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Quarterly AVO Is Still LDAR: EPA's Marginal Well Site Proposal and the Leak Monitoring That Applies Today
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Quarterly AVO Is Still LDAR: EPA's Marginal Well Site Proposal and the Leak Monitoring That Applies Today

EPA's October 2026 proposal would cut low-production well sites to quarterly AVO. What leak monitoring marginal well sites owe today, and what did not change.

by iSi Environmental

On October 29, 2026, EPA published a proposal that would put the lowest-producing well sites in the country on quarterly audio, visual and olfactory inspection and nothing else. The same document proposes to rescind the Super Emitter Program. Both items are already being read as the end of leak detection and repair at small sites, and both readings will cost an operator money.

Quarterly AVO is a fugitive emissions monitoring program. It carries a schedule, a defined component list, a repair clock and a recordkeeping obligation. An operator who stands down because the periodic optical gas imaging survey went away is building a calendar violation, which is the violation EPA actually writes up.

The Super Emitter Program sits in different sections of the CFR. The rescission reaches 40 CFR 60.5371, 60.5371a, 60.5371b and 60.5388c. It does not reach 40 CFR 60.5397b or 60.5397c, which are the periodic fugitive emissions monitoring provisions for well sites and compressor stations. EPA’s own justification depends on that survival: the agency argues the super emitter program is unnecessary because other requirements suffice, “combined with regular monitoring for fugitive emissions” (91 FR 68246).

Nothing in this document is law. The proposal at 91 FR 68234 to 68361 (FR Doc. 2026-22082, Docket EPA-HQ-OAR-2025-0163, RIN 2060-AW73) contains no regulatory text at all, which is why the new marginal well subcategory has no CFR section numbers and no effective date. The March 2024 rule, 89 FR 16820, is what applies to your sites this morning. It was never stayed, and the Supreme Court denied a stay on October 4, 2024 in Oklahoma v. EPA, No. 24A213.

Does EPA’s Super Emitter Program rescission eliminate LDAR requirements under OOOOb?

No. The proposed rescission removes 40 CFR 60.5371, 60.5371a, 60.5371b and 60.5388c and their cross-references. It does not touch 40 CFR 60.5397b or 60.5397c, the periodic fugitive emissions monitoring provisions. EPA’s rationale relies on monitoring surviving: the agency calls the program unnecessary given other requirements “combined with regular monitoring for fugitive emissions” (91 FR 68246).

The rescission runs across NSPS OOOO, OOOOa, OOOOb and EG OOOOc. Besides the four sections above, it clears cross-references at 60.5398b(d), 60.5420b(b)(14) and 60.5420c(b)(14), the “average aggregate detection threshold” definition at 60.5430b and 60.5430c, and table 1 to subpart OOOOc. The super emitter definition being withdrawn is a quantified emission rate at or above 100 kilograms per hour of methane (91 FR 68244 to 68245). The program’s implementation date was January 22, 2027, so for most operators it was a future obligation rather than a current one.

There is a tension inside the document worth knowing about. EPA leans on fugitive monitoring as the backstop that makes the super emitter program redundant, and in the same proposal asks, in Questions III.4c, III.10h through III.10j and III.10q through III.10s, whether the fugitive emissions monitoring requirements in NSPS OOOOb and EG OOOOc are necessary at all, including “potential exemptions of certain subcategories.”

What is a “marginal well site” under EPA’s October 2026 oil and gas proposal?

A well site where every well is marginal and the combined oil and gas production of all wells averages 15 barrels of oil equivalent per day or less over the prior 12 months (91 FR 68330). EPA takes the 15 boe/day figure from the stripper well property definition at 26 U.S.C. 613A(c)(6)(E) and applies it at the site level rather than per well.

That site-level choice is deliberate and it is where operators will get surprised. A site with three wells producing 6 boe/day each sits at 18 boe/day and does not qualify, even though each well on its own would be a stripper well for tax purposes (91 FR 68304).

EPA co-proposed a second version of the same subcategory. The alternative “conventional well site” option keys off formation type and has no production threshold at all. The agency says it may finalize one or the other, which means the qualifying test is itself still open for comment. Nationally, EPA counts roughly 717,000 marginal wells out of 918,000 active U.S. wells in 2024, producing about 7 percent of national volume (91 FR 68305, citing EIA well production data).

What leak detection frequency applies to my well site right now?

Under 40 CFR 60.5397b, unchanged by this proposal: single wellhead only and small well sites run quarterly AVO; multi-wellhead only sites run quarterly AVO plus semiannual OGI or EPA Method 21; well sites and centralized production facilities with major production and processing equipment run bimonthly AVO plus quarterly OGI or Method 21; compressor stations run monthly AVO plus quarterly OGI or Method 21.

The spacing rules matter as much as the frequency. Semiannual surveys fall 4 to 7 months apart. Quarterly surveys fall at least 60 days apart. Small well sites must include a visual check of thief hatches and separator dump valves as part of the AVO. The supporting obligations run alongside: a monitoring plan under 60.5397b(b), repair under 60.5397b(h), recordkeeping and reporting under 60.5397b(k), and well closure under 60.5397b(l). A fugitive emission means an AVO indication, visible emissions imaged by OGI, or a reading at or above 500 ppmv by Method 21 (60.5430b).

The amendments EPA actually proposes to 60.5397b are narrow: “technique” becomes “technique(s)” to confirm that operators may combine detection methods, the difficult-to-monitor and unsafe-to-monitor provisions extend to AVO inspections, the fugitive emissions component definition at 60.5430b picks up exclusions for covers, closed vent systems and thief hatches regulated elsewhere, and the centralized production facility modification criteria at 60.5365b(i)(2) are rewritten. None of that moves a survey date.

Compressor stations are outside the new subcategory entirely. The phrase “compressor station” appears once in the whole of section III.K. If you run a compressor station, monthly AVO plus quarterly OGI or Method 21 is your program under either outcome.

What monitoring would a marginal well site have to do instead?

Quarterly AVO only, across all four well site types, with the periodic OGI or Method 21 survey dropping out rather than being reduced. The AVO would have to cover every fugitive emissions component except buried yard piping and its associated components, every thief hatch and storage vessel opening, every separator dump valve, and every natural gas-driven intermittent vent process controller (section III.K.ii of the proposal).

The controller check is the piece most likely to be missed, because it is a listening task rather than a looking task. During idle periods the inspector is checking for audible continuous flow, hissing, abnormal clicking or chattering, for odors, and for visible leaks, cracks, holes, gaps, corrosion or missing pieces. Corrective action is due within 5 calendar days, with a re-survey within 5 days after that.

Repair clocks split by how the leak was found. An AVO-detected fugitive emission requires a first repair attempt within 15 calendar days of detection and completion within 15 calendar days of that first attempt. An OGI or Method 21 detection runs on 30 days and 30 days, subject to delay of repair.

Several other standards shift for the subcategory. Continuous-bleed process controllers move from zero-emission to 6 standard cubic feet per hour or less, with a functional-need exception. Pneumatic pumps route to an onsite control device achieving 95 percent if one is already available, route to a process, or get replaced with non-gas-driven pumps. Associated gas requires control only where methane content reaches 20 tons per year, though the demonstration that methane sits below 20 tpy is still required. Liquids-unloading best management practices come out for the subcategory, and storage vessel requirements stay as they are. An anti-backslide provision keeps zero-emission controllers under 60.5390b(a) and zero-emission pumps under 60.5393b(a) in place at a site that moves from non-marginal to marginal.

Separately, EPA reverses the associated gas BSER for everyone: routing to a sales line is out, a control device or flare achieving 95 percent or greater reduction is in, and the temporary flaring provisions are removed.

How do I demonstrate that a well site qualifies as marginal?

Divide the site’s combined daily oil and gas production over the previous 12 months by the number of operating days. The initial determination may be made at any time, but the reduced requirements apply only after submission of a notification of marginal well site determination. Any production-increasing modification triggers a new determination within 45 days (91 FR 68330).

Qualification is a documented determination rather than a status your production numbers confer on you automatically. Nothing happens until the notification goes in, and because the proposal carries no regulatory text, there is no section number, no form and no submission address for that notification yet.

If EPA finalizes the conventional option instead, the arithmetic disappears. There is no production test under that version, only documentation that the site meets the conventional well site definition, and in EPA’s words “all conventional wells would be subject to less stringent standards, without regard to actual production levels” (91 FR 68334).

Does the marginal well subcategory apply to existing wells or only new ones?

Both, through two different instruments. NSPS OOOOb reaches new, reconstructed and modified sources directly. Existing sources are reached only through EG OOOOc, which states implement in plans due January 22, 2027 under 40 CFR 60.5362c(c). Until a state plan or a federal plan is in place, an existing site carries no OOOOc obligation.

For an operator with older wells, this is the whole question. The relief in the proposal arrives at an existing site only after a state writes it into a plan, EPA approves that plan, and the plan takes effect. January 22, 2027 is also the Super Emitter Program implementation date and the NSPS zero-emission process controller compliance date (91 FR 68245 and 68252), so it is the date to put on the wall regardless of which way the proposal lands.

When is the comment deadline for the 2026 OOOOb proposal, and when would it take effect?

Comments are due December 16, 2026 (91 FR 68234), in Docket EPA-HQ-OAR-2025-0163. The published document gives two different virtual hearing dates: November 13, 2026 in the DATES section and November 16, 2026 in SUPPLEMENTARY INFORMATION. Pre-registration to speak closed November 10, 2026. Nothing proposed takes effect until a final rule publishes.

Confirm the hearing date with EPA before you plan around it. Both dates are in the published document, and the discrepancy is in the document itself rather than in a summary of it.

Three separate dates are getting conflated in the coverage, and keeping them apart is worth a minute:

  • December 16, 2026 is the comment deadline on the proposal (91 FR 68234).
  • November 30, 2026 is when OMB must receive Paperwork Reduction Act comments (91 FR 68360). The Federal Register API returns this date in its comment-close field, which is how it ends up misreported as the comment deadline.
  • November 30, 2026 is also, for an unrelated reason, the due date for initial annual reports under 40 CFR 60.5420b(b) (91 FR 68236 to 68237, printed there as “60.5420(b)”). That one is a live compliance deadline under the rule in force, not a proposed date, and it is 32 days from publication.

The comment window is wider than the marginal well subcategory. EPA states it is “broadly seeking comment on any and all of the requirements established in the March 2024 Final Rule not discussed elsewhere,” and that the final rule “may revise, expand, or eliminate the standards or requirements in the March 2024 Final Rule” (91 FR 68348).

What happens on January 22, 2027 if my state has not submitted an OOOOc plan?

EPA promulgates a federal plan within twelve months of the missed deadline under 40 CFR 60.27a(c) and (d), unless the state cures first. A federal plan “will prescribe standards of performance of the same stringency as the corresponding emission guideline(s)” (60.27a(e)(1)). Missing the deadline hands implementation to EPA at the guideline’s own stringency rather than producing a lighter program.

The floor works in one direction. 40 CFR 60.24a(c) sets a state plan at no less stringent than the guideline, and 60.24a(i) expressly preserves a state’s authority to adopt standards more stringent than the guidelines, with earlier final compliance dates. There is no ceiling.

Where the region stands as of this writing: Colorado’s Air Quality Control Commission adopted its plan at the September 16 to 18, 2026 hearing and CDPHE states submittal to EPA is planned for January 2027. Oklahoma’s ODEQ 111(d) page says the oil and gas plan is “currently paused,” with no formal policy decisions and no rule language drafted. No Kansas, Missouri or Nebraska plan or negative declaration is on record.

What is the penalty for a fugitive emissions monitoring violation?

Up to $124,426 per day per violation in a civil judicial action under CAA section 113(b), or $59,114 per day with a $472,901 cap per matter administratively under section 113(d)(1) (40 CFR 19.4). Knowing violations carry up to five years’ imprisonment, and falsified or unfiled records up to two years, under 42 U.S.C. 7413(c)(1) and (2).

Those figures apply to penalties assessed on or after January 8, 2025 (90 FR 1375). No 2026 inflation adjustment has published.

Federal enforcement attention has been withdrawn in writing, and that is a separate thing from the rules changing. The OECA memo of March 12, 2025 states that “enforcement and compliance will no longer focus on methane emissions from oil and gas facilities,” requires the OECA Assistant Administrator’s concurrence to resolve methane violations already found, and directs that enforcement “shall not shut down any stage of energy production” absent an imminent and substantial threat to human health. Mitigating Climate Change, which expressly covered oil and gas methane, is no longer among the six initiatives on EPA’s current enforcement initiative list. FY2024 was the last year with a sector breakout: 353 oil and gas facility inspections, 19 enforcement cases, and almost $72 million in civil penalties from oil and gas cases alone.

The recent case record shows what the exposure looks like when it does land, and it is regional. Gulfport Energy, headquartered in Oklahoma City, paid $454,403 with no injunctive relief on 115 counts across 33 well pads, almost entirely missed repair deadlines under 40 CFR 60.5397a(h)(2): 41 failures to attempt repair within 5 days, 42 failures to complete within 30 days, and 32 failures to complete final repair within 30 days of the first attempt. The order records that the repairs were not technically infeasible and required no shutdown or blowdown. Every count in it was a missed date.

EOG Resources paid $412,500 across 15 New Mexico and 8 Texas Permian facilities in January 2025, and the injunctive relief is the part worth reading: a third-party auditor, monthly OGI surveys at every facility for a year, tank pressure, pilot, vapor recovery and bypass monitoring, and a $1.98 million supplemental environmental project backed by a $2,268,000 stipulated penalty.

Two gaps are worth stating plainly rather than implying. No 2026 federal oil and gas Clean Air Act action involving NSPS OOOO, OOOOa or OOOOb turned up, and no EPA Region 7 oil and gas Clean Air Act action turned up for 2024 through 2026 at all.

Do Kansas, Oklahoma or Texas have their own well-site LDAR rules?

Kansas and Oklahoma do not. Kansas has no oil and gas fugitive emissions rule in K.A.R. 28-19, and OAC 252:100-37-4(b) exempts upstream production from Oklahoma’s entire VOC subchapter. Texas does, in the Dallas-Fort Worth and Houston-Galveston-Brazoria ozone nonattainment areas only, under 30 TAC sections 115.170 through 115.183, which reach neither the Permian nor the rest of the state.

Texas is the interesting one, because Texas already drew EPA’s line. 30 TAC section 115.172(a)(8) exempts fugitive emission components at a well site whose wells “produce on average 15-barrel equivalents or less per day.” Same number, same site-level test, adopted June 30, 2021, approved by EPA at 88 FR 55379 and effective September 14, 2023, which makes it SIP-approved and federally enforceable. An operator in the Barnett or the Houston area has been working EPA’s proposed threshold for five years.

Two things the Texas experience tells you. First, the threshold is workable in practice. Second, the exemption is narrower than it sounds: it covers components, while compressors, controllers, pumps and tanks stay regulated, and the recordkeeping obligation under section 115.180(2) survives the exemption. Division 7 monitoring where it does apply runs semiannual at well sites and quarterly at gathering and boosting stations, by Method 21 or an approved alternative, with a 500 ppmv leak threshold and 5-day and 15-day repair deadlines. Confirm the monitoring section number before you cite it to anyone: EPA’s SIP page puts monitoring at section 115.177 while TCEQ’s own Division 7 table maps it to section 115.178.

Delegation separates Texas from its neighbors. Texas holds automatic NSPS delegation for existing and future standards, effective December 28, 1982, so OOOOb is delegated there. TCEQ’s OOOOc rulemaking (project 2024-027-113-AI) is still at informal stakeholder stage with every formal milestone listed as subject to change based on EPA actions.

Does the EPA marginal-well proposal reduce my obligations in Colorado?

No. Colorado’s LDAR program in AQCC Regulation 7 (5 CCR 1001-9, Part B, section II.E) is state-only, carries no production-rate exemption, and puts even the smallest sites at annual OGI or Method 21 plus monthly AVO. Regulation 7 also pins the federal subparts it incorporates to fixed 2025 dates, so later EPA relaxations do not flow through on their own.

The incorporation language at Part B, section I.G.1 names subpart OOOO as of July 31, 2025, subpart OOOOa as of July 31, 2025, and subpart OOOOb as of December 3, 2025. A relaxation finalized in 2027 does not reach a Colorado operator until the Commission adopts it. Colorado also moved in the opposite direction while the federal rollback was underway: in a rulemaking adopted February 20, 2026 and effective April 14, 2026, the Commission added a “wellhead only well production facility” definition to confirm that well production facility LDAR requirements reach wellhead-only sites, and required every Colorado gas processing plant to meet LDAR modeled on EG OOOOc using appendix K OGI. Colorado tiers by uncontrolled actual VOC tons per year and proximity to people, escalating to semiannual near occupied areas and in disproportionately impacted communities, and monthly for sites that commenced operation on or after May 1, 2022. A full-text search of the rule for “marginal,” “stripper” and “low production” returns no definition and no exemption.

New Mexico declines the same exemption. 20.2.50.116 NMAC tiers by production and potential to emit, with weekly AVO above 10 barrels or 60,000 scf per day and monthly AVO below, plus annual, semiannual or quarterly OGI by VOC potential to emit, and it never removes the obligation. NMED filed a new methane rule, 20.2.51 NMAC, in August 2026, with operator investigation and repair generally within three days of NMED notification.

Two more obligations sit outside EPA’s air rules and have not moved. Subpart W greenhouse gas reporting is still in effect, with RY2025 reports due March 10, 2027 under an interim final rule (91 FR 65112) that makes no other changes to the rule. And if your gas reaches Europe, producer-level monitoring, reporting and verification equivalence must be demonstrable from January 1, 2027 under Article 28(1) of Regulation (EU) 2024/1787.

Does a modification at a marginal well site change which rules apply?

Yes. Seven listed actions trigger a new marginal well site determination within 45 days, using the first 30 days of post-activity production. If the site comes out above 15 boe/day, the full OOOOb requirements apply on the dates in 40 CFR 60.5370b, and the anti-backslide provision keeps already-installed zero-emission equipment where it is (91 FR 68330).

The seven triggers are specific:

  • drilling a new well at the site
  • hydraulic fracturing or refracturing
  • stimulation beyond normal maintenance to increase production
  • shutting a well in to boost production from another well
  • adding a natural gas-driven process controller
  • adding or replacing a storage vessel in a way that raises tank battery capacity or throughput
  • adding a natural gas-driven pump

For an operator who reworks wells to keep marginal production alive, that list is the practical constraint on the whole subcategory. The relief is tied to a production number you are actively trying to raise.

EPA also solicited comment on a 6 boe/day sub-split inside the marginal subcategory without proposing it (91 FR 68331 to 68332). If a second tier at 6 boe/day would change your program, that is a comment-period question rather than a wait-and-see question.

Kansas has the most marginal wells in the region and the least machinery to deliver the relief

Kansas is the most marginal-weighted state in iSi’s service region by a wide margin. In CY2024, 99.00 percent of Kansas oil wells and 99.12 percent of gas wells produced at or below 15 boe/day (EIA WDR2025 Appendix B, Table B35). Oklahoma runs 91.50 percent of oil wells and 68.50 percent of gas wells under the threshold. Texas runs 74.24 percent and 66.64 percent. Those are well counts rather than site counts, and EPA’s threshold is site-level, so the share of sites that would actually qualify is lower. EIA discontinued this report on October 15, 2026, which makes CY2024 its final vintage.

Then look at how the relief would have to arrive. K.A.R. 28-19-720 adopts 40 CFR part 60 as revised July 1, 2017 and expressly excludes emission guidelines, so NSPS OOOOb is not in Kansas law and EG OOOOc is carved out. EPA’s Kansas delegation table shows the state holding OOOO and OOOOa and not OOOOb, which leaves EPA implementing. No Kansas OOOOc plan or negative declaration is on record. Oklahoma’s delegation, at 90 FR 59057 effective January 20, 2026, marks both OOOOb and OOOOc “No.”

Kansas has asked for exactly this relief before. In a February 12, 2023 comment letter signed by Deputy Secretary Leo G. Henning, KDHE urged EPA to exempt low-production wells in 16 Kansas counties from monitoring and to make yard piping AVO-only. The state’s position on the merits is on the record. The instrument that would deliver it, a delegated program or an approved state plan, is not built.

This is also where company size shows up. EPA counts more than 11,000 unique operators in 2023, with 51.3 percent of U.S. marginal wells held by 127 firms running 1,000 or more wells each, while 7,320 firms, more than 65 percent of the total, own ten or fewer wells and hold 3.2 percent of marginal wells (91 FR 68305). The operator most exposed to a misread headline is the one with a handful of sites and nobody in-house whose job is air compliance.

What to do between now and December 16

  1. Write down which of the five schedules in 40 CFR 60.5397b each of your sites is on today, and the date of the next required survey. Keep surveying on that schedule. The proposal changes nothing about it.
  2. Confirm your initial annual report under 40 CFR 60.5420b(b) is filed by November 30, 2026. That is a live deadline under the rule in force.
  3. Run the 15 boe/day math at the site level now, using the prior 12 months divided by operating days, so you know which of your sites would qualify under the marginal option and which would not.
  4. If you operate in the Dallas-Fort Worth or Houston-Galveston-Brazoria areas, check your site records against the 30 TAC 115.172(a)(8) exemption you may already hold, and against the recordkeeping that survives it.
  5. If the threshold, the 6 boe/day sub-split, or the scope of the quarterly AVO would change your program, comment by December 16, 2026 in Docket EPA-HQ-OAR-2025-0163. EPA asked whether fugitive monitoring is necessary at all, so the window covers more than the subcategory.
  6. Do not cancel OGI contracts or retire monitoring records on the strength of a proposal with no regulatory text and no effective date.

For the broader picture of how this proposal fits the rest of EPA’s air rule activity this year, including the April 2026 technical amendments that were part one of this same reconsideration, see our digest of EPA’s 2026 deregulatory cycle.

Most of the operators this proposal is aimed at do not have an air compliance person. They have a pumper and a consultant they call when something breaks. The work this rule actually demands is tracking: knowing which schedule each site is on, surveying on time, closing repairs inside 15 or 30 days, and keeping records that prove it. iSi’s EHS COOP retainer covers that tracking for operators who do not want to hire for it, including the monitoring calendar, the repair documentation and the annual report. If you want to know which of your sites would qualify as marginal and what each one owes today, call us and we will walk the site list with you.

Frequently Asked Questions

Does EPA’s October 2026 proposal eliminate LDAR at marginal well sites?

No. It is a proposal with no regulatory text and no effective date. The five fugitive-monitoring frequencies at 40 CFR 60.5397b apply today, unchanged. If finalized as proposed, qualifying marginal well sites would move to quarterly AVO inspections only, with the periodic OGI or Method 21 survey removed.

What counts as a marginal well site under the proposal?

A well site where every well produced 15 barrels of oil equivalent per day or less over the prior 12 months and the site’s cumulative production across all wells is also at or under 15 boe/day. The test is site-level, adapted from the IRC stripper-well definition. A co-proposed alternative uses formation type with no production threshold.

When are comments due on the OOOOb marginal well proposal?

December 16, 2026, to Docket EPA-HQ-OAR-2025-0163 (91 FR 68234). November 30, 2026 is the separate Paperwork Reduction Act date for OMB, which is widely misreported as the comment deadline because the Federal Register API returns it in the comment-close field.

Did the Super Emitter Program rescission remove fugitive emissions monitoring?

No. The rescission reaches 40 CFR 60.5371, 60.5371a, 60.5371b and 60.5388c and their cross-references. It never touches 60.5397b or 60.5397c, and EPA’s own rationale for the rescission assumes periodic LDAR survives (91 FR 68246).

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