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

#  Does this subpart directly affect designated facility owners and operators in my state?

**AGENCY:**

Environmental Protection Agency (EPA).

**ACTION:**

Interim final rule; request for comments.

**SUMMARY:**

The U.S. Environmental Protection Agency (EPA) is taking interim final action to extend certain deadlines within the final rule titled “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review,” 89 FR 16820 (March 8, 2024) (hereafter “2024 final rule”). Specifically, the EPA is extending deadlines for certain provisions related to control devices, equipment leaks, storage vessels, process controllers, and covers/closed vent systems in “Subpart  OOOOb—Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification or Reconstruction Commenced After December 6, 2022” (NSPS OOOOb). The EPA also is extending the date for future implementation of the SuperEmitter Program. Finally, the EPA is extending the state plan submittal deadline in “Subpart OOOOc—Emissions Guidelines (EG) for Greenhouse Gas Emissions From Existing Crude Oil and Natural Gas Facilities” (EG OOOOc). The EPA is requesting comments on all aspects of this interim final rule and will consider all comments received in determining whether amendments to this rule are appropriate after the conclusion of the comment period.

**DATES:**

This interim final rule is effective on July 31, 2025. Comments on this interim final rule must be received on or before September 2, 2025.

**ADDRESSES:**

You may send comments, identified by Docket ID No. EPA-HQ-OAR-2025-0162, by any of the following methods:

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

• *Email: [email protected].* Include Docket ID No. EPA-HQ-OAR-2025-0162 in the subject line of the message.

• *Mail:* U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPAHQ-OAR-2025-0162, Mail Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.

• *Hand/Courier Delivery:* EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-Friday (except Federal Holidays). Comments received may be posted without change to *https://www.regulations.gov,* including any personal information provided. For detailed instructions on sending comments, see the “Public Participation” heading of the General Information section of this document.

**FOR FURTHER INFORMATION CONTACT:**

Amy Hambrick, Sector Policies and Programs Division (E143-05), 109 T.W. Alexander Drive, P.O. Box 12055, Office of Air Quality Planning and Standards, United States Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-0964; and email address: *[email protected].* Individuals who are deaf or hard of hearing, as well as individuals who have speech or communication disabilities may use a relay service. To learn more about how to make an accessible telephone call to any of the numbers shown in this document, visit the web page for the relay service of the Federal Communications Commission. Additional questions may be directed to the following email address: *O&[email protected].*

**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:

APA Administrative Procedure Act

AVO audible, visual, and olfactory

CAA Clean Air Act

CBI Confidential Business Information

CFR Code of Federal Regulations

CRA Congressional Review Act

CVS closed vent systems

ECD enclosed combustion device

EG emissions guidelines

EPA Environmental Protection Agency

FR Federal Register

GC gas chromatograph

GHG greenhouse gas

LPE legally and practicably enforceable

Mcf thousand cubic feet

MS mass spectrometer

NAICS North American Industry Classification System

NIE no identifiable emissions

NHV net heating value

NHV <sub>cz</sub> combustion zone net heating value

NHV <sub>dil</sub> dilution parameter net heating value

NSPS new source performance standards

OGI optical gas imaging

OMB Office of Management and Budget

ppmv parts per million by volume

PRA Paperwork Reduction Act

RFA Regulatory Flexibility Act

RULOF remaining useful life and other factors

SEP super emitter program

SIP state implementation plan

TOC total organic compounds

tpy tons per year

UMRA Unfunded Mandates Reform Act

U.S.C. United States Code

VOC volatile organic compound(s)

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

I. General Information

A. Public Participation

B. Potentially Affected Entities

C. Statutory Authority

D. Judicial Review and Administrative Review

II. Regulatory Revisions

A. Background and Summary

B. Deadline Extensions for NSPS OOOOb

C. Deadline Extensions for EG OOOOc

III. Rulemaking Procedures

IV. Request for Comment

V. Statutory and Executive Order Reviews

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

B. Executive Order 14192: Unleashing Prosperity Through Deregulation

C. Paperwork Reduction Act (PRA)

D. Regulatory Flexibility Act (RFA)

E. Unfunded Mandates Reform Act of 1995 (UMRA)

F. Executive Order 13132: Federalism

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

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

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

J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51

K. Congressional Review Act (CRA)

**I. General Information**

**A. Public Participation**

Submit your written comments, identified by Docket ID No. EPA-HQ-OAR-2025-0162, at *https://www.regulations.gov* (our preferred method), or by the other methods identified in the *ADDRESSES* section. Once submitted, comments cannot be edited or removed from the docket. The EPA may publish any comment received to its public docket. Do not submit to the EPA's docket at *https://www.regulations.gov* any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. This type of information should be submitted as discussed in the *Submitting CBI* section of this document. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission ( *i.e.,* on the web, cloud, or other file sharing system). Please visit *https://www.epa.gov/dockets/commenting-epa-dockets* for additional submission methods; the full EPA public comment policy; information about CBI or multimedia submissions; and general guidance on making effective comments.

*Submitting CBI.* Do not submit information containing CBI to the EPA through *https://www.regulations.gov.* Clearly mark the part or all the information that you claim to be CBI. For CBI on any digital storage media  that you mail to the EPA, note the docket ID, mark the outside of the digital storage media as CBI, and identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in the Public Participation section of this document. If you submit any digital storage media that does not contain CBI, mark the outside of the digital storage media clearly that it does not contain CBI and note the docket ID. Information not marked as CBI will be included in the public docket and the EPA's electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2.

Our preferred method to receive CBI is for it to be transmitted electronically using email attachments, File Transfer Protocol (FTP), or other online file sharing services ( *e.g.,* Dropbox, OneDrive, Google Drive). Electronic submissions must be transmitted directly to the OAQPS CBI Office at the email address *[email protected],* and as described above, should include clear CBI markings, and note the docket ID. If assistance is needed with submitting large electronic files that exceed the file size limit for email attachments, and if you do not have your own file sharing service, please email *[email protected]* to request a file transfer link. If sending CBI information through the postal service, please send it to the following address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2025-0162. The mailed CBI material should be double wrapped and clearly marked. Any CBI markings should not show through the outer envelope.

**B. Potentially Affected Entities**

The source category that is the subject of this action is the Crude Oil and Natural Gas source category, regulated under Clean Air Act (CAA) section 111. The North American Industry Classification System (NAICS) codes for the industrial source categories affected by the new source performance standards (NSPS) portion of this action are summarized in table 1.

| Category | NAICS code | Examples of regulated entities |
| --- | --- | --- |
| Industry | 211120 | Crude Petroleum Extraction. |
|  | 211130 | Natural Gas Extraction. |
|  | 221210 | Natural Gas Distribution. |
|  | 486110 | Pipeline Distribution of Crude Oil. |
|  | 486210 | Pipeline Transportation of Natural Gas. |
| Federal Government |  | Not affected. |
| State and Local Government |  | Not affected. |
| Tribal Government | 921150 | American Indian and Alaska Native Tribal Governments. |

This table is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by the deadline extensions. Other types of entities not listed in the table could also be affected by this action. To determine whether your entity is affected by any of the deadline extensions in this action, you should carefully examine the applicability criteria found in NSPS OOOOb. If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the *FOR FURTHER INFORMATION CONTACT* section.

The deadline extensions in EG OOOOc 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 greenhouse gases (GHG) 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.

[^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.

**C. Statutory Authority**

Statutory authority to issue the amendments finalized in this action is provided by the same CAA provisions that provided authority to issue the regulations being amended: CAA section 111(b)(1)(B) (requirement to review, and if appropriate, revise, standards of performance for new sources at least every 8 years) and CAA section 111(d) (requirement to issue EG for existing sources for certain pollutants to which a NSPS would apply if such existing source were a new source). These statutory provisions, along with administrative agencies' authority to reconsider prior regulations, provide the EPA's statutory authority for the targeted amendments to compliance deadlines finalized in this action. [^2]

[^2]*See FDA* v. *Wages & White Lion Invs., LLC,* 145 S. Ct. 898 (2025); *FCC* v. *Fox TV Stations, Inc.,* 556 U.S. 502 (2009); *Motor Vehicle Mfrs. Ass'n* v. *State Farm Mut. Auto. Ins. Co.,* 463 U.S. 29 (1983).

Statutory authority for the rulemaking procedures followed in this action is provided by Administrative Procedure Act (APA) section 553(b)(B), 5 United States Code (U.S.C.) 553(b)(B) (good cause exception to notice-and-comment rulemaking), and statutory authority for making this action, which meets the criteria under 5 U.S.C. 804(2), effectively immediately is provided by 5 U.S.C. 808(2). As explained in section III of this preamble, the EPA finds good cause to forego prior notice and comment because such procedures are unnecessary and impracticable under the circumstances detailed in section II of this preamble.

**D. Judicial Review and Administrative Review**

Under CAA section 307(b)(1), judicial review of this final action is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by September 29, 2025. Under CAA section 307(b)(2), the requirements established by this final action may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce the requirements.

**II. Regulatory Revisions**

**A. Background and Summary**

On November 15, 2021, the EPA published a proposed rule (“November 2021 Proposal”) to reduce GHG and volatile organic compound (VOC) emissions from the oil and natural gas industry, [^3] specifically the Crude Oil and Natural Gas source category. <sub>4 5</sub> In the November 2021 Proposal, the EPA proposed revised standards of performance under CAA section 111(b) for GHG and VOC emissions from new, modified, and reconstructed sources in this source category, as well as changes to standards of performance already codified at 40 CFR part 60, subparts OOOO and OOOOa. The EPA also proposed EG under CAA section 111(d) for GHG emissions from existing sources. [^6] The EPA also updated the NSPS OOOO and NSPS OOOOa provisions in the Code of Federal Regulations (CFR) in response to Congress' disapproval of 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”), under the CRA. Lastly, the EPA proposed a protocol under the NSPS general provisions for optical gas imaging (OGI).

[^3] The EPA characterizes the oil and natural gas industry operations as being generally composed of 4 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.

[^4] “ *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).

[^5] 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.”

[^6] 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).

On December 6, 2022, the EPA published a supplemental proposed rule (“December 2022 Supplemental Proposal”) that was composed of two main additions. [^7] First, the EPA proposed to update, tighten, and expand the NSPS OOOOb standards proposed in November 2021 under CAA section 111(b) for GHG and VOC emissions from new, modified, and reconstructed sources. Second, the EPA proposed to update, tighten, and expand the EG OOOOc presumptive standards proposed in November 2021 under CAA section 111(d) for GHG emissions from existing sources. For purposes of EG OOOOc, the EPA also proposed implementation requirements for state plans.

[^7] “ *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).

On March 8, 2024, the EPA published a final rule for the Crude Oil and Natural Gas source category under CAA section 111(b) and (d). First, the EPA finalized NSPS OOOOb for GHG and VOC emissions from new, modified, and reconstructed sources in this source category. Second, the EPA finalized EG OOOOc for GHG emissions from existing sources in this source category. Third, the EPA finalized various amendments in response to Congress' disapproval of the 2020 Policy Rule. The 2024 final rule became effective on May 7, 2024.

After publication of the 2024 final rule, the EPA received multiple petitions for reconsideration and has now determined, through ongoing and recent communications with stakeholders and review of the relevant regulatory language, that certain discrete provisions in the final rule present immediate problems related to compliance. The issues raised in petitions for reconsideration that are relevant to this interim final rule are described in individual sections below. In this action, the EPA is amending certain compliance deadlines and timeframes for implementation in response to information received after promulgation of the 2024 final rule to address legitimate concerns, raised by stakeholders, that certain regulatory provisions are not currently workable or contain problematic regulatory language that frustrates compliance.

The 2024 final rule is extensive, covering many individual emissions sources of different types at thousands of facilities in the oil and natural gas source category across the country. As explained in more detail in the sections below, the 2024 rule included several provisions that subsequent developments have shown to be untenable from a compliance perspective on the original timeframes set out in the 2024 rule. These timing difficulties were not anticipated in or intended by the 2024 rule, and it is in the public interest and consistent with the purposes of the CAA to provide regulated entities sufficient time to achieve the emissions reductions envisioned by the 2024 rule. Based on information received in petitions for reconsideration and from ongoing conversations with regulated entities, the EPA finds that the targeted revisions to compliance deadlines set forth below are necessary, appropriate, and consistent with the purposes of the 2024 rule and the CAA.

Each regulatory change included in this final action is severable from the other. First, each of the deadlines amended in this action is functionally independent from the others— *i.e.,* may operate in practice independently of the other requirements being amended here, such that the amendment of a deadline in one set of requirements does not turn on the amendment of a deadline in any other set of requirements. For example, amendments to individual compliance deadlines in NSPS OOOOb function separately from amendments to the state plan submittal deadline in EG OOOOc. Similarly, amendments to the implementation deadline for the Super-Emitter Program and amendments to timing for EPA action on methane detection technology for use in the Super-Emitter Program function separately from amendments to individual compliance deadlines to other aspects of the 2024 final rule. Second, as explained in section II.B of this preamble, the reasoning for each regulatory change is distinct and independent from the others. For  example, amendments to individual compliance deadlines in NSPS OOOOb are separately justified, based on the recent information received by the Agency, from the amendments made to the state plan submittal deadline in EG OOOOc based on recent information gathered by the Agency on a distinct set of issues related to OOOOc. Similarly, amendments to individual implementation deadlines for the SEP are separately justified, based on information received by the Agency, from amendments made in response to information received on distinct compliance issues under the other provisions of the 2024 final rule.

The EPA continues to review other issues related to the 2024 final rule that have been brought to the Agency's attention but are not substantively addressed in this action. <sub>8 9</sub> Thus, this action does not reopen the substance of the 2024 final rule or address the substantive amendments requested in various petitions for reconsideration. As noted in section IV of this preamble, the EPA seeks comment on the compliance deadline amendments at issue in this action and will consider appropriate revisions in reviewing comments. However, the EPA does not seek comment on the substance of the 2024 final rule and will seek and respond to comments on further amendments to the substance of the 2024 final rule at an appropriate time in future rulemaking.

[^8] See 90 FR 3734. On January 15, 2025, the EPA proposed amendments to NSPS OOOOb and EG OOOOc in response to petitions for reconsideration. The January 2025 proposal includes discrete technical changes to two aspects of the 2024 final rule. The two issues addressed in the January 2025 proposal are temporary flaring provisions for associated gas in certain situations and vent gas NHV continuous monitoring requirements and alternative performance test (sampling demonstration) option for flares and ECDs.

[^9] In a press release dated March 12, 2025, the EPA Administrator announced various reconsideration efforts including NSPS OOOOb and EG OOOOc. *https://www.epa.gov/newsreleases/trump-epa-announces-oooo-bc-reconsideration-biden-harris-rules-strangling-american.*

**B. Deadline Extensions for NSPS OOOOb 
                    10**

[^10] Changes made to the SEP discussed in section II.B.6 of this preamble also apply to 40 CFR part 60, subparts OOOO and OOOOa.

**1. Control Devices**

In the 2024 final rule, the EPA finalized monitoring requirements for control devices that included vent gas net heating value (NHV) continuous monitoring requirements and an alternative performance test (sampling demonstration) option for flares and enclosed combustion devices (ECDs). In the 2024 final rule, with exceptions for catalytic vapor incinerators, boilers and process heaters, and enclosed combustors where temperature is an indicator of destruction efficiency, all flares and enclosed combustors must maintain the NHV of the gas sent to the device above a minimum NHV if the combustion device is pressure-assisted or uses no assist gas. If an owner or operator uses a steam- or air-assisted flare or ECD, the owner or operator must maintain the combustion zone NHV (NHV <sub>cz</sub> ) above a minimum level. If the owner or operator uses an air-assisted enclosed flare or ECD, the owner or operator must maintain the NHV dilution parameter (NHV <sub>dil</sub> ) above a minimum level. The NHV <sub>cz</sub> and NHV <sub>dil</sub> parameter terms account for the reduction in heating value caused by the introduction of air 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. Owners or operators also have the option to apply to use an alternative test method that either demonstrates continuous compliance with the combustion efficiency limit or directly demonstrates continuous compliance with the NHV <sub>cz</sub> operating limit and, if applicable, the NHV <sub>dil</sub> operating limit.

For each flare or ECD used to control gases other than associated gas from a well site affected facility, the owner or operator must conduct continuous monitoring using a calorimeter, gas chromatograph (GC), or mass spectrometer (MS) in order to determine the NHV of the vent stream. As an alternative to continuous monitoring of NHV, the owner or operator may conduct a performance test to demonstrate the NHV of the vent stream consistently exceeds the applicable NHV operating limit in one of two ways: (1) Continuous sampling for 14 consecutive days plus ongoing (3 samples every 5 years) sampling, or (2) manual sampling (twice daily for 14 consecutive days) plus ongoing (3 samples every 5 years) sampling. The minimum collection time for each individual, manually collected sample must be at least 1 hour. If inlet gas flow is intermittent such that collecting 28 samples in 14 days is infeasible, an owner or operator must continue to collect samples beyond 14 days in order to collect a minimum of 28 samples. Owners or operators also have the option to use an alternative test method <sub>11 12</sub> that demonstrates continuous compliance with the combustion efficiency limit. If there are no values of the combustion efficiency measured by the alternative test method over the 14-day period that are less than 95 percent, the gas stream is considered to consistently exceed the applicable NHV operating limit, and the owner or operator is not required to continuously monitor or conduct sampling of the NHV of the inlet gas to the flare or ECD. Owners or operators of steam-assisted and air-assisted enclosed combustors and flares also must monitor the vent gas and assist gas flow rates and calculate NHV <sub>cz</sub> and NHV <sub>dil</sub> in accordance with the provisions in 40 CFR 63.670 ( *i.e.,* the refinery maximum achievable control technology rule, or Refinery MACT). Alternatively, owners or operators of air-assisted flares may provide a one-time demonstration based on maximum air assist rates, minimum waste gas flow rates (based on back pressure regulator setting), and minimum NHV from the most recent sampling rather than continuously monitor vent gas and assist gas flow rates.

[^11] Under the provisions outlined in 40 CFR 60.5412b(d) and 60.5415b(f)(1)(xi), sources can request to use an “equivalent method” pursuant to 40 CFR 60.8(b)(2), or “an alternative method the results of which [the Administrator] has determined to be adequate for indicating whether a specific source is in compliance” pursuant to 40 CFR 60.8(b)(3). The EPA is currently accepting and reviewing applications for alternative (ALT) test methods for NHV monitoring in the oil and natural gas sector. See *https://www.epa.gov/emc/oil-andgas-alternative-test-methods#:* ~ *:text=The%20application%20portal%20can%20be,Air%20Emission%20Measurement%20Center%20web page.* Since the rule's publication date of March 8, 2024, two alternative test method requests have been approved by the EPA for use under NSPS subpart OOOOb: (1) ALT-156 Alternative Test Method to monitor the NHV of the flare combustion zone at facilities Subject to NSPS OOOOb and (2) ALT-157 Alternative Test Method for determining NHV from gas sent to an ECD or Flare subject to NSPS OOOOb. A list of the EPA's approved alternative test methods can be found at *https://www.epa.gov/emc/broadlyapplicable-approved-alternative-test-methods.*

[^12] Per 40 CFR 60.8(b)(5), the EPA has more general authority to approve alternative test methods involving “shorter sampling times and smaller sample volumes when necessitated by process variables or other factors.”

Multiple petitions for reconsideration and communications with stakeholders after promulgation of the 2024 final rule raised concerns regarding the availability of equipment and personnel necessary [^13] to comply with the NHV provisions in the 2024 final rule. Due to the thousands of control devices immediately subject to the OOOOb NHV requirements, number of samples required to be taken, and existing supply chain constraints for monitoring equipment and sampling vendors, [^14] petitioners have credibly asserted that  compliance would be very challenging to achieve within the compliance timeline. [^15] Moreover, petitioners credibly asserted that even if the samples could be taken within the prescribed period, there is also insufficient analytical laboratory capacity to conduct the necessary analyses for each sample in a timely manner. One of the petitioners stated that vent gas flow from midstream sources to control devices tends to be sporadic and at low pressure and this is particularly true for storage vessels that either have low flows generally or have pressure control valves that only release short bursts of gas to control devices. [^16] Other stakeholders added that even if continuous monitoring was technically feasible, there is a lack of available monitoring equipment, [^17] and that it will take owners and operators several months to procure continuous monitoring equipment and installation will take additional time. Furthermore, stakeholders have credibly asserted that discussions with vendors indicated that calorimeters would take between 8 to 12 weeks for delivery and continuous monitoring devices will take up to 26 weeks [^18] with installation requiring an additional 2 to 3 weeks. [^19]

[^13] See EPA-HQ-OAR-2024-0358-0023 attachment 1 at page 9.

[^14] See EPA-HQ-OAR-2024-0358-0016 at page 6.

[^15] See EPA-HQ-OAR-2024-0358-0009 at page 1.

[^16] See EPA-HQ-OAR-2024-0358-0016 at page 6.

[^17] See EPA-HQ-OAR-2024-0358-0020 attachment 3 at page 5.

[^18] See EPA-HQ-OAR-2024-0358-0020 attachment 3 at page 13.

[^19] See EPA-HQ-OAR-2024-0358-0013 at pages 2-3.

Additionally, one of the petitioners credibly asserted that the 2024 final rule does not provide an adequate period of time to perform the alternative testing procedures under 40 CFR 60.5412b(d) and does not provide any time for testing at all, putting owners and operators at risk of being deemed out of compliance for operating a modified source before and during testing. The petitioner added that the alternative testing protocol (40 CFR 60.5312b(d)(1)-(5)) requires the combustion device to already be operating in order to determine destruction efficiency and inspect for visible emissions, unlike continuous monitoring, which can be installed prior to the startup of a new source. Therefore, petitioners stated that full compliance with the current deadlines across the industry is not feasible. These concerns have been reiterated [^20] in public comments submitted by industry groups on the EPA's proposed reconsideration related to NHV monitoring. [^21] Commenters have pointed out that testing equipment requires significant lead times, often multiple months in advance. [^22]

[^20] See EPA-HQ-OAR-2024-0358-0083 at page 16, submitted to the EPA on March 4, 2025.

[^21] On January 15, 2025, the EPA proposed amendments to the 2024 final rule based on reconsideration of two discrete issues related to NHV monitoring and temporary flaring. See 90 FR 3734 for the January 2025 reconsideration proposal. See Docket ID No. EPA-HQ-OAR-2024-0358 for public comments submitted on the January 2025 reconsideration proposal.

[^22] See EPA-HQ-OAR-2024-0358-0046 at page 8.

In the 2024 final rule, in addition to the NHV requirements described in this section, the EPA also finalized performance testing requirements for ECDs applicable to well, centrifugal compressor, reciprocating compressor, storage vessel, process controller, pump, or process unit equipment affected facilities. These performance test requirements consist of a minimum of 3 test runs at least 1 hour long at the inlet of the first control device and at the outlet of the final control device to determine compliance with a total organic compound (TOC) percent reduction requirement of 95.0 percent by weight or greater, or reduce the concentration of TOC in the exhaust gases at the outlet to the control device to a level equal to or less than 275 ppmv as propane on a wet basis corrected to 3 percent oxygen.

According to reconsideration petitioners, the performance testing provisions for ECDs are currently untenable for NSPS OOOOb control devices. Due to the sheer volume of ECDs that require testing under NSPS OOOOb, coupled with the limited number of specialized source testing firms that are available to perform these tests, the petitioners stated that additional time is needed to conduct performance testing for ECDs at affected facilities constructed, modified, or reconstructed since December 6, 2022. The petitioners also expressed concerns over the workload and backlog for the EPA or delegated state and local authorities to process alternative performance testing requests for potentially hundreds of ECD test programs. The petitioners credibly asserted that relying on delegated authorities to address performance testing issues provides no solution on most tribal lands, where the EPA is often the sole agency responsible for implementing NSPS OOOOb. [^23] Petitioners stated that while owners and operators utilizing ECDs to comply with standards in a state or Federal plan under EG OOOOc will likely have years to address these challenges, these performance testing issues present an immediate and untenable scenario for NSPS OOOOb control devices.

[^23] See EPA-HQ-OAR-2024-0358-0009 at page 5.

The petitioners expressed additional concerns over the amount of time required ( *i.e.,* minimum test run duration) and the need for supplemental gas to conduct three 1-hour test runs on sources that have intermittent flow ( *e.g.,* storage vessels). A testing crew is typically able to conduct up to two performance tests per day where vapor flow is sufficient. Where vapor flow is low and/or intermittent, as can be the case for many storage vessels, it may take multiple days of waiting to find a window with sufficient flow to accommodate a 1-hour test run, and in many cases, there will never be sufficient vapor flow to accommodate a 1-hour test run under normal operating conditions. Therefore, petitioners stated, performing these tests as prescribed in the 2024 final rule is not always feasible.

Additionally, petitioners stated the installation of monitoring equipment or sampling ports on existing ECDs requires specialized “hot tap” work. A “hot tap” requires specialized vendors and a site shutdown to perform this work. This work exacerbates the already challenging compliance timeline given the existing supply chain constraints, which will prevent most affected facilities from obtaining the necessary monitoring equipment, and the large number of needed retrofits. [^24] Therefore, petitioners said this work cannot be accomplished across the industry prior to the deadline for compliance demonstrations.

[^24] See EPA-HQ-OAR-2024-0358-0009 at page 2 and attachment 1 to the petition.

In this action, the EPA is extending the compliance dates related to NHV monitoring of flares and ECDs found in 40 CFR 60.5417b(d)(8)(i) through (iv) and (vi) by 120 days from publication of this interim final rule to address the supply chain, personnel, and laboratory limitations identified by petitioners which make compliance with the requirements promulgated in the 2024 final rule infeasible. On January 15, 2025, the EPA proposed amendments to the NSPS and EG related to NHV requirements based on reconsideration petitions. The Agency is working towards finalizing those amendments and expects a final rule to be issued soon. Because a separate rulemaking action will address the substantive problems raised with the NHV provisions in the 2024 final rule, we have determined that an extension to November 28, 2025 is sufficient for present purposes. The EPA solicits comments on this extension of 120 days.  If, based on comments or otherwise, additional adjustment to the compliance timeline for the NHV requirements is needed, the EPA may address that issue via additional amendments following this action, including potentially in the separate reconsideration action.

Additionally, the EPA is extending the requirement to conduct performance tests on ECDs in 40 CFR 60.5413b(b) until January 22, 2027 to provide affected facilities sufficient lead time to retrofit sources and to plan and execute the performance tests required by the final rule. The EPA notes that even though the Agency is extending the deadline to complete the prescribed NHV monitoring on these source types, the visible emission observation requirements of 40 CFR 60.5417b(d)(8)(v) will continue to apply in order for sources to demonstrate compliance with the prescribed emission standards as of the 2024 final rule effective date of May 7, 2024, or 180 days after startup, whichever is later, as required in 40 CFR 60.5370b(a)(9)(ii).

**2. Covers and Closed Vent Systems**

As in NSPS OOOO and OOOOa, NSPS OOOOb contains requirements for closed vent systems (CVS) and covers. [^25] CVS route emissions from well ( *i.e.,* oil wells when routing associated gas to a control device), centrifugal compressor, reciprocating compressor, process controller, pump, storage vessel and process unit affected facilities to a control device or to a process. Pursuant to the 2024 final rule, each CVS used for compliance with an NSPS OOOOb standard must be designed and operated to capture and route all gases, vapors, and fumes to a process or to a control device with “no identifiable emissions” (NIE) and these systems must be inspected within 30 days of startup of the affected facility and annually thereafter to verify 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.

[^25] Also, as in NSPS OOOOa, CVS and covers that are not associated with an affected facility are fugitive emissions components.

Under the final 2024 rule, initial and continuous compliance of the NIE requirement can be demonstrated through OGI, EPA Method 21, or audio, visual and olfactory inspections (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 requirement for covers and CVS using the periodic screening or continuous monitoring requirements for advanced methane detection technologies in 40 CFR 60.5398b. Where AVO inspections are required, the CVS and cover are determined to operate with NIE if no emissions are detected by AVO means. Where OGI monitoring is conducted, the CVS and cover are determined to operate with NIE if no emissions are imaged by the OGI camera. Where EPA Method 21 monitoring is conducted, the CVS and covers are 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 requirement until a subsequent inspection determines that the CVS and cover operate with NIE. Where monitoring is conducted using advanced methane detection technologies, covers and CVS are determined to operate with NIE if no emissions are detected by the periodic screening survey or, where continuous monitoring is conducted, the site remains under the action levels. If emissions are detected from the site during a periodic screening survey or the site exceeds an action level, the cover and CVS are still determined to operate with NIE unless a follow-up inspection with EPA Method 21, OGI, or AVO indicates that the cover and CVS do not operate with NIE.

Each CVS must be inspected to ensure that the CVS operates with NIE initially within 30 calendar days after startup of the affected facility routing emissions through the CVS. 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 CVS must be conducted and certified by a qualified professional engineer or inhouse 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. Owners and operators may designate parts of the CVS as unsafe to inspect or 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.

As to this set of issues, the reconsideration petitioners have credibly asserted that it is not technically achievable over the long-term to maintain NIE compliance with these systems. [^26] They state that fugitive emissions will occur over time due to normal wear and tear during typical operation of the equipment and leak  detection and repair (LDAR) programs are typically designed to allow operators to address them promptly and responsibly. [^27] The petitioners state that affected facilities will not be able to prevent inevitable minor fugitive emissions from covers and CVS, and thus the requirement to achieve and maintain NIE is untenable. According to the petitioners, this unrealistic requirement will inevitably yield widespread non-compliance with the NIE requirements in the 2024 final rule due to normal operation of these affected sources because detected leaks are treated as deviations without first allowing for repair. [^28] These concerns related to compliance with a requirement viewed as unworkable have been reiterated by stakeholders in subsequent meetings with the EPA. <sub>29 30</sub>

[^26] See EPA-HQ-OAR-2024-0358-0009 at page 7.

[^27] See EPA-HQ-OAR-2024-0358-0012 at page 1.

[^28] See EPA-HQ-OAR-2024-0358-0013 at page 14.

[^29] See EPA-HQ-OAR-2024-0358-0046 at page 16.

[^30] See EPA-HQ-OAR-2024-0358-0023 at page 16.

In this action, the EPA is extending the compliance date for NIE requirements until January 22, 2027. Based on information received since promulgation of the 2024 final rule, the EPA has serious concerns regarding the ability of owners/operators to meet the NIE inspection requirements in the 2024 rule on the existing compliance schedule and finds it necessary, appropriate, and in the public interest to extend the compliance deadline given credible workability concerns. We note that other compliance requirements for affected facilities that would otherwise be subject to NIE requirements continue to apply consistent with the substantive requirements and goals of the 2024 final rule. In other words, owners and operators still must design and install a CVS and perform initial and ongoing inspections to ensure that the system has no leaks consistent with the requirements of the 2024 final rule and repair any leaks that are found within 30 days. The only requirements that are being delayed are the inspections to confirm that systems operate with NIE during which identifying a leak would be considered a deviation of the standard.

**3. Equipment Leaks**

In the 2024 final rule, the EPA promulgated requirements for equipment leaks that included provisions for repairs when equipment leaks are detected. For each valve where a leak is detected, regulated entities must comply by repacking the existing valve with a low emitting (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. [^31] 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 the following: retrofit requirements for installation ( *e.g.,* re-piping or space limitation), commercial unavailability for valve type, or certain instrumentation assemblies.

[^31] The 2024 final rule includes the following definitions: *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.

Reconsideration petitioners have credibly asserted that requiring replacement of leaking valves with low-E valves without first providing an opportunity for an attempt at repair of the existing valve is technically and economically infeasible, did not follow proper notice and comment requirements, and creates confusion regarding when replacement is considered feasible in an enforcement proceeding. [^32] Based on cost estimates provided in the petitions for reconsideration, petitioners claim that such equipment (low-E valves and packing) is not commercially available at costs that make widespread replacement of valves with low-E equipment viable across the industry.

[^32] See EPA-HQ-OAR-2024-0358-0013 at pages 7-11.

The EPA acknowledges that regulatory language in the 2024 final rule introduced unintended compliance difficulties related to equipment leak repair requirements. As currently written, the regulatory language in 40 CFR 60.5400b(h)(2)(ii)(A) appears to require a source to repack an existing valve with low-E packing, and then the language is unclear as to whether a source must also comply with paragraph (B) or (C), which require that they either replace the valve with a low-e valve or perform a drill and tap repair with a low-E injectable packing, respectively. It was not the EPA's intention to require that a source repack an existing valve and replace that valve during the same repair. Furthermore, the CFR erroneously includes two versions of paragraph 60.5401b(i). The EPA discovered since promulgation of the 2024 final rule that these two copies of the repair requirements paragraph differ and create confusion for affected facilities. The first of the two copies included in the CFR is correct while the second contains similar errors to those present in 40 CFR 60.5400b(h)(2)(ii). In order to alleviate the compliance confusion created by the conflicting regulatory language, and to provide potentially affected sources additional time to undertake planning to obtain needed low-e equipment given the cost and widespread need for such equipment, the EPA is extending the compliance date for equipment leak repair requirements contained in 40 CFR 60.5400b(h)(2)(ii) and 60.5401b(i)(2)(ii) until January 22, 2027 or 180 days after startup of the affected source, whichever is later.

**4. Process Controllers**

Process controllers are automated instruments used for maintaining a process condition, such as liquid level, pressure, pressure difference, or temperature. Historically, in the oil and gas industry, many process controllers were powered by pressurized natural gas and therefore would 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. In the December 2022 Supplemental Proposal, the EPA proposed a “zero emissions” VOC and methane standard for most process controllers in NSPS OOOOb and a “zero emissions” methane presumptive standard for most process controllers 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 2024 final rule includes the “zero emissions” VOC standard proposed in December 2022 along with different standards for process controllers in Alaska at locations where access to electrical power from the power grid is not available. The requirements for these sources in Alaska are to use lower emitting natural gas-driven process controllers and to perform inspections to ensure that they are operating properly.

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

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 methane. Zero emissions of VOC and methane 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 CVS 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 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 methane. 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. Further, as an 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 of the March 2024 final rule preamble (89 FR 16882) summarizes the emissions standards for process controllers.

Based on comments the EPA received in 2022 and 2023 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 finalized a NSPS compliance deadline for process controllers that allows up to 1 year from the effective date of the final rule 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. See 89 FR 16929-30.

According to reconsideration petitioners, in the 2024 final rule, existing sites that trigger the OOOOb modification provisions, and thus become subject to the NSPS, have to convert all process controllers in a process controller affected facility to comply with the zero-emission standard by May 7, 2025, or upon modification, whichever is later. Reconsideration petitioners have credibly asserted that this will place a significant demand on the equipment, supplies, and service vendors during the compliance time frame and add more strain to a supply chain that currently requires 12-18 months to deliver certain types of components necessary for the conversion of large natural gas driven controllers to an air driven system. [^33] According to petitioners, if an operator is unable to complete the conversion due to reasons beyond its control, the operator will have to make a decision whether to continue operating, potentially in a non-compliant state; or shut down that compressor station, thereby reducing its ability to move gas during peak demand periods, pursuant to their Federal Energy Regulatory Commission approved tariffs. [^34] Petitioners also state that the EPA's regulatory language is ambiguous and creates confusion regarding the types of processes potentially subject to the standards. Specifically, petitioners have credibly asserted that the 2024 final rule is unclear with respect to whether certain high-pressure applications are included in the scope of the regulations. [^35] Therefore, even more sources may require the equipment necessary to achieve the zero emissions standard which puts even more demand on a limited supply, resulting in further compliance delays that EPA did not intend to create in promulgating the 2024 final rule.

[^33] See EPA-HQ-OAR-2024-0358-0014 at page 10.

[^34] See EPA-HQ-OAR-2024-0358-0014 at page 10.

[^35] See EPA-HQ-OAR-2024-0358-0043 attachment 2 at page 4.

In this final action, the EPA is extending the second phase of the phased-in compliance deadline for the zero emission standards applicable to process controllers to January 22, 2027 to address the supply chain and logistical issues raised by petitioners. The EPA has determined that the additional compliance time is needed to ensure that sufficient equipment can be sourced, obtained, and installed in timelines that are achievable by affected sources. In the meantime, consistent with the substantive provisions and goals of the 2024 final rule, the interim standard continues to apply to process controller affected facilities ( *i.e.,* the same standard applicable to sites in Alaska without access to electricity).

**5. Storage Vessels**

In the 2024 final rule, the EPA promulgated requirements that defined a storage vessel affected facility as a tank battery that has the potential for VOC emissions equal to or greater than 6 tons per year (tpy) or methane emissions equal to or greater than 20 tpy. 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 non-earthen 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. The 2024 final rule includes language in 40 CFR 60.5365b(e)(ii) that describes how a source should determine the potential emissions from storage vessels. Specifically, the final rule states that 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.

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 vapor recovery unit (VRU). For storage vessel affected facilities not at a well site or centralized production site, and without potential for flashing emissions, owners and operators may choose to comply by using an internal or external floating roof to reduce emissions in accordance with 40 CFR part 60, subpart Kb (NSPS for Volatile Organic Liquid Storage Vessels). The rule allows removal of a control device from a storage vessel affected facility if the owner or operator maintains the uncontrolled actual VOC emissions at less than 4 tpy and the actual methane emissions at less than 14 tpy as determined monthly for 12 consecutive months.

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 CVS which route all emissions to a process or one or more control devices. Owners and operators of 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 the March 2024 final rule preamble (89 FR 16963) and information regarding covers and CVS may be found in section X.K of the March 2024 final rule preamble (89 FR 16984).

The EPA finalized an affected facility-specific definition of “modification” for storage vessels to include specific physical changes that trigger the modification requirements. Those changes include 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 defined “reconstruction” for OOOOb storage vessels 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.

Further, in the 2024 final rule, the EPA finalized criteria that must be met for a permit limit or other requirement to qualify as a legally and practicably enforceable (LPE) limit for purposes of determining whether a tank battery is an affected or designated facility under NSPS OOOOb or EG OOOOc, respectively. The 2024 final rule established that a LPE 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.

Reconsideration petitioners have raised concerns with provisions related to how sources determine potential emissions, [^36] the triggers for modification, and the specific criteria for limits on potential to emit to be considered LPE. [^37] Some reconsideration petitioners credibly asserted that the applicability determination language in 40 CFR 60.5365b(e)(2)(ii) is ambiguous for tanks that commenced construction, modification, or reconstruction after the date of the supplemental proposal (December 6, 2022) and prior to the OOOOb effective date (“pre-effective date tanks”), May 7, 2024. [^38] The petitioners also stated that it is unclear what “30-day period of production” operators must use to determine the maximum average daily throughput to calculate the potential for VOC and methane emissions for pre-effective date tanks. [^39] Without clarification, operators may not know with certainty the scope of affected storage vessels that must comply with OOOOb by the compliance deadline. The petitioners also credibly asserted that requiring a determination earlier than the OOOOb effective date imposes compliance obligations before they are effective. Additionally, the petitioners stated this is compounded by defining a “legally and practicably enforceable limit,” which effectively eliminated the ability to rely on permit limits for applicability determinations under OOOOb. Stakeholders have continued to reiterate these concerns in further discussions with the EPA. [^40] Petitioners further stated that the LPE requirements apply to storage vessels for which states do not have the authority or mechanisms to apply such limits in permits. [^41]

[^36] See EPA-HQ-OAR-2024-0358-0043 at page 17.

[^37] See EPA-HQ-OAR-2024-0358-0016 at pages 2-4.

[^38] See EPA-HQ-OAR-2024-0358-0009 at page 7.

[^39] See EPA-HQ-OAR-2024-0358-0010 at page 5.

[^40] See EPA-HQ-OAR-2024-0358-0046 at page 15.

[^41] See EPA-HQ-OAR-2024-0358-0043 attachment 2 at page 5.

According to petitioners, the expansive storage vessel modification provisions will immediately and automatically trigger new source requirements for tens of thousands of tanks and tank batteries (far more than the EPA predicted when formulating those provisions). The EPA agrees that the modification provisions finalized in 2024 contain a degree of vagueness such that it is possible that far more midstream storage vessels could trigger modification than the EPA estimated in the 2024 final rule. We did not anticipate that these provisions would affect the large number of sources cited by petitioners and agree that additional compliance time is needed for the large number of potentially affected sources.

The petitioners also stated the EPA should allow more time than afforded in the 2024 final rule to allow state, local, and tribal agencies to adopt and implement conformant LPE limits. The EPA is extending the date for the specific provisions required for a limit to be considered LPE limits in 40 CFR 60.5365b(e)(2)(i)(A)-(F) until January 22, 2027. This action will ensure there is enough time for sources to work with delegated authorities to establish limits that are LPE without foreclosing the use of LPE limits already established that may or may not contain the same level of specificity as the requirements in NSPS OOOOb during that time. Additionally, the EPA is extending the date at which the throughput-based modification triggers become effective by 18 months in order to provide time for the potentially large number of sources that would trigger those provisions to make any needed adjustments to facility planning, equipment procurement, and process changes needed to comply with the requirements. Finally, the EPA is extending the date by which sources must calculate potential emissions using the 30-day period of production by 18 months to allow facilities to obtain additional information and make the requisite decisions related to their facilities that may be subject to these requirements. We note that until the provisions that we are extending come into effect, there are still provisions in place that establish what other activities constitute a modification, *i.e.,* sources that add an additional vessel or replace a vessel with one that has increased capacity still trigger modification. Sources are still required to determine the potential emissions from storage vessels. The only change to these provisions is that, in the interim period, sources need not use the (confusing) 30-day period of production calculation  and limits on potential emissions can be considered LPE with or without the specific criteria included in the 2024 final rule. Any sources that do trigger modification provisions will still be subject to the standards in the 2024 final rule and this action does not change those standards.

**6. Super Emitter Program**

The EPA included the Super Emitter Program (SEP) in the 2024 final rule, previously proposed as the Super Emitter Response Program in the December 2022 Supplemental Proposal. For purposes of the 2024 final rule, a “super emitter event” is defined as any emissions event that is located at or near an oil and natural gas facility and that is detected using remote detection methods and has a quantified emission rate of 100 kg/hr of methane or greater.

As described in the preamble to the 2024 final rule, this program was designed to provide a mechanism by which the EPA would provide owners and operators with timely notifications of super-emitter emissions data collected by EPA-certified third parties using EPA-approved remote sensing technologies. See 89 FR 16877. Where such an event is attributable to an oil or natural gas 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 would take action in response to such notifications in accordance with the applicable regulation. *Id.* Section X.C of the 2024 final rule preamble describes the SEP in detail. See 89 FR 16876.

In implementing this novel program, the EPA has experienced unanticipated difficulties and concerns that require additional time for effective and lawful administration of various program procedures. [^42] For example, while the rule requires a third-party notifier to provide a significant amount of information regarding a super emitter event as part of submitting a notification of the event to the EPA, the attribution of who owns or operates a site is not a required element. While the EPA has developed tools to aid certified third parties in the attribution of identified events, in limited practice, the certified third parties that have submitted information to date have chosen not to include an owner/operator attribution in the submitted notification. In the absence of this information, to meet the program's goals of providing the submitted information about these events to the owners or operators of the appropriate facilities, the EPA must itself determine and then confirm the owner/operator attribution. This process has proven time- and labor-intensive and generated unanticipated concerns about improper attribution and related consequences for enforcement and compliance efforts more generally.

[^42] See EPA-HQ-OAR-2024-0358-0010 at 27-32.

Though the super-emitter program has thus far received relatively few submittals of notifications of super-emitter events from a certified third party, we expect that the number of submittals would grow extensively if more cost-effective technologies were approved ( *e.g.,* satellite sensors). With the potential increase in the number of submitted notifications, the EPA's ability to provide timely notification of these events to the facility owner or operator would be hampered given the existing challenges identified in determination attribution for each owner or operator. Similarly, if the number of notifications that the EPA receives based on the currently approved remote-sensing technology were to substantially increase, the EPA's ability to timely provide the notification to the appropriate owner and operator would be constrained by the EPA's ability to make and confirm the owner or operator attribution. These limitations would lead to delays in providing notifications to the appropriate owner or operator that are inconsistent with the program's design and intended function. A central element of the program's design is to provide information about these emissions events in a timely fashion to the appropriate owners and operators, so that they can quickly conduct the investigations into the event required under the rule and take any necessary corrective action if the source is subject to the rule. Delays in providing the notifications to owners and operators would result in the information being stale when received, or superseded by intervening events, limiting both the value of information that could be discovered through the required investigation and the opportunity to take corrective action.

Additionally, implementation of the program to date indicates that application of this program has been broader than the EPA anticipated in promulgating the 2024 final rule. For instance, part of the definition of a super-emitter event under 40 CFR 60.5371b is that the event be located at or near an oil and natural gas facility. In limited practice, this definition has resulted in the EPA receiving notifications of an event at a downstream production site not subject to any upstream oil and gas regulation. Specifically, a notification was provided to a renewable fuel refinery in Bakersfield, California on January 21, 2025. Though this facility is within an oil and gas production basin and an emission was detected from the site, it does not appear to be the type of oil and gas facility that the EPA intended to cover in the SEP. This distinction is important since these types of emissions are likely tied to short-term process conditions which are typical at downstream production sites. While the program requires the EPA to review the submitted notifications of super-emitter events for completeness and accuracy, it does not allow the EPA the discretion to not post or provide a notification to an owner or operator identified in the notification for other reasons, such as the EPA's judgment on the appropriateness of a notification. In the absence of such discretion, the EPA is required to provide a notification to an owner or operator of who is identified in the notification, so long as the EPA had reviewed the notification and determined that it is complete and does not contain information that the EPA finds to be inaccurate to a reasonable degree of certainty, even if other reasons might counsel against providing the notification, such as when that site has already received a notification of a particular emissions event, or if the EPA has determined that a notification relates to an emissions event that is not regulated or prohibited under the EPA's oil and gas rules.

For these reasons, the EPA is extending the date for future implementation of the super-emitter program until January 22, 2027. This extension also impacts the timing for EPA action on methane detection technology under 40 CFR 60.5398b(d)(1)(iii) for use in the SEP. Because the EPA is extending the date for future implementation of the SEP, there is no need for the EPA to act on submissions of remote-detection technology for use in the program in the intervening period. Therefore, the EPA is extending the provisions that include conditional approval of methane detection technology for use in the SEP that occurs if the EPA does not act on submissions of those technologies by the timelines prescribed by the rule until January 22, 2027.

**7. Flare Pilot Flame and Alarm Requirements**

In the 2024 final rule, the EPA finalized requirements that all enclosed combustion devices, other than boilers and process heaters, that introduce the vent stream with the primary fuel into the flame zone or use the vent stream as the primary fuel, as well as all catalytic  incinerators, that operate above a minimum flow rate established by the manufacturer must install and operate a continuous burning pilot or combustion flame. Additionally, the combustion devices must have a way to alert the nearest control room whenever the pilot or combustion flame is unlit.

The 2024 final rule also requires that all flares ( *e.g.,* unassisted, pressure-assisted, and steam-assisted) have a continuous burning pilot or combustion flame and have a system that provides an alert to the nearest control room whenever the pilot or combustion flame is unlit. 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 used to comply with the standards 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. The 2024 final rule requires that if owners and operators use certain flares and enclosed combustion devices to comply with the standards, they must install a system to send an alarm to the nearest control room if an unlit pilot flame is detected on a flare or enclosed combustion device. 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, including 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. Using 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, if approved by the EPA, would be used in lieu of the other monitoring required for combustion device ( *e.g.,* vent gas NHV, flow rate).

In addition to information that must be reported, owners and operators must keep records of continuous compliance with the monitoring requirements, including information about the pilot flame being lit, CPMS limits, CPMS hourly and average values, and results of visible emissions observations or surveillance camera feed.

Petitioners have raised concerns that the 2024 final rule requirements for continuous pilot flames pose significant logistical challenges. These challenges relate to providing supplemental fuel to maintain a continuous pilot flame at intermittently operating processes for affected facilities that are located far from reliable sources of such fuel. [^43] Petitioners have also described challenges in obtaining and installing communications equipment capable of reliably transmitting an alarm to the nearest control room. [^44] Due to the large number and remote geographic location of many flares and enclosed combustion devices used to achieve compliance with the EPA's standards, industry requires additional time to prepare and install needed equipment to maintain continuous pilot flames that alarm in the nearest control room when the pilot is unlit. Therefore, in this action, we are extending the date by which owners and operators who utilize these flares and enclosed combustion devices must: (1) ensure that flares and enclosed combustion devices operate with a continuous pilot flame, and (2) install and operate a system to send an alarm to the nearest control room when a pilot flame is unlit to 18 months from publication of this interim final rule. The emission reduction requirements for flares and enclosed combustion devices and the other monitoring of such devices described above are not affected by this extension. Put another way, during this extension owners and operators are still required to ensure that emissions being routed to a flare or enclosed combustion devise are reduced by 95.0 percent, and there are still other applicable requirements in the 2024 final rule to ensure compliance.

[^43] See EPA-HQ-OAR-2024-0358-0010 at page 13.

[^44] See EPA-HQ-OAR-2024-0358-0010 at page 13-14.

**C. Deadline Extensions for EG OOOOc**

**1. State Plan Submittal Deadline**

In the 2024 final rule, the EPA finalized a state plan submittal deadline of 24 months after publication of the final EG OOOOc (March 9, 2026). [^45] While the EPA did not receive any petitions for reconsideration on this deadline, since the rule was finalized, the EPA has regularly engaged with various states regarding their concerns. For example, one state has informally asked their respective EPA Region for an extension of the state plan submittal deadline; other states have been inquiring as to the consequences of late state plan submissions. These compliance assistance efforts from the EPA to the states prompted the EPA to assess the status of the state plan submittals. This assessment has led the EPA to determine that states planning to submit state plans need additional time to develop their plans to achieve the emissions-reduction goals of the 2024 final rule in an effective and efficient manner.

[^45] See 89 FR 17010.

The EPA expects approximately 21 states to submit state plans. Since publication of the 2024 final rule, states should now be approximately halfway completed with the plan development process because state plans are due on March 9, 2026; in other words, we are over 1 year into the 2-year time allowance. For those states relying entirely or mostly on the EPA's model rule included in the final EG without modification, the EPA would expect states to have completed, or be near completing, at least some of the following development milestones: (1) Conduct and document meaningful engagement with pertinent stakeholders pursuant to 40 CFR 60.5363c(a)(6) and 60.23a(i); (2) identify the types of designated facilities within the state that will be covered by the state plan; (3) produce a draft of major portions of the state plan, including standards of performance, compliance schedules, increments of progress, and compliance assurance measures, incorporating relevant sections of the model rule in EG OOOOc; (4) determine and/or draft enforceable regulatory mechanisms to implement the state plan ( *e.g.,* general permits, state regulations, etc.); and (5)  notice the draft state plan for public comment in accordance with state laws.

Further, for those states not relying predominantly on the model rule but which are instead leveraging pre-existing state programs and/or invoking remaining useful life and other factors (RULOF) to apply less stringent standards than the presumptive standards in EG OOOOc, the EPA would expect states to have completed, or be near completing, at least some of the following milestones: (1) Conduct and document meaningful engagement with pertinent stakeholders; (2) identify the types of designated facilities within the state that will be covered by the state plan; (3) compile and compare all relevant pre-existing state regulations (or statutes, permits, or other legal authorities) to corresponding coverage of EG OOOOc and determine which state regulations to leverage for purposes of satisfying state plan obligations; (4) determine changes necessary, if any, to harmonize pre-existing state regulations with state plan requirements of EG OOOOc ( *e.g.,* changes to designated facilities, designated pollutants, types of standards, etc.); (5) conduct and document analyses to demonstrate equivalency between pre-existing state regulations and EG OOOOc in terms of emissions reductions; (6) begin state rulemaking process to make changes to existing state regulations, if any are necessary; (7) collect and document information to support RULOF demonstrations, if any, for less stringent standards (or longer compliance schedules) than those in EG OOOOc; (8) determine alternative standards to apply in any case where invoking RULOF; and (9) draft other portions of the state plan (those not leveraging pre-existing state regulations and/or invoking RULOF).

The EPA, however, has identified twelve states that have yet to identify how they plan to implement EG OOOOc. Several of these states are still seeking to identify all the potentially impacted facilities within their borders before deciding whether to develop a state plan. The EPA has also identified that 18 of 21 states intending to submit a state plan have yet to share significant portions of those plans with the EPA for feedback. The EPA expects approximately nine states to leverage at least some pre-existing state regulations to satisfy state plan obligations. While at least four states have identified some revisions necessary to harmonize their pre-existing programs with EG OOOOc, the EPA is aware of no state that has begun its rulemaking process to undertake those revisions. Additionally, while the EPA has received numerous questions from states concerning demonstrating equivalency between pre-existing state regulations and EG OOOOc in terms emissions reductions, the EPA has not received any draft analyses for such demonstrations for review. Similarly, while the EPA currently expects approximately five states to invoke RULOF to apply less stringent standards to certain designated facilities, and while the EPA has received numerous questions from states concerning RULOF demonstrations, the EPA has yet to receive any draft RULOF demonstrations for review. The EPA outlines this information in table 2 below. This demonstrates that many states are struggling to develop their plans on the schedule that the 2024 final rule requires.

| Status | States |
| --- | --- |
| I. EPA-Approved State Plans | None. |
| II. Anticipated Negative Declarations to be Submitted to the EPA | Hawaii, American Samoa, Guam. |
| III. Negative Declaration Submitted/EPA Approved | Vermont (submitted), Puerto Rico (submitted), District of Columbia (submitted). |
| IV. Anticipated State Plans to be Submitted to the EPA | Maine, New York, Delaware, Maryland, Pennsylvania, Virginia, West Virginia, Georgia, South Carolina, Tennessee, Arkansas, New Mexico, Oklahoma, Texas, Colorado, Montana, North Dakota, Utah, Wyoming, Arizona, California. |
| V. Anticipated State Plans Leveraging Pre-Existing State Programs to be Submitted to the EPA | New York, Maryland, New Mexico, Colorado, Montana, North Dakota, Utah, Wyoming, California. |
| VI. Anticipated State Plans Invoking RULOF to be Submitted to the EPA | Tennessee, Arkansas, Oklahoma, Texas, California. |
| VII. Final State Plans Submitted to the EPA | None. |
| VIII. Draft State Plans Submitted to the EPA | Pennsylvania (partial), West Virginia (partial), Montana (partial). |
| IX. EPA Has Not Received a Draft or Final State Plan or Negative Declaration | Maine, New York, Delaware, Maryland, Virginia, Alabama, Florida, Kentucky, Mississippi, North Carolina, Georgia, South Carolina, Tennessee, Illinois, Indiana, Michigan, Minnesota, Ohio, Arkansas, Louisiana, New Mexico, Oklahoma, Texas, Missouri, Colorado, Montana, North Dakota, Utah, Wyoming, Arizona, California, Hawaii, American Samoa, Guam. |
| X. Anticipated Federal Plan Promulgation | Connecticut, Massachusetts, New Hampshire, Rhode Island, New Jersey, Wisconsin, Iowa, Kansas, Nebraska, South Dakota, Nevada, Alaska, Idaho, Oregon, Washington. |

The EPA acknowledges this delay in meeting expected informal state plan development milestones could be because of various factors, including several that the EPA acknowledged in the 2024 final rule. However, the EPA has determined that the practical reality of states identifying impacted sources and pertinent stakeholders, conducting meaningful engagement, comparing pre-existing state programs to EG OOOOc, and producing RULOF demonstrations has proven to be more time-consuming than we expected because of various challenges faced by states. These challenges stem from both the relatively large and complex nature of the source category, the corresponding complexity associated with applying EG OOOOc to designated facilities, and states' lack of familiarity with the newly revised general implementing regulations. <sup>46</sup> States are understandably taking more time than the EPA initially expected as they navigate these multiple challenges, including through iterative questions for and discussions with the Agency.

[^46] EG OOOOc represents the first time states will be implementing the requirements promulgated in  the revisions to 40 CFR part 60, subpart Ba (subpart Ba), the implementing regulations for the adoption and submission of state plans. 88 FR 80480.

Moreover, implementing some of these requirements in the context of EG OOOOc in particular is proving to be more complex than originally anticipated. For example, the new requirement to submit documentation of meaningful engagement pursuant to 40 CFR 60.23a(i) has proven time consuming due to the large number of geographically dispersed designated facilities in some states, covering multiple industry segments. States have faced challenges determining the appropriate scope, form, and number of engagement activities, as well as identifying pertinent stakeholders and owners and operators. States have also communicated to the EPA that the relatively complicated technical nature of EG OOOOc has presented obstacles to fostering public participation at engagement activities.

Similarly, states are needing more time than anticipated to invoke RULOF to apply less stringent standards (or longer compliance schedules). [^47] For example, due to the large number of EG OOOOc designated facilities, some states have undertaken the task of attempting to segment designated facility types into classes for purposes of RULOF. Given the number and diverse circumstances of designated facilities in the source category, collecting enough information on facility operations necessary to determine appropriate classes and associated standards has proven difficult and time-consuming. For similar reasons, states have confronted difficulties with quickly collecting the full complement of relevant data on emissions and costs to demonstrate fundamental differences between the information specific to those facilities (for which the states are invoking RULOF) and the information the EPA considered in determining the presumptive standards in EG OOOOc.

[^47] See 40 CFR 60.24a(e)-(h); 88 FR 80508-80528.

While the EPA provided flexibility to states with pre-existing regulatory programs for the oil and natural gas industry to leverage those programs for the purposes of state plan submission, the scope and stringency of those programs varies considerably, each posing unique issues regarding demonstrating equivalency or harmonizing with EG OOOOc. Analyses to compare the stringency of pre-existing standards and their associated compliance assurance measures to EG OOOOc have proven to be complicated and time-consuming, especially for those presumptive standards that are expressed in a non-numerical format in EG OOOOc. Administrative complexities have also arisen for several states attempting to concurrently revise associated state rules for Reasonably Available Control Technology in their State Implementation Plans (SIP) for CAA sections 182 and/or 184, in order to maintain a single set of requirements for the oil and natural gas sources in those states.

These challenges have increased the time needed to develop state plans beyond the EPA's expectations. The EPA has worked to provide assistance to states along the way. The EPA has made information publicly available in efforts to helps states including a document summarizing requirements for state plans [^48] and answers to frequently asked questions about the 2024 final rule. [^49] Additionally, the EPA notes that states have returned multiple times to their Regional offices and the EPA's Office of Air Quality Planning and Standards for numerous meetings to get dozens of complex implementation questions answered, many of which require the coordinated weeks-long effort of multiple EPA staff members to respond to.

[^48]*https://www.epa.gov/system/files/documents/2024-08/ooooc-summary-of-requirements-for-state-plans-final-8-23-2024.pdf.*

[^49]*https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/frequently-asked-questions-about-epas.*

Based on the information the EPA currently has, the EPA anticipates the vast majority of states intending to submit state plans will be unable to meet the current state plan submittal deadline of March 9, 2026. If a state does not submit a state plan within the prescribed time, the EPA is obligated to promulgate a Federal plan within twelve months of the submittal deadline. [^50] The EPA does not find it appropriate to maintain a state plan submittal deadline that we now have reason to believe is untenable for most states intending to submit state plans. The EPA does not wish to set these states up to fail, especially when they have been diligently working to try to meet the submittal deadline. Extending the submittal deadline will enable states to devote suitable time and resources to developing approvable plans that meet all applicable requirements and achieve the objectives of the states and their stakeholders. In contrast, pressing forward on the existing deadline could needlessly embroil states and the EPA in disputes over untimely or insufficient submissions, thereby triggering administrative processes and litigation that detract from implementation of the emission guidelines and could be avoided with a targeted extension.

[^50] 40 CFR 60.27a(c). The EPA's obligation to promulgate a Federal plan is removed if the state submits, and the EPA approves, a state plan before the EPA issues a Federal plan.

In this action we are extending the deadline for state plan submittal until January 22, 2027 for the reasons discussed in this section. This gives states additional time from their current deadline in March 2026.

**III. Rulemaking Procedures**

As noted in section I.C. of this preamble, the EPA's authority for the rulemaking procedures followed in this action is provided by APA section 553(b)(B), which allows an agency to forgo notice-and comment requirements “when the Agency for good cause finds (and incorporates the finding and a brief statement of reasons, therefore, in the rule issued) that notice and public procedure thereon are impracticable, unnecessary, or contrary to the public interest.” [^51] The EPA finds good cause to forego prior notice and comment because that rulemaking procedure is impracticable and unnecessary under the circumstances.

[^51] Although the procedural requirements of CAA section 307(d) apply to the EPA's promulgation or revision of any standard of performance under CAA section 111, these procedural requirements do not apply “in the case of any rule or circumstance referred to in subparagraphs (A) or (B) of [APA section 553(b)].” 42 U.S.C. 7607(d)(1).

The EPA finds that prior notice and comment is unnecessary because the EPA is making only targeted changes to certain compliance or implementation dates in response to immediate concerns raised by stakeholders, including owners and operators subject to the rule's requirements. For the reasons described in more detail in section II of this preamble, certain regulatory provisions have created unintended compliance difficulties unrelated to the actual emissions standards and other requirements of the underlying regulations. This targeted action provides subject facilities the additional time needed to resolve these specific compliance and implementation problems without disrupting the sequencing of the compliance deadlines in the final rule or risking interim noncompliance proceedings. The EPA believes the targeted deadline revisions in this action do not interfere with, or unreasonably frustrate, the ultimate emission reduction requirements of the rule. To the extent interested parties  raise concerns about this action or any particular deadline amendment made therein, the EPA will carefully review any comments submitted on this action and consider whether changes are appropriate after close of the comment period.

In addition, the EPA finds that prior notice and comment would be impracticable given the applicable compliance deadlines and the timeline involved in completing such procedures. The EPA has determined through ongoing communications with stakeholders and review of the relevant regulatory language that there are legitimate barriers to compliance and/or questions as to whether the regulatory provisions for which we are extending compliance deadlines are practically and logistically achievable as promulgated in the timeframes allowed by the 2024 final rule. As a result, the EPA is making only targeted changes to certain compliance dates in this action to provide the immediate relief necessary to avoid unnecessary and problematic situations of owners and operators expending time and resources attempting to comply in short amounts of time with untenable regulatory provisions. Prior notice and comment would be impracticable given the purpose of these targeted amendments, which is to provide the immediate extension required to address the problems identified above.

The EPA has determined that this rule may take effect immediately upon publication because, in extending certain deadlines within the 2024 rule it “relieves a restriction.” 5 U.S.C. 553(d)(1). Further, for the reasons described above, there exists “good cause” for an immediate effective date. 5 U.S.C. 553(d)(3); 5 U.S.C. 808(2).

**IV. Request for Comment**

As explained in section III of this document, the EPA finds good cause to issue this interim final rule without prior notice or opportunity for public comment. However, the EPA is providing an opportunity for the public to comment on the deadlines being extended in the regulatory text changes being made by this action and, thus, requests comment on the revisions described herein. The EPA is not reopening for comment any provisions of the March 2024 final rule other than the specific changes made in this interim final rule. The EPA will review comments received and consider whether this action should be revised, if appropriate, in response to comments received.

**V. Statutory and Executive Order Reviews**

Additional information about these statutes and Executive Orders can be found at *https://www.epa.gov/laws-regulations/laws-and-executive-orders.*

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

This action is a significant regulatory action as defined under section 3(f)(1) of Executive Order (E.O.) 12866. Accordingly, it was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to E.O. 12866 review have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, *Economic Impact Analysis for the Extension of Deadlines in the NSPS OOOOb and EG OOOOc,* is available in the docket.

In the analysis, we present the estimated present values (PV) and equivalent annualized values (EAV) of the estimated cost savings of delaying compliance with the EG OOOOc (via extending the state plan submittal deadline) in 2024 dollars over the 2028 to 2039 period, discounted to 2025. Those quantitative results can be found in the next section. We acknowledge, but do not quantify, the cost savings to states resulting from having an additional year to develop state plans to implement the EG OOOOc.

Under the IFR, we anticipate disbenefits associated with additional emissions and lost value of captured natural gas because of delayed compliance with EG OOOOc. Specifically, we estimate climate damages from increasing methane emissions by 1,300,000 short tons, lost value of PM <sub>2.5</sub> and ozone-related health benefits from increasing VOC emissions by 350,000 short tons, and lost value of benefits from increasing HAP emissions by 13,000 short tons. In addition, we estimate present values of the lost value of natural gas of $170 million using a 3 percent discount rate and $280 million using a 7 percent discount rate.

**B. Executive Order 14192: Unleashing Prosperity Through Deregulation**

This action is considered an Executive Order 14192 deregulatory action. Details on the estimated cost savings of this final rule can be found in the EPA's analysis of the potential costs and benefits associated with this action. Table 3 presents the estimates of the compliance cost savings of this action. The analysis horizon over which the present value (PV) and equivalent annualized value (EAV) are estimated is 2028 to 2039. We estimate the PV and EAV under 3 and 7 percent discount rates discounted back to 2025 in 2024 dollars.

| 3 Percent discount rate | PV | EAV | 7 Percent discount rate | PV | EAV |
| --- | --- | --- | --- | --- | --- |
| 0.75 | 0.08 | 1.38 | 0.18 |  |  |

**C. Paperwork Reduction Act (PRA)**

This action does not impose any new information collection burden under the PRA. On June 28, 2024, the information collection activities for NSPS OOOOb and EG OOOOc were approved by OMB under the PRA. [^52] The ICR document that the EPA prepared has been assigned OMB Control No. 2060-0721 and EPA ICR number 2523.07. You can find a copy of the previously submitted ICR in EPA-HQ-OAR-2021-0317.

[^52]*https://www.reginfo.gov/public/do/PRAViewICR?ref_nbr=202405-2060-001.*

This action does not change the information collection requirements.

**D. Regulatory Flexibility Act (RFA)**

This action is not subject to the RFA. The RFA applies only to rules subject to notice and comment rulemaking requirements under the APA, 5 U.S.C. 553, or any other statute. This rule is not  subject to notice and comment requirements because the Agency has invoked the APA “good cause” exemption under 5 U.S.C. 553(b).

**E. Unfunded Mandates Reform Act of 1995 (UMRA)**

This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. This action imposes no enforceable duty on any state, local or tribal governments or the private sector. This action extends certain deadlines in the March 2024 final rule.

**F. Executive Order 13132: Federalism**

This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. This action extends the deadline for state plan submittals, which will allow additional time for states to develop plans. However, this action does not alter the substantive requirements related to the content of state plans.

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

This action does not have tribal implications as specified in Executive Order 13175. This action will implement extension of certain deadlines in the March 2024 final rule. Thus, Executive Order 13175 does not apply to this action.

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

This action is not subject to Executive Order 13045 because the EPA does not believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. The EPA contends that the environmental health risks or safety risks addressed by this action do not present a disproportionate risk to children because other regulations are sufficiently protective of children's health. This action does not affect the level of public health and environmental protection already being provided by existing NAAQS and other mechanisms in the CAA. Nor does this action result in any changes to the control of air pollutants. This action does not affect applicable local, state, or Federal permitting or air quality management programs that will continue to address areas with degraded air quality and maintain the air quality in areas meeting current standards. Areas that need to reduce criteria air pollution to meet the NAAQS will still need to rely on control strategies to reduce emissions. The EPA does not believe this decrease in emission reductions projected from this action will have a disproportionate adverse effect on children's health.

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

This action is not a “significant energy action” because it is not likely to have a significant adverse effect on the supply, distribution or use of energy. In the Regulatory Impact Analysis (RIA) accompanying the 2024 final rule, the EPA used a set of supply and demand price elasticities to estimate the impacts of the rule on the United States energy system (see section 4.1.4 of that document). The EPA estimated maximum production reductions of about 41.4 million barrels of crude oil (1.05 percent of projected baseline production) and 272.5 million Mcf (thousand cubic feet) per year (0.75 percent). This final rule is estimated to result in a decrease in total compliance costs, with the reduction in costs affecting the affected entities under EG subpart OOOOc, which the EPA expects will attenuate the impacts estimated for the 2024 final rule RIA.

**J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51**

This action does not involve technical standards; therefore, the NTTAA does not apply.

**K. Congressional Review Act (CRA)**

This action meets the criteria described at 5 U.S.C. 804(2), and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. The CRA allows the issuing agency to make a rule effective sooner than otherwise provided by the CRA if the agency makes a good cause finding that notice and comment rulemaking procedures are impracticable, unnecessary, or contrary to the public interest (5 U.S.C. 808(2)). The EPA has made a good cause finding for this action as discussed in section III of this document, including the basis for that finding.

**List of Subjects in 40 CFR Part 60**

Environmental protection, Administrative practices and procedures, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.

Lee Zeldin,

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**

**40 CFR Part 60**

1. The authority citation for part 60 continues to read as follows:

**Authority:**

42 U.S.C. 7401 *et seq.*

**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**

**40 CFR Part 60**

2. Amend § 60.5371 by adding two sentences before the first sentence of the introductory text to read as follows:

§ 60.5371

The provisions of this section will not apply between July 31, 2025, and January 22, 2027. The provisions of this section will apply after January 22, 2027. * * *

**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**

**40 CFR Part 60**

3. Amend § 60.5371a by adding two sentences before the first sentence of the introductory text to read as follows:

§ 60.5371a

The provisions of this section will not apply between July 31, 2025, and January 22, 2027. The provisions of this section will apply after January 22, 2027. * * *

**Subpart OOOOb—Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification or Reconstruction Commenced After December 6, 2022**

**40 CFR Part 60**

4. Amend § 60.5365b by revising paragraph (e)(2)(i) introductory text and paragraphs (e)(2)(ii) and (e)(3)(ii)(C) and (D) to read as follows:

§ 60.5365b

(e) * * *

(2) * * *

(i) Beginning January 22, 2027, or upon startup, whichever is later, 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.

(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. Beginning January 22, 2027, 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.

(3) * * *

(ii) * * *

(C) Beginning January 22, 2027, or upon startup, whichever is later, 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) Beginning January 22, 2027, or upon startup, whichever is later, 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 paragraph (e)(3)(ii)(A), (B), or (D) of this section) determination of the potential for VOC or methane emissions.

**40 CFR Part 60**

5. Amend § 60.5370b by revising paragraph (a) introductory text and paragraphs (a)(4) and (5) and adding paragraphs (a)(8) and (9) to read as follows:

§ 60.5370b

(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, paragraph (a)(8) of this section for enclosed combustion devices, paragraph (a)(9) of this section for enclosed combustion devices or flares, and paragraphs § 60.5377b(b) or (c) for associated gas wells.

(4) Except as specified in paragraph (a)(4)(i) and (ii) of this section, you must comply with the requirements of § 60.5400b or as an alternative, the requirements in § 60.5401b, 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.

(i) If complying with § 60.5400b, beginning January 22, 2027, or 180 days after startup, whichever is later, you must comply with the requirements of § 60.5400b(h)(2)(ii).

(ii) If complying with § 60.5401b, beginning January 22, 2027, or 180 days after startup, whichever is later, you must comply with the requirements of § 60.5401b(i)(2)(ii).

(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 § 60.5390b(b)(1) and (2) or (3) as an alternative to compliance with § 60.5390b(a) until January 22, 2027.

(ii) On or after January 22, 2027, process controller affected facilities must comply with § 60.5390b(a) or (b), as specified in those paragraphs.

(8) For an enclosed combustion device, you must comply with the requirements of paragraph (a)(8)(i) of this section, as applicable.

(i) Beginning January 22, 2027, or 180 days after startup, whichever is later, you must comply with the performance testing procedures of § 60.5413b(b).

(ii) [Reserved]

(9) For an enclosed combustion device or for a flare, you must comply with the requirements of paragraph (a)(9)(i), (ii), or (iii) of this section, as applicable.

(i) Beginning November 28, 2025, or 180 days after startup, whichever is later, you must comply with the continuous monitoring systems requirements of § 60.5417b(d)(8)(i) through (iv).

(ii) Beginning May 7, 2024 or 180 days after startup, whichever is later, you must comply with the visible emission observation requirements of § 60.5417b(d)(8)(v).

(iii) Beginning November 28, 2025, or 180 days after startup, whichever is later, you must comply with the continuous monitoring systems requirements of § 60.5417b(d)(8)(vi) for enclosed combustion devices or flares that are air-assisted or steam-assisted.

**40 CFR Part 60**

6. Amend § 60.5371b by adding two sentences before the first sentence of the introductory text to read as follows:

§ 60.5371b

The provisions of this section will not apply between July 31, 2025, and January 22, 2027. The provisions of this section will apply after January 22, 2027. * * *

**40 CFR Part 60**

7. Amend § 60.5375b by revising paragraphs (a)(2) and (f)(3)(i) and (ii) to read as follows:

§ 60.5375b

(a) * * *

(2) If it is technically infeasible to route the recovered gas as required in paragraph (a)(1)(ii) of this section, 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. After January 22, 2027, completion combustion devices must be equipped with a reliable continuous pilot flame.

(f) * * *

(3) * * *

(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. After January 22, 2027, 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. After January 22, 2027, completion combustion devices must be equipped with a reliable continuous pilot flame.

**40 CFR Part 60**

8. Amend § 60.5390b by revising paragraph (a) introductory text to read as follows:

§ 60.5390b

(a) Beginning January 22, 2027, or upon startup, whichever is later, 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.

**40 CFR Part 60**

9. Amend § 60.5398b by revising paragraph (d)(1)(iii) to read as follows:

§ 60.5398b

(d) * * *

(1) * * *

(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 § 60.5397b and continuous inspection and monitoring of covers and closed vent systems in § 60.5416b and/or for identifying super-emitter events in § 60.5371b, except that the Administrator is not required to make determinations on such requests for methods for identifying super emitter events in § 60.5371b before January 22, 2027. 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, except that conditional approval will not be given for purposes of identifying super-emitter events in § 60.5371b before January 22, 2027. 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.

**40 CFR Part 60**

10. Amend § 60.5411b by revising paragraphs (a)(3) and (b)(4) to read as follows:

§ 60.5411b

(a) * * *

(3) Beginning January 22, 2027, or upon startup, whichever is later, you must design and operate the closed vent system with no identifiable emissions as demonstrated by § 60.5416b(a) and (b).

(b) * * *

(4) Beginning January 22, 2027 or upon startup, whichever is later, you must design and operate the cover with no identifiable emissions as demonstrated by § 60.5416b(a) and (b), except when operated as provided in paragraphs (b)(2)(i) through (iv) of this section.

**40 CFR Part 60**

11. Amend § 60.5412b by revising paragraphs (a)(1)(viii), (a)(3)(viii), and (d)(5) to read as follows:

§ 60.5412b

(a) * * *

(1) * * *

(viii) After January 22, 2027, you must install and operate a continuous burning pilot or combustion flame. After January 22, 2027, an alert must be sent to the nearest control room whenever the pilot or combustion flame is unlit.

(3) * * *

(viii) After January 22, 2027, you must install and operate a continuous burning pilot or combustion flame. After January 22, 2027, an alert must be sent to the nearest control room whenever the pilot or combustion flame is unlit.

(d) * * *

(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, after January 22, 2027, you must still install the pilot or combustion flame monitoring system required by § 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 § 60.5417b(d)(8)(i) no longer applies.

**40 CFR Part 60**

12. Amend § 60.5413b by revising paragraph (e)(2) to read as follows:

§ 60.5413b

(e) * * *

(2) After January 22, 2027, a pilot or combustion flame must be present at all times of operation. After January 22, 2027, an alert must be sent to the nearest control room whenever the pilot or combustion flame is unlit.

**40 CFR Part 60**

13. Amend § 60.5415b by revising paragraph (f)(1)(vii)(A)( *1* ) and paragraph (h)(1) introductory text to read as follows:

§ 60.5415b

(f) * * *

(1) * * *

(vii) * * *

(A) * * *

( *1* ) After January 22, 2027, a pilot or combustion flame must be present at all times of operation. After January 22, 2027, an alert must be sent to the nearest control room whenever the pilot or combustion flame is unlit.

(h) * * *

(1) Beginning January 22, 2027, or upon startup, whichever is later, you must demonstrate that your process controller affected facility does not emit any VOC or methane to the atmosphere  by meeting the requirements of paragraph (h)(1)(i) or (ii) of this section.

14. Amend § 60.5416b by revising paragraphs (a)(1) and (2) and (a)(3)(i) and paragraph (b) introductory text to read as follows:

§ 60.5416b

(a) * * *

(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) Within the first 30 calendar days after January 22, 2027, or upon startup of the affected facility routing emissions through the closed vent system, whichever is later, 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.

(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. Beginning on the first annual inspection after January 22, 2027, and for all annual inspections thereafter, 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 § 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 or January 22, 2027, whichever is later, to demonstrate that the closed vent system operates with no identifiable emissions.

(ii) Beginning January 22, 2027, 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. Beginning January 22, 2027, 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 § 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) * * *

(i) Beginning January 22, 2027, 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.

(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 § 60.5398b(b), you must meet the requirements of paragraphs (b)(1) through (9) of this section after January 22, 2027. 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 § 60.5390b(a)(2).

**40 CFR Part 60**

15. Amend § 60.5417b by revising paragraphs (d)(8)(i) and (i)(6)(v) to read as follows:

§ 60.5417b

(d) * * *

(8) * * *

(i) After January 22, 2027, 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. After January 22, 2027, 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.

(i) * * *

(6) * * *

(v) After January 22, 2027, 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.

**Subpart OOOOc—Emissions Guidelines for Greenhouse Gas Emissions From Existing Crude Oil and Natural Gas Facilities**

**40 CFR Part 60**

16. Amend § 60.5362c by revising paragraph (c) to read as follows:

§ 60.5362c

(c) You must submit the state or Tribal plan or negative declaration letter to EPA by January 22, 2027.

**40 CFR Part 60**

17. Revise § 60.5368c to read as follows:

§ 60.5368c

If you do not submit a state or Tribal plan (or a negative declaration letter) by January 22, 2027, or if EPA disapproves your state plan, EPA will develop a Federal plan according to § 60.27a(c) through (f) to implement the emission guidelines contained in this subpart.

**40 CFR Part 60**

18. Amend § 60.5374c by revising paragraph (b) to read as follows:

§ 60.5374c

(b) If you do not submit a plan to implement and enforce the guidelines contained in this subpart by the date specified in § 60.5352c, or if EPA disapproves your plan, the EPA will implement and enforce a Federal plan, as provided in § 60.5368c, 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 § 60.5360c.