteorological measurements in EPA-454/B-08-002 (incorporated by 
reference, see Sec.  60.17). The equipment must meet the following 
minimum specifications:
    6.2.6.1 Ambient temperature readings accurate to at least 0.50 
[deg]C, with a resolution of 0.10 [deg]C or less, and a minimum 
range of -20 to 70 [deg]C.
    6.2.6.2 Ambient pressure readings accurate to at least 5.0 
millibar (mbar), with a resolution of 1.0 mbar or less, and a 
minimum range of 700 to 1100 mbar.
    6.2.6.3 Wind speed readings accurate to at least 1.0 m/s, with a 
resolution of 0.10 m/s or less, and a minimum range of 0.10 to 20 m/
s.
    6.2.6.4 Wind direction readings accurate to at least 5 degrees, 
with a resolution of 1 degree or less.
    6.2.6.5 Relative humidity readings accurate to at least 5.0 
percent, with a resolution of 0.50 percent or less, and a minimum 
range of 10 to 90 percent noncondensing.
    6.2.7 A temperature-controlled background large enough for 
viewing the emissions plume and capable of maintaining a uniform 
temperature. Uniform is defined as all points on the background 
deviating no more than 1.0 [deg]C from the average temperature of 
the background.
    6.2.8 T-type probe thermocouple and readout, accurate to at 1.0 
[deg]C and traceable to the SI through an unbroken chain of 
comparisons, i.e., calibrations, for measuring the test gas at or 
near the point of release.
    6.2.9 T-type surface skin thermocouple and readout, accurate to 
at 1.0 [deg]C and traceable to the SI through an unbroken chain of 
comparisons, i.e., calibrations, for measuring the background 
immediately behind the test gas.
    6.2.10 Device to measure the distance between the OGI camera and 
the release point (e.g., tape measure, laser measurement tool), 
accurate to at least 2.0 centimeters (cm), with a resolution of at 
least 1.0 cm and traceable to the SI through an unbroken chain of 
comparisons, i.e., calibrations.

7.0 Camera Calibration and Maintenance

    7.1 The camera does not require routine calibration for purposes 
of gas leak detection but may require calibration if it is used for 
thermography (such as with [Delta]T determination features). 
Operators should follow manufacturer recommendations regarding 
maintenance and calibration, as appropriate.

8.0 Camera Specification Confirmation and Development of the Operating 
Envelope

    8.1 Determine that the OGI camera meets the specifications in 
Section 6.1 prior to conducting surveys with the OGI camera. The 
determination in Section 6.1.1 must also be made any time the OGI 
camera will be used to survey components on equipment that was not 
previously included in monitoring surveys or whenever there are 
process changes that are expected to cause the gaseous emissions 
composition to

[[Page 17221]]

change. The determination in Section 6.1.2 is only required 
initially. The results of this determination must be documented.
    8.2 Field conditions such as the viewing distance to the 
component to be monitored, wind speed, ambient air temperature, and 
the background temperature all have the potential to impact the 
ability of the OGI camera operator to detect a leak. 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.
    8.3 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.
    8.3.1 The operating envelope is specific to each model of OGI 
camera. The operating envelope can be developed by the owner or 
operator, the camera manufacturer, or a third party. The operating 
envelope must be developed initially, prior to conducting surveys 
with the OGI camera. The operating envelope may be updated or 
expanded at any time, following the procedures in this section.
    8.3.2 The operating envelope must be confirmed for all potential 
configurations that could impact the detection limit, such as high 
sensitivity modes, available lenses, and handheld versus tripod. 
Conversely, separate operating envelopes may be developed for 
different configurations. If, in addition to or in lieu of the 
display on the camera itself, an external device (e.g., laptop, 
tablet) is intended to be used to visualize the leak in the field, 
the operating envelope must be developed while using the external 
device. If the external device will not be used at all times, use of 
the external device is considered a separate configuration, and the 
operating envelope testing must be performed for both 
configurations.
    8.4 Development of the operating envelope is to be performed 
using the test gas composition, flow rate, and orifice diameter 
described in Section 6.1.2, and must include the following 
variables:
    8.4.1 Delta-T, regulated through the use of a temperature-
controlled background encompassing approximately 50 percent of the 
field of view, with no potential for solar interference;
    8.4.2 Viewing distance from the OGI camera to the component 
being imaged; and
    8.4.3 Wind speed, controlled through the use of an industrial 
fan.
    8.5 Determine the operating envelope using the following 
procedure:
    8.5.1 Set up the methane test gas at a flow rate of 19 g/hr.
    8.5.2 For this flow rate, the ability of the OGI camera to 
produce an observable image is challenged by ranges of the variables 
in Sections 8.4.1 through 8.4.3.
    8.5.3 A panel of no less than 4 observers who have been trained 
using the OGI camera and who have a demonstrated capability of 
detecting gaseous leaks will observe the test gas release for each 
combination of delta-T, distance, and wind speed. A test emission is 
determined to be observed when at least 75 percent of the observers 
(i.e., 3 of the 4 observers) see the image.
    8.5.4 Repeat the procedures in Sections 8.5.2 and 8.5.3 using 
either an n-butane test gas at a flow rate of 29 g/hr or a propane 
test gas at a flow rate of 22 g/hr.
    8.5.5 The operating envelope to be used in the field for each 
OGI camera configuration tested is the more restrictive operating 
envelope developed between the two test gases.
    8.5.6 Repeat the procedures in Sections 8.5.1-8.5.5 for each 
camera configuration that will be used to conduct surveys in the 
field.
    8.6 The results of the testing to establish the operating 
envelope, including supporting videos, must be documented.
    8.7 If an operating envelope has not been developed for an OGI 
camera model or an OGI camera operator wants to expand an operating 
envelope to account for site-specific conditions, a daily field 
check for maximum viewing distance must be completed prior to 
conducting a monitoring survey. This daily field check for maximum 
viewing distance does not need to be performed if an OGI suvey will 
be conducted within an operating envelope developed according to 
Sections 8.3 through 8.6.
    8.7.1 A complete video record of the daily field check must be 
retained with the OGI survey records.
    8.7.2 Each OGI camera operator who will conduct the monitoring 
survey must complete their own daily field check for maximum viewing 
distance using the OGI camera they will use to complete the 
monitoring survey. The daily field check must be conducted for each 
camera configuration that will be used during the monitoring survey.
    8.7.3 The daily field check must be performed using the test gas 
composition and orifice diameter described in Section 6.1.2.
    8.7.4 The daily field check must be conducted first for methane 
at a flow rate of 19 g/hr and then for either n-butane at a flow 
rate of 29 g/hr or propane at a flow rate of 22 g/hr. You must use a 
flow meter with a minimum accuracy of 5 percent of the mass rate. 
The daily field check for the two gases must occur at the same 
delta-T and wind speed conditions.
    8.7.5 The OGI camera operator must determine the maximum 
distance from the gas release point at which the operator is able to 
visualize the gas release with the OGI camera. The OGI camera 
operator must document this distance, as well as the delta-T and the 
wind speed at the time of the daily field check and include this 
information with the OGI survey records.
    8.7.6 If the daily check results in different maximum viewing 
distances for methane and n-butane/propane, the maximum viewing 
distance for the day for the OGI camera operator will be the shorter 
of the two maximum viewing distances.
    8.7.7 If the delta-T in the field decreases below the delta-T 
that was recorded for the daily field check or if the wind speed 
increases above the wind speed recorded for the daily field check, 
the maximum viewing distance determination must be repeated for the 
new delta-T and wind speed conditions.
    8.7.8 If multiple camera configurations will be used during the 
monitoring survey, the OGI camera operator may use the shortest 
maximum viewing distance of any configuration for all the 
configurations that will be used during the survey, or the OGI 
camera operator may use a different maximum viewing distance for 
each configuration that will be used during the survey.

9.0 Conducting the Monitoring Survey

    Each site must 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. At a minimum, the monitoring 
plan must include the elements in this section.
    9.1 The monitoring plan must include a description of a daily 
verification check to be performed prior to imaging to confirm that 
the camera is operating properly. This verification must consist of 
the following at a minimum:
    9.1.1 Confirm that the OGI camera software loads successfully 
and does not display any error messages upon startup;
    9.1.2 Confirm that the OGI camera focuses properly at the 
shortest and longest distances that will be imaged;
    9.1.3 Confirm that the OGI camera produces a live IR image using 
a known emissions source, such as a butane lighter or a propane 
cylinder;
    9.1.4 Confirm that the OGI camera can perform the delta-T check 
function as expected if this function will be used to meet the 
requirement in Section 9.2.3.
    9.2 The monitoring plan must include a procedure for ensuring 
that the monitoring survey is performed only when conditions in the 
field are within the operating envelope established in Section 8 or 
the conditions established by the daily field check in Section 8.7. 
This procedure must include the following:
    9.2.1 If the OGI camera operator will use an operating envelope 
established under Section 8, a description of how the viewing 
distance from the surveyed components, the wind speed, and the 
delta-T will be monitored and how the operator will deal with 
changes in site conditions during the survey to ensure that the 
monitoring survey is conducted within the limits of the operating 
envelope;
    9.2.2 If the OGI camera operator performs a daily field check 
according to Section 8.7, a description of how the OGI camera 
operator will monitor viewing distance to ensure the viewing 
distance is less than the daily maximum viewing distance and how the 
OGI camera operator will monitor the delta-T and wind speed to 
ensure the delta-T remains above and the wind speed remains below 
those that occurred during the daily field check;
    9.2.3 Description of 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;
    9.2.4 Description of how the operator will recognize the 
presence of and deal with potential interferences and/or adverse 
monitoring conditions, such as steam, fog,

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mist, rain, solar glint, extremely high concentrations of 
particulate matter, and hot temperature backgrounds.
    9.3 The site must conduct monitoring surveys using a methodology 
that ensures that all the components regulated by the referencing 
subpart within the unit or area are monitored. This must be achieved 
using one of the following three approaches or a combination of 
these approaches. The approach(es) chosen and how the approach(es) 
will be implemented must be described in the monitoring plan.
    9.3.1 Use of a route map or a map with designated observation 
locations. The map must be included as part of the monitoring plan, 
with a predetermined sequence of process unit monitoring (such as 
directional arrows along the monitoring path) depicted or designated 
observation locations clearly marked.
    9.3.2 Use of visual cues. The facility must develop visual cues 
(e.g., tags, streamers, or color-coded pipes) to ensure that all 
components regulated by the referencing subpart were monitored. The 
monitoring plan must describe what visual cue method is used and how 
it will be used to ensure all components are monitored during the 
survey.
    9.3.3 Use of global positioning system (GPS) route tracing. The 
facility must document the path taken during the survey by capturing 
GPS coordinates along the survey path, along with date and time 
stamps. These locations should be identified by latitude and 
longitude coordinates in decimal degrees to an accuracy and 
precision of at least five decimals of a degree using the North 
American Datum of 1983. GPS coordinates must be recorded frequently 
enough to document that all components regulated by the referencing 
subpart were monitored. The monitoring plan must describe how often 
GPS coordinates will be recorded and how the route tracing will 
ensure all components regulated by the referencing subpart are 
monitored.
    9.4 The monitoring plan must include a procedure that describes 
how components will be viewed with the OGI camera.
    9.4.1 Components must be imaged from at least two different 
angles.
    9.4.2 For a simple scene, which is a scene that contains 10 or 
fewer components in the field of view, the OGI camera operator must 
have a minimum dwell time on each angle of 10 seconds per scene 
before changing the angle, distance, or focus and dwelling again.
    9.4.3 For scenes other than simple scenes, the operator must 
divide the scene into manageable subsections. The OGI camera 
operator must have a minimum dwell time of 2 seconds per component 
in the field of view for each angle.
    9.4.4 It may be necessary to reduce distance or change angles in 
order to reduce the number of components in the field of view. An 
OGI camera operator may choose to reduce the distance from 
components in order to create simple scenes.
    9.4.5 The required dwell times stated in this section are 
minimum dwell times. Additional dwell time may be necessary to 
assess whether each monitored component is leaking or not leaking. 
OGI camera operators should use training and knowledge of 
environmental conditions and component configurations to increase 
dwell time where appropriate.
    9.4.6 The dwell time is the time that the OGI camera is in a 
particular operating mode and the scene is in focus and held steady 
such that an OGI camera operator is able to monitor for leaks. 
Changing OGI camera operating modes or viewing angles requires the 
OGI camera operator to restart the dwell time.
    9.4.7 The procedure must discuss changes, if necessary, to the 
imaging mode of the OGI camera that are appropriate to ensure that 
leaks from all components regulated by the referencing subpart can 
be imaged.
    9.5 The monitoring plan must include a plan for avoiding camera 
operator fatigue, as physical, mental, and eye fatigue are concerns 
with continuous field operation of OGI cameras. The OGI camera 
operator should not survey continuously for a period of more than 30 
minutes without taking a rest break. Taking a rest break between 
surveys of process units may satisfy this requirement; however, for 
process units or complex scenes requiring continuous survey periods 
of more than 30 minutes, the operator must take a break of at least 
5 minutes after every 30 minutes of surveying. Operators can 
complete tasks related to the monitoring survey, such as 
documentation, during the 5-minute rest break, so long as the 
operator is not actively imaging components.
    Note: If continuous surveying is desired for extended time 
periods, two camera operators can alternate between surveying and 
taking breaks.
    9.6 The monitoring plan must include a procedure for documenting 
monitoring surveys. The information documented must include:
    9.6.1 The name of the facility, date, and approximate start and 
end times for each monitoring survey.
    9.6.2 The weather conditions, including ambient temperature, 
wind speed, relative humidity, and sky conditions at the start and 
end of each monitoring survey. For monitoring surveys conducted for 
more than four hours, record the weather conditions every two hours.
    9.7 The site must have a procedure for documenting fugitive 
emissions or leaks found during the monitoring survey.
    9.7.1 If a leak is found, capture either a short video clip or 
photograph of the component associated with the leak. If the leak is 
not immediately repaired, the leaking component must be tagged for 
repair. The date, time, location of the leak, and an identification 
of the component associated with the leak must be recorded and 
stored with the OGI survey records. A full recording of the survey 
will suffice for this requirement.
    9.7.2 If no emissions are found, no recorded footage is required 
to demonstrate that the component was not leaking.
    9.8 The monitoring plan must include a quality assurance (QA) 
verification video for each OGI operator at least once each 
monitoring day. The QA verification video must be a minimum of 5 
minutes long and document the procedures the operator uses to survey 
(e.g., dwell times, angles, distances, backgrounds) and the camera 
configuration.
    9.9 The monitoring plan must describe the process that will be 
used to ensure the validity of the monitoring data as detailed in 
Section 11.

10.0 Camera Operator Training

    10.1 The facility or company performing the OGI surveys must 
have a training plan which ensures and monitors the proficiency of 
the camera operators. Training should include classroom instruction 
and field training 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. 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.
    10.2 Prior to conducting monitoring surveys, camera operators 
must complete initial training and demonstrate proficiency with the 
OGI camera and any external devices to be utilized for detecting a 
potential leak.
    10.2.1 At a minimum, the training plan must include the 
following classroom training elements as part of the initial 
training. Classroom training can be conducted at a physical 
location, remotely, or online.
    10.2.1.1 Key fundamental concepts of the OGI camera technology, 
such as the types of images the camera is capable of visualizing and 
the technology basis (theory) behind this capability.
    10.2.1.2 Parameters that can affect image detection (e.g., wind 
speed, temperature, distance, background, and potential 
interferences).
    10.2.1.3 Description of the components to be surveyed and 
example imagery of the various types of leaks that can be expected.
    10.2.1.4 Operating and maintenance instructions for the OGI 
camera used at the facility.
    10.2.1.5 Procedures for performing the monitoring survey 
according to the monitoring plan, including the daily verification 
check; how to ensure the monitoring survey is performed only when 
the conditions in the field are within the established operating 
envelope; the number of angles a component or set of components 
should be imaged from; the minimum dwell time for a scene before 
changing the angle, distance, and/or focus; how to improve the 
background visualization; the procedure for ensuring that all 
components regulated by the referencing subpart are visualized; and 
required rest breaks.
    10.2.1.6 Recordkeeping requirements.
    10.2.1.7 Common mistakes and best practices.
    10.2.1.8 Discussion of the regulatory requirements related to 
leak detection that are relevant to the facility's OGI monitoring 
efforts.
    10.2.2 At a minimum, the training plan must include the 
following field training elements as part of the initial training:
    10.2.2.1 A minimum of 3 survey hours with OGI where trainees 
observe the techniques and methods of a senior OGI

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camera operator (see definition in Section 3.0) who reinforces the 
classroom training elements.
    10.2.2.2 A minimum of 12 survey hours with OGI where the trainee 
performs the initial OGI survey with a senior OGI camera operator 
verifying the results by conducting a side-by-side comparative 
survey and providing instruction/correction where necessary.
    10.2.2.3 A minimum of 15 survey hours with OGI where the trainee 
performs monitoring surveys independently with a senior OGI camera 
operator trainer present and the senior OGI camera operator 
providing oversight and instruction/correction to the trainee where 
necessary.
    10.2.2.4 A final monitoring survey test where the trainee 
conducts an OGI survey of at least 2 suvey hours and a senior OGI 
camera operator follows behind with a second camera to confirm the 
OGI survey results. If there are 10 or more leaks identified by the 
senior OGI operator, the trainee must achieve no more 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.
    10.2.2.5 If the trainee doesn't pass the monitoring survey test 
in Section 10.2.2.4, the senior OGI operator must discuss the 
reasons for the failure with the trainee and provide instruction/
correction on improving the trainee's performance. Following the 
discussion with the senior OGI operator, the trainee may repeat the 
test in Section 10.2.2.4.
    10.3 All OGI camera operators must attend a biennial classroom 
training refresher. This refresher can be shorter in duration than 
the initial classroom training but must cover all the salient points 
necessary to operate the camera (e.g., performing surveys according 
to the monitoring plan, best practices, discussion of lessons 
learned). Refresher training can be conducted at a physical 
location, remotely, or online.
    10.4 Performance audits for all OGI camera operators must occur 
on a semiannual basis with at least three months between two 
consecutive audits. Performance audits must be conducted according 
to one of the following procedures:
    10.4.1 Performance audit by comparative monitoring. Comparative 
monitoring in near real-time is where a senior OGI camera operator 
reviews the performance of the employee being audited by performing 
an independent monitoring survey.
    10.4.1.1 Following a survey conducted by the camera operator 
being audited, the senior OGI camera operator will conduct a survey 
of at least 2 survey hours in the same area to ensure that no 
persistent leaks were missed.
    10.4.1.2 If there are 10 or more leaks identified by the senior 
OGI operator, the camera operator being audited must achieve no more 
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. If the camera operator being audited does not achieve this 
benchmark, then the camera operator being audited will need to be 
retrained as outlined in Section 10.4.3.
    10.4.2 Performance audit by video review. The camera operator 
being audited must submit unedited and uncut video footage of their 
OGI survey technique to a senior OGI camera operator for review.
    10.4.2.1 The videos must contain at least 2 survey hours of 
survey footage. If a single monitoring survey is less than 2 survey 
hours, footage from multiple monitoring surveys may be submitted; 
however, all videos necessary to cover a 2-hour period must be 
recorded and submitted for review. The senior OGI camera operator 
will review the survey technique of the camera operator being 
audited, as well as look for any missed leaks.
    10.4.2.2 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 as outlined in Section 10.4.3. Additionally, if 
there are 10 or more leaks identified by the senior OGI operator, 
the camera operator being audited must achieve no more 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. 
If the camera operator being audited does not achieve this 
benchmark, then the camera operator being audited will need to be 
retrained as outlined in Section 10.4.3.
    10.4.3 At a minimum, retraining must consist of the following 
elements:
    10.4.3.1 A discussion of the reasons for the failure with the 
OGI operator being audited and techniques to improve performance.
    10.4.3.2 A minimum of 8 survey hours with OGI where the trainee 
performs the initial OGI survey with a senior OGI camera operator 
verifying the results by conducting a side-by-side comparative 
survey and providing instruction/correction where necessary.
    10.4.3.3 A minimum of 8 survey hours with OGI where the trainee 
performs the survey independently with the senior OGI camera 
operator trainer present and the senior OGI camera operator provides 
oversight and instruction/correction to the trainee where necessary.
    10.4.3.4 The audited camera operator must perform a final 
monitoring survey test as described in Section 10.2.2.4 and meet the 
requirements in Section 10.2.2.4 to be recertified.
    10.4.4 If an OGI operator requires retraining in two consecutive 
semiannual audits, the OGI operator must repeat the initial training 
requirements in Section 10.2.
    10.4.5 If a camera operator is not scheduled to perform an OGI 
survey during a semiannual period, then the audit must occur with 
the next scheduled monitoring survey.
    10.5 If an OGI camera operator has not conducted a monitoring 
survey in over 12 months, then the operator must complete the 
retraining requirements in Section 10.4.3 prior to conducting 
surveys. If an OGI camera operator has not conducted a monitoring 
survey in over 24 months, then the operator must complete the 
biennial classroom training in Section 10.3 and complete the 
retraining requirements in Section 10.4.3 prior to conducting 
surveys.
    10.6 Previous experience with OGI camera operation can be 
substituted for some of the initial training requirements in Section 
10.2 as outlined in this Section 10.6.1 and 10.6.2.
    10.6.1 OGI camera operators with previous classroom training (at 
a physical location, remotely, or online) that included a majority 
of the elements listed in Section 10.2.1 do not need to complete the 
initial classroom training as described in Section 10.2.1, but if 
the date of training is more than two years before March 8, 2024, 
the biennial classroom training in Section 10.3 must be completed in 
lieu of the initial classroom training in Section 10.2.1.
    10.6.2 OGI camera operators who have 40 survey hours of 
experience over the 12 calendar months prior to March 8, 2024 may 
substitute the retraining requirements in Section 10.4.3, including 
the final monitoring survey test, for the initial field training 
requirements in Section 10.2.2.

11.0 Quality Assurance and Quality Control

    11.1 As part of the facility's monitoring plan, the facility 
must have a process which ensures the validity of the monitoring 
data. Examples may include routine review and sign-off of the 
monitoring data by the camera operator's supervisor, periodic 
comparative monitoring using a different camera operator as part of 
a continuing training verification plan described in Section 10, or 
other due diligence procedures.
    11.2 For each monitoring day, the daily OGI camera verification 
must be performed as described in Section 9.1. Additionally, the 
daily QA verification video for each operator must be recorded as 
described in Section 9.8 for each operator for each monitoring day.
    11.3 The following table is a summary of the mandatory QA and 
quality control (QC) measures in this protocol with the associated 
frequency and acceptance criteria. All of the QA/QC data must be 
documented and kept with other OGI records.

[[Page 17224]]



                                             Summary Table of QA/QC
----------------------------------------------------------------------------------------------------------------
             Parameter               QA/QC specification       Acceptance criteria             Frequency
----------------------------------------------------------------------------------------------------------------
OGI Camera Design.................  Spectral bandpass      Must overlap with major     Once initially (prior to
                                     range.                 absorption peak of the      using the OGI camera to
                                                            compound(s) of interest.    conduct surveys), when
                                                                                        survey components on
                                                                                        equipment that was not
                                                                                        previously included in
                                                                                        monitoring surveys,
                                                                                        whenever there are
                                                                                        process changes that are
                                                                                        expected to cause the
                                                                                        gaseous emissions
                                                                                        composition to change.
OGI Camera Design.................  Initial camera         Must be capable of          Once initially (prior to
                                     specification          detecting (or producing a   using the OGI camera to
                                     confirmation.          detectable image of)        conduct surveys).
                                                            methane emissions of 19 g/
                                                            hr and either n-butane
                                                            emission of 29 g/hr or
                                                            propane emissions of 22 g/
                                                            hr at a viewing distance
                                                            of 2.0 meters and a delta-
                                                            T of 5.0 [deg]C in an
                                                            environment of calm wind
                                                            conditions around 1.0 m/s
                                                            or less.
Developing the Operating Envelope.  Observation            Leak is observed by 3 out   Once initially (prior to
                                     confirmation.          of 4 panel observers for    using the OGI camera to
                                                            specific combinations of    conduct surveys) and
                                                            delta-T, distance, and      prior to using a new
                                                            wind speed.                 camera configuration for
                                                                                        which an envelope was
                                                                                        not previously
                                                                                        established. The
                                                                                        operating envelope may
                                                                                        be updated or expanded
                                                                                        at any time, following
                                                                                        the procedures in
                                                                                        Section 8.
Daily Field Check.................  Maximum viewing        Determine distance at       Each monitoring day. Not
                                     distance.              which each OGI camera       required for OGI camera
                                                            operator can visualize      operators using
                                                            leaks according to          operating envelopes
                                                            Section 8.7.                established according to
                                                                                        Section 8.
OGI Camera Functionality..........  Verification Check...  Meet the requirements of    Each monitoring day,
                                                            Section 9.1 to confirm      prior to conducting a
                                                            that the OGI camera         survey.
                                                            software loads
                                                            successfully and that the
                                                            camera focuses properly,
                                                            produces a live IR image,
                                                            and, as applicable,
                                                            performs the delta-T
                                                            check function.
Camera Operator Training..........  Classroom training...  Meet the requirements of    Prior to conducting
                                                            Sections 10.2.1 and 10.3    surveys (except as noted
                                                            with the issuing of a       in Section 10.6.1), with
                                                            certificate or record of    a biennial refresher.
                                                            attendance.
Camera Operator Training..........  Field training.......  Meet the requirements of    Except as noted in
                                                            Section 10.2.2 while        Section 10.6.2, prior to
                                                            maintaining the records     conducting surveys and
                                                            of survey hours by the      if retraining is
                                                            trainee along with a        required following two
                                                            certificate or record of    consecutive semiannual
                                                            completion issued upon      audits.
                                                            passing the final
                                                            monitoring survey test in
                                                            Section 10.2.2.4 with the
                                                            date of the survey
                                                            recorded.
OGI Camera Operator Performance...  Semiannual             Comparative monitoring or   Every 6 months, with at
                                     performance audits.    video review. Meet the      least 3 months between
                                                            benchmarks in Section       consecutive audits or at
                                                            10.4.1.2 or 10.4.2.2.       the next scheduled
                                                                                        monitoring survey if a
                                                                                        camera operator is not
                                                                                        scheduled to perform an
                                                                                        OGI survey during the
                                                                                        semiannual period.
Camera Operator Training..........  Field retraining.....  Meet the requirements of    After failing to meet the
                                                            Section 10.4.3 while        benchmarks in Section
                                                            maintaining the records     10.4.1.2 or 10.4.2.2
                                                            of survey hours by the      during a semiannual
                                                            trainee along with a        audit or after a
                                                            certificate or record of    prolonged period
                                                            completion issued upon      (greater than 12 months)
                                                            passing the final           of not performing OGI
                                                            monitoring survey test in   surveys. May be
                                                            Section 10.2.2.4 with the   substituted for initial
                                                            date of the survey          field training as noted
                                                            recorded.                   in Section 10.6.2.
OGI Camera Operator Performance...  QA verification video  Record a video that is a    Each monitoring day.
                                                            minimum of 5 minutes long
                                                            that documents the
                                                            procedures the operator
                                                            uses to survey (e.g.,
                                                            dwell times, angles,
                                                            distances, backgrounds)
                                                            and the camera
                                                            configuration.
----------------------------------------------------------------------------------------------------------------

12.0 Recordkeeping

    12.1 Records must be kept for a period of 5 years, unless 
otherwise noted below or otherwise specified in a referencing 
subpart. Records may be retained in hard copy or electronic form.
    12.2 The facility must maintain the following records in a 
manner that is easily accessible to all OGI camera operators. These 
records must be retained for as long as the site performs OGI 
surveys. Older versions of these records that are no longer relevant 
because they have been replaced by newer versions must be retained 
for a period of 5 years past the date on which they are replaced.
    12.2.1 Complete site monitoring plan with all the required 
elements.
    12.2.2 The OGI camera operating envelope limitations.
    12.3 All data supporting the OGI camera specification 
confirmation (initially and updated as required in Section 8.1) and 
development of the operating envelope. While the owner or operator 
does not need to have a copy of these records onsite if another 
entity performed the camera specification confirmation or 
development of the operating envelope, the owner or operator must:
    (1) Ensure that the camera specification confirmation and 
development of the operating envelope were performed in accordance 
with the requirements of this appendix K,

[[Page 17225]]

    (2) Ensure easy access to these records, and
    (3) Make the records available for review if requested by the 
Administrator.
    These records must be retained for the entire period that the 
OGI camera is used to conduct surveys at the site plus 5 years.
    12.4 The training plan for OGI camera operators. The plan must 
be retained for as long as the site performs OGI surveys. Older 
versions of the plan that are no longer relevant because they have 
been replaced by a newer version must be retained for a period of 5 
years past the date on which they are replaced. If the facility does 
not perform its own OGI monitoring, the owner or operator must:
    (1) Ensure that the training plan for the company performing the 
OGI surveys adheres to the requirements of this appendix K,
    (2) Ensure easy access to the plan, and
    (3) Make the plan available for review if requested by the 
Administrator.
    12.5 For each OGI camera operator, the following records. These 
may be kept in a separate location for privacy but must be easily 
accessible to program administrators and available for review if 
requested by the Administrator. It may be necessary to retain the 
records in Section 12.5.3 for longer than 5 years to show the career 
experience survey hours for senior OGI camera operators. If the 
facility does not perform its own OGI monitoring, the owner or 
operator must:
    (1) Ensure that the training plan for the company performing the 
OGI surveys adheres to the requirements of this appendix K,
    (2) Be able to easily access these records, and
    (3) Make the records available for review if requested by the 
Administrator.
    The records must include the following information.
    12.5.1 The date of completion of initial OGI camera operator 
classroom training;
    12.5.2 The date of the passed final site survey test following 
the initial OGI camera operator field training or retraining;
    12.5.3 The number and date of all surveys performed, and if the 
survey is part of initial field training or retraining, the amount 
of survey hours and notation of whether the survey was performed by 
observing a senior OGI camera operator, side-by-side with a senior 
OGI camera operator, or with oversight from a senior OGI camera 
operator;
    12.5.4 The date and results of semiannual performance audits;
    12.5.5 The date of the biennial classroom training refresher; 
and
    12.5.6 Documentation to support the use of previous experience 
as a substitution for initial training requirements, including the 
date of previous classroom training and documentation of survey 
hours over the 12 calendar months prior to March 8, 2024, as 
appropriate.
    12.6 Monitoring survey results shall be kept in a manner that is 
accessible to those technicians executing repairs and at a minimum 
must contain the following:
    12.6.1 Daily verification check;
    12.6.2 Identification of the site surveyed, the survey date, and 
the start and end times of the survey;
    12.6.3 Name of the OGI camera operator performing the survey and 
identification of the OGI camera used to conduct the survey. The 
identification of the OGI camera can be the serial number or an 
assigned name/number labeled on the camera, but it must allow an 
operator or inspector to tie the camera back to the records 
associated with the camera (e.g., maintenance, initial specification 
confirmation);
    12.6.4 Weather conditions, including the ambient temperature, 
wind speed, relative humidity, and sky conditions, at the start and 
end of the survey and every two hours (if the survey exceeded four 
hours in length);
    12.6.5 Video footage or photograph of any leak detected, or 
video footage of the entire survey, along with the date, time, and 
location of the leak, and identification of the component associated 
with the leak;
    12.6.6 The daily QA verification video for each operator; and
    12.6.7 GPS coordinates for the route taken, if Section 9.3.3 is 
used to ensure all components regulated by the referencing subpart 
are monitored.
    12.7 For each instance that an OGI camera operator uses the 
daily field check outlined in Section 8.7 instead of an operating 
enveloped established under Section 8, the following records must be 
kept with the monitoring survey records required by Section 12.6.
    12.7.1 Date and time of each daily field check.
    12.7.2 Video record of the daily field check.
    12.7.3 Maximum viewing distance determined for each test gas in 
each configuration for each OGI camera operator. The overall maximum 
viewing distance (or overall maximum viewing distance per 
configuration) that will be used for the monitoring day for each OGI 
camera operator.
    12.7.4 The delta-T and wind speed at the time of the daily field 
check.
    12.7.5 Documentation of the test gas flow rate and 
concentrations during the daily field check.
    12.8 Camera maintenance and calibration records over the entire 
period that the OGI camera is used to conduct surveys at the site. 
Older versions of these records that are no longer relevant because 
they have been replaced by newer versions must be retained for a 
period of 5 years past the date on which they are replaced. If the 
facility does not perform its own OGI monitoring, the owner or 
operator must be able to easily access these records and must make 
the records available for review if requested by the Administrator.

13.0 References

    13.1 U.S. Department of Health and Human Services. (2010). NIOSH 
Pocket Guide to Chemical Hazards. NIOSH Publication No. 2010-168c. 
Also available from https://www.cdc.gov/niosh/docs/2010-168c/default.html.
    13.2 U.S. Environmental Protection Agency. (2023). Technical 
Support Document: Optical Gas Imaging Protocol (Appendix K to this 
part).
    13.3 U.S. Environmental Protection Agency. (2020). Optical Gas 
Imaging Stakeholder Input Workshop Presentations and Discussion; 
Summary Letter Report.
    13.4 Zimmerle, D., T. Vaughn, C. Bell, K. Bennett, P. Deshmukh, 
and E. Thoma. (2020). Detection Limits of Optical Gas Imaging for 
Natural Gas Leak Detection in Realistic Controlled Conditions. 
Environmental Science & Technology, 54(18), 11506-11514. DOI: 
10.1021/acs.est.0c01285.

14.0 Annexes

    14.1 Annex 1--Development of Response Factors for OGI Cameras.
    14.1.1 Introduction.
    The purpose of this annex 14.1 is to outline the protocol for 
the development of response factors (RFs) for optical gas imaging 
(OGI) cameras. As defined in Section 3.0 of this appendix K, a 
response factor is the OGI camera's response to a compound of 
interest relative to a reference compound at a concentration path-
length of 10,000 parts per million-meter (ppm-m).
    14.1.1.1 Nomenclature.
    14.1.1.1.1 The definitions listed in Section 3.0 of this 
appendix K apply to this annex 14.1.
    14.1.1.1.2 Infrared (IR) radiance pixel area. The IR radiance 
pixel area is the average of a set of pixel IR radiance for an 
instantaneous measurement. There will be three different areas 
representing the reference cell, gas cell, and the raw blackbody 
surface. The pixel count for each area must be at a minimum of 0.5 
percent of the total pixels of the detector. The pixel locations 
selected for an area must not change throughout the test.
    14.1.1.1.3 Measurement data set. Measurement data set is the 
number of time independent IR radiance pixel areas that are taken. 
The minimum number of measured IR radiance pixel area within a data 
set is 1,000 data points. The number of measured IR radiance pixel 
area within a measurement data set should stay consistent throughout 
the test.
    14.1.1.1.4 Reference Compound. The reference compound is the 
compound that provides the reference for determination of the RF 
with the compound of interest. The reference compound for this annex 
14.1 is propane, unless otherwise specified in a referencing 
subpart.
    14.1.2 Applicability and Analytical Principle.
    14.1.2.1 Applicability. This annex 14.1 applies to the 
determination of compound specific RFs through empirical testing for 
use with this appendix K. This annex 14.1 does not apply to other 
applications of OGI cameras or other instruments. This annex 14.1 
does not limit the use of other peer reviewed and published 
techniques and RFs per Section 3.0 of this appendix K.
    14.1.2.2 Analytical Principle. OGI cameras work by providing an 
image or video with each pixel representing a measurement of the IR 
radiation. OGI cameras limit measurement to specific wavelengths of 
IR through the choice of the detector and generally through the 
addition of a bandpass filter. Limiting the measurement to specific 
wavelengths of IR allows the OGI camera to focus on a specific 
region of interest in order to increase the detection capabilities 
of

[[Page 17226]]

particular compounds of interest. The combination of detector and 
bandpass filter, in addition to limiting the region of interest, 
will allow varying amounts of IR over the specific wavelength 
region.
    14.1.3.0 Equipment and Supplies.
    14.1.3.1 Section 6.0 of this appendix K lists equipment and 
supplies that may be used in this annex 14.1.
    14.1.3.2 Blackbody Source. A sufficiently large blackbody source 
capable of maintaining high emissivity, as well as temperature 
stability and homogeneity.
    14.1.3.2.1 The blackbody must have an emissivity of 0.95 or 
higher in the IR region of interest.
    14.1.3.2.2 The source emissive area must have a uniform 
temperature, where uniform is defined as all points on the emissive 
area deviating no more than 0.10 degree Celsius ([deg]C) from the 
average temperature of the emissive area. The temperature readings 
must be accurate to at least 0.10 [deg]C. The blackbody must be able 
to maintain its temperature within 0.10 [deg]C.
    14.1.3.2.3 The source's surface area must be large enough to 
allow the OGI camera to take IR measurements of two gas cells and 
allow for the proper measurement of IR radiance through the gas and 
reference cell and IR radiance of the surface itself.
    14.1.3.3 Test gas for each compound of interest, used for 
determining the RF. The concentration of the gas in the cylinder 
must be vendor certified to <plus-minus> 5.0 percent of the cylinder 
tag value and be in a balance of nitrogen. The concentration of the 
gas must be such that the gas cell concentration is 10,000 ppm-m 
with less than 2.0 percent error. Alternatively, the gas standard 
may be produced with dilution per Method 205 of 40 CFR part 51 
Appendix M with the exception that the mid-supply gas may be vendor 
certified to <plus-minus> 5.0 percent of the cylinder tag value.
    14.1.3.4 Gas Cell. A windowed gas cell that is leak tight and 
has the ability to flow gas through the cell. The size of the cell 
should be such to allow for 10,000 ppm-m to be viewed by the OGI 
camera with less than 2.0 percent error. The windows should be 99 
percent transmissive in the IR region of interest and deviate no 
more than 0.50 percent transmission over than region of interest. 
The cell must have associated temperature, flow, and pressure 
measurements.
    14.1.3.5 Reference Compound Gas Standard. Propane gas standard, 
unless a referencing subpart specifies otherwise, used as the 
reference for determination of the RF. The concentration of the gas 
in the cylinder must be vendor certified to <plus-minus> 2.0 percent 
of the cylinder tag value and be in a balance of nitrogen. The 
concentration of the gas must be such that the gas cell 
concentration is 10,000. ppm-m with less than 2.0 percent error.
    14.1.3.6 Reference Cell. A gas cell for the reference compound 
gas standard which meets all of the requirements in Section 14.1.3.4 
of this annex 14.1.
    14.1.3.7 Zero Gas. A 99.99 percent pure diatomic gas, typically 
nitrogen, that has no IR response from the OGI camera, used to 
assess the detection level of the system and baseline response of 
the gas cells.
    14.1.3.8 OGI Camera is the specific OGI camera that is being 
tested. RFs must be determined for each IR detector and bandpass 
filter combination. The OGI camera must have the ability to output 
the raw IR radiance at the pixel level.
    14.1.3.8.1 The combination of IR detector and bandpass filter 
may be consistent over several models such that the developed RFs 
may be applicable to more than one model of OGI camera.
    14.1.3.8.2 If the OGI camera model has exchangeable bandpass 
filters, more than one set of RFs may be needed for the OGI camera 
model to account for the differences between filters.
    4.0 Pre-Test Preparation and Evaluations.
    14.1.4.1 Room Preparation. The room where testing will occur 
must be prepared by removing all extraneous thermal sources, or at a 
minimum, isolating extraneous thermal sources with IR absorptive 
material before any testing is conducted.
    14.1.4.2 Reference and Gas Cell Preparation. Perform leak checks 
on both the reference and gas cells. Ensure that the temperatures of 
the cells are within 0.10 [deg]C and that the pressure measurements 
are working.
    14.1.4.3 OGI Camera Preparation. Ensure the OGI camera is 
operating to manufacturer specifications and able to record in raw 
IR radiance on a per pixel basis.
    14.1.4.4 Blackbody Preparation and Verification. Prepare the 
blackbody by setting the temperature 10.0 [deg]C different than the 
gas and reference cell temperatures. Ensure the blackbody is working 
correctly by verifying the IR radiance homogeneity of the blackbody 
surface with the OGI camera.
    14.1.4.5 System Preparation. Ensure the alignment of the cells, 
blackbody source, and OGI camera are all fixed in place and cannot 
deviate from their position during the testing.
    14.1.4.5.1 The reference and gas cell windows must overlap the 
blackbody surface in a manner that provides sufficient viewing of 
the blackbody surface from the vantage point of the camera.
    14.1.4.5.2 The reference and gas cells should be placed 
sufficiently away from the blackbody surface. The distance must be 
far enough to ensure that the reference and gas cells are not heated 
or cooled by the blackbody surface.
    14.1.4.5.3 The OGI camera should be located at a distance such 
that the field of view allows the requirements of the IR radiance 
pixel area to be met. Additionally, the distance must be such that 
it does not nominally change the path length of the cell.
    14.1.4.5.4 For both the reference cell and the gas cell, the 
depth of the cell and concentration of the gas must result in a 
concentration 10,000. ppm-m with less than 2 percent error.
    14.1.4.6 Initial System Assessment.
    14.1.4.6.1 Flow zero gas through both the reference and gas 
cell, and ensure the gas cell temperatures are within 0.1 [deg]C.
    14.1.4.6.2 Record the temperatures of the gas and reference 
cells, the blackbody surface, and the room. Record the pressures in 
the reference and gas cells. Record the flowrates into the reference 
and gas cells.
    14.1.4.6.3 Measure the IR radiance of the reference cell, the 
gas cell, and the blackbody surface for a measurement data set. For 
the IR radiance pixel area for the blackbody, the blackbody through 
the reference cell, and the blackbody through the gas cell, 
calculate the average, the standard deviation, and the 99 percent 
confidence level for the measurement data set.
    14.1.4.6.4 The detection limit for the system will be the 
highest 99 percent confidence level of the IR radiance measurement 
of the blackbody, blackbody through the reference cell, or blackbody 
through the gas cell.
    14.1.4.6.5 If the standard deviation of the reference cell's and 
the gas cell's average pixel areas of interest have a difference 
greater than 5 percent, take corrective actions and repeat the 
assessment.
    14.1.5.0 Sampling and Analysis Procedure.
    14.1.5.1 Flow reference compound gas through the reference cell 
and test gas for the compound of interest through the gas cell and 
ensure the cell temperatures are within 0.10 [deg]C.
    14.1.5.2 Record the temperatures of the gas and reference cells, 
the blackbody surface, and the room temperature. Record the 
pressures in the reference and gas cells. Record the flowrates into 
the reference and gas cells. If using Method 205 of 40 CFR part 51 
Appendix M for dilution of the test gas for the compound of 
interest, record the appropriate parameters required by the method.
    14.1.5.3 Adjust the gas flow if the pressure in the cell is not 
within an inch of water of ambient pressure. Ensure cell 
temperatures are within 0.10 [deg]C of the room temperature.
    14.1.5.4 Measure the IR radiance of the reference cell, the gas 
cell, and the blackbody surface for a measurement data set. 
Calculate the average of the IR radiance pixel area and the standard 
deviation of the IR radiance pixel area for the reference cell, gas 
cell, and the blackbody surface for the measurement data set.
    14.1.6.0 Post-test Requirements.
    14.1.6.1 Post-test Assessment.
    14.1.6.1.1 Flow zero gas through both the reference and gas 
cells and ensure the cell temperatures are within 0.1 [deg]C.
    14.1.6.1.2 Record the temperatures of the gas and reference 
cells, the blackbody surface, and the room. Record the pressures in 
the reference and gas cells. Record the flowrates into the reference 
and gas cells.
    14.1.6.1.3 Measure the IR radiance of the reference cell, the 
gas cell, and the blackbody surface for a measurement data set. 
Calculate the average of the IR radiance pixel area, the standard 
deviation of the IR radiance pixel area, and the 99 percent 
confidence level of the IR radiance pixel area for the reference 
cell, gas cell, and the blackbody surface for the measurement data 
set.
    14.1.6.1.4 If the average and standard deviation of the 
reference cell's and the gas cell's average pixel areas of interest 
have a difference greater than 5.0 percent between the pre-test and 
post-test assessment, then the test is invalid. Take corrective 
actions and repeat the test.
    14.1.6.2 When the average of the IR radiance pixel areas for the 
compound of

[[Page 17227]]

interest over the measurement set as determined in Section 14.1.5.4 
of this annex 14.1 is greater than the detection limit established 
in Section 14.1.4.6.4 of this annex 14.1, calculate the RF for the 
compound of interest as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.043

RF = response factor of the compound of interest (unitless).
I<INF>Blackbody</INF> = average of the IR radiance pixel areas for 
the blackbody over the measurement set as determined in Section 
14.1.4.6.3 of this annex 14.1, 
W[middot]m<SUP>-2</SUP>[middot]sr<SUP>-1</SUP> (watts per square 
meter per steradian).
I<INF>Compound of interest</INF> = average of the IR radiance pixel 
areas for the compound of interest over the measurement set as 
determined in Section 14.1.5.4 of this annex 14.1, 
W[middot]m<SUP>-2</SUP>[middot]sr<SUP>-1</SUP>.
I<INF>Gas Cell</INF> = average of the IR radiance pixel areas for 
the gas cell over the measurement set during the pre-test assessment 
as determined in Section 14.1.4.6.3 of this annex 14.1, 
W[middot]m<SUP>-2</SUP>[middot]sr<SUP>-1</SUP>.
I<INF>Reference Compound</INF> = average of the IR radiance pixel 
areas for the reference compound over the measurement set as 
determined in Section 14.1.5.4 of this annex 14.1, 
W[middot]m<SUP>-2</SUP>[middot]sr<SUP>-1</SUP>.
I<INF>Reference Cell</INF> = average of the IR radiance pixel areas 
for the reference cell over the measurement set during the pre-test 
assessment as determined in Section 14.1.4.6.3 of this annex 14.1, 
W[middot]m<SUP>-2</SUP>[middot]sr<SUP>-1</SUP>.

    14.1.6.3 When the average of the IR radiance pixel areas for the 
compound of interest over the measurement set as determined in 
Section 14.1.5.4 of this annex 14.1 is less than the detection limit 
established in Section 14.1.4.6.4 of this annex 14.1, the RF is 
equal to zero.
    14.1.7.0 Reporting and Recordkeeping Requirements.
    14.1.7.1 Records, including all raw data and calculations, must 
be kept for a period of 5 years, unless otherwise noted below or 
otherwise specified in a referencing subpart. Records may be 
retained in hard copy or electronic form.
    14.1.7.2 All records supporting the development of RFs under 
this annex 14.1 must be maintained in a manner that is easily 
accessible to all OGI camera operators using the RFs. While the 
owner or operator does not need to have a copy of these records 
onsite if another entity performed the development of the RFs, the 
owner or operator must:
    (1) Ensure that the RF development was performed in accordance 
with the requirements of this annex,
    (2) Ensure easy access to these records, and
    (3) Make the records available for review if requested by the 
Administrator.
    These records must be retained for the entire period that the 
OGI camera is used to conduct surveys at the site plus 5 years. 
Previous versions of these records that are no longer relevant 
because they have been replaced by newer versions or because the 
specific OGI camera model is no longer being used to conduct surveys 
at the site must be retained for a period of 5 years past the date 
on which the records are replaced or the OGI camera model is no 
longer being used to conduct surveys at the site.
    14.1.8.0 References.
    14.1.8.1 U.S. Environmental Protection Agency. (2023). Technical 
Support Document: Optical Gas Imaging Protocol (appendix K to this 
part).

[FR Doc. 2024-00366 Filed 2-23-24; 4:15 pm]
BILLING CODE 6560-50-P


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