The 32-Day Window on EPA's Steam Electric CRL Rollback: What Utility EHS Leads Must Decide Before the Comment Period Closes

On May 13, 2026, EPA announced a proposal to rescind the unmanaged combustion residual leachate (CRL) provisions of the 2024 Steam Electric Effluent Limitations Guidelines, opening a 30-day public comment period that closes on or about June 12, 2026. For utility environmental, health, and safety leads who run coal-fired generating fleets, that window is the entire decision space — every comment-period decision compresses into roughly four weeks, and the choices made in that window will set the compliance posture for permit renewals running out to 2034.

This is the second of three steam-electric ELG actions in the current reconsideration sequence. The first was the deadline-extensions final rule published at 90 FR 116550 on December 31, 2025 and corrected on January 30, 2026. The third — a final unmanaged-CRL (UCRL) rescission rule — is targeted for the fourth quarter of 2026. Once the final rule publishes, the 8th Circuit litigation challenging the 2024 ELG resumes 30 days later, which means the regulatory uncertainty extends well into 2027.

The decision window is not abstract. Coal-fired utilities have to decide, before the comment period closes, what posture to take on stranded compliance capital, how to read state NPDES authorities under delegated programs, and whether the rollback materially shifts the next permit-renewal cycle. Below is a practical reading of what changed, what’s at stake, and the seven decisions that have to be made now.

What the May 2026 Proposal Actually Does

The 2024 Steam Electric ELG final rule, published at 89 FR 40198 on May 9, 2024 and effective July 8, 2024, established the first non-zero numeric Best Available Technology (BAT) discharge limits on arsenic and mercury for “unmanaged” combustion residual leachate. Unmanaged CRL is leachate that escapes a coal-ash management unit — a landfill or surface impoundment — mixes with groundwater, gets captured, and discharges to a Water of the United States. Before the 2024 rule, those leachate discharges were largely controlled through case-by-case permit conditions; after it, they had to meet uniform numeric limits.

The May 13, 2026 proposal rescinds those numeric limits and replaces them with case-by-case Best Professional Judgment (BPJ) determinations by NPDES permit writers. EPA’s news release projects the rollback will reduce coal-fleet generation costs by up to $1.1 billion per year. The agency frames the change as flexibility for permit writers; for utilities, the practical effect is that the technology-forcing function moves from a national floor to a permit-by-permit negotiation.

That distinction matters. A national BAT floor produces uniform compliance burdens — every plant has to meet the same number. A BPJ permitting regime produces non-uniform outcomes — some permit writers will set tight limits derived from the 2024 technology basis, some will set looser limits derived from site-specific characterization. The rollback does not delete the underlying control technology data; it just unbinds the permit writer from a numeric floor.

How Does the Comment Window Translate Into a Decision Calendar?

EPA published its news release on May 13, 2026 and signaled a 30-day public comment period. From a planning standpoint, that gives utility EHS leads roughly four weeks from Federal Register publication to internal sign-off on whether and how to file. The docket — EPA-HQ-OW-2009-0819 — is the same one used for every steam-electric ELG action since 2009, so historical comments and technical support documents are co-located there for reference.

A workable internal timeline looks like this. Week one: confirm the FR publication date, pull the proposed rule text, and identify which plants in the fleet have CRL discharges captured by the 2024 numeric limits. Week two: quantify stranded-cost exposure — how much CRL-treatment capital is already committed, in what stage (design, procurement, construction, commissioning), and at what plants. Week three: align with the legal team and trade groups (UWAG, EEI, NRECA, APPA) on consolidated industry comments, and decide whether plant-specific technical data justifies an individual filing. Week four: finalize and submit comments through regulations.gov.

That sequence assumes the EHS lead already has accurate CRL discharge characterization data on hand. If the data is stale or the plant has been operating under a pre-2024 BPJ permit, week one expands into a data-pull exercise that compresses everything that follows.

Which Plants Are Captured?

The Steam Electric ELG at 40 CFR Part 423 applies to point-source dischargers in the Steam Electric Power Generating Category — predominantly coal-fired electric utility generators. EPA’s 2024 Regulatory Impact Analysis (EPA-821-R-24-007) identifies 858 plants in the EIA-tracked steam electric universe. The CRL provisions of the 2024 rule directly affect a smaller subset — coal-fired units still operating after the 2024 effective date that discharge leachate from coal combustion residual management units to a Water of the United States.

That subset divides operationally into three categories. The first is plants that responded to the 2024 rule by initiating CRL treatment capital projects — engineering procurement and construction contracts already signed, equipment on order, in some cases physical installation underway. The second is plants that paused or delayed pending reconsideration — the deadline-extensions rule pushed the latest compliance date out to 2034, and the no-action assurance memo issued alongside it covered a narrow set of compliance triggers. The third is plants on a retirement glide-path — many coal units in the fleet are scheduled to retire before 2034, which makes 2024-rule compliance largely moot but does not exempt the plant from NPDES renewal cycles in 2026, 2027, and 2028.

The rollback creates different problems for each category. Stranded capital in category one. BPJ uncertainty in category two. State-level permit conditions in category three.

Does Federal Rollback Mean State Rollback?

This is the question that gets overlooked in coverage of the proposal. The answer is no — and it is the most important point for any utility operating in a state with an authorized NPDES program.

EPA’s NPDES State Program Authority page lists the 47 states (plus territories) authorized to administer the NPDES permit program in lieu of EPA. iSi’s seven-state operating region — Kansas, Missouri, Oklahoma, Texas, Kentucky, Arkansas, and Nebraska — is entirely composed of authorized NPDES states. The Kansas program was the subject of an EPA 2021 Permit Quality Review; the Texas program was further authorized in 2021 for oil and gas NPDES.

In an authorized state, the state agency issues the coal-plant NPDES permit. Federal ELG numeric limits set a floor that the state cannot go below, but the state can be more stringent if state law allows, and the state retains BPJ authority for any pollutant or wastestream the federal ELG does not cover. When the federal numeric limit on unmanaged CRL goes away, the state’s BPJ authority comes back into play — and a state permit writer can carry forward CRL limits derived from the 2024 technology basis as a BPJ determination, even though the federal limit no longer exists.

That means utilities operating in delegated states need a parallel comment strategy. Filing in the federal docket is necessary but not sufficient. Engaging the state water-quality program — through trade-association coordination, technical workshops, or direct outreach — is the only way to influence the next NPDES renewal cycle’s discharge conditions. For multi-state operators, the strategy has to be replicated in each delegated jurisdiction.

What Are the Penalties If the Permit Conditions Are Missed?

The Clean Water Act civil-penalty framework has not relaxed even as the substantive rule rolls back. Under CWA §309(d), federal judicial civil penalties for NPDES permit violations run up to $68,445 per day, per violation, based on the 2025 inflation adjustment in 40 CFR 19.4. The administrative Class I cap under §309(g)(2)(A) is $66,712, with a per-day maximum of $26,685.

A note on the 2026 inflation adjustment: it was canceled. OMB issued memorandum M-26-11 on April 17, 2026 directing agencies not to apply the annual cost-of-living adjustment, and the Federal Register notice at 2026-09334 (May 12, 2026) reflects the cancellation. The 2025 amounts remain operative through the 2026 calendar year for any violations assessed during that period.

Multiply $68,445 by 365 days of continuous violation and the exposure on a single permit parameter approaches $25 million per year, per violation. State penalty regimes typically mirror or slightly trail the federal cap. EPA’s Clean Water Act enforcement track record on power-sector dischargers includes multi-million-dollar consent decrees, and the agency has historically treated ELG violations as a priority enforcement category. The rollback does not retroactively wipe out liability for any 2024-rule violations that occurred before the rescission becomes effective.

What About Plants That Already Built CRL Treatment?

This is the hardest question for utilities in the first operational category. A plant that invested in CRL treatment capacity in 2024 or 2025 — design engineering, equipment procurement, civil works, controls integration — now holds an asset whose regulatory justification is being removed.

Three observations make the stranded-capital problem worse than it looks at first read.

First, BPJ does not mean no limit. The state permit writer can carry forward equivalent numeric limits as a BPJ determination. A utility that already built treatment may not be released from operating it — the next NPDES permit cycle may require continued use as a “control technology in place” condition. The rollback removes the federal floor but does not automatically remove the plant’s permit conditions.

Second, sunk capital is not recoverable. Engineering and procurement spend already executed cannot be unwound. Construction contracts in flight have cancellation costs. Equipment on order may carry significant change-order penalties. The capital allocation decisions made under the 2024-rule framework are largely locked in.

Third, the competitive asymmetry runs in both directions. A utility that built treatment now faces operating-cost disadvantages relative to a utility that delayed and benefits from a relaxed BPJ outcome. A utility that delayed now faces BPJ uncertainty — the state permit writer may impose conditions that the utility has not engineered for, on a timeline that may not accommodate retrofit construction. Neither posture is comfortable.

The comment record is the only place to surface these specific operational realities. Trade-association consolidated filings will address the policy question; plant-specific data — characterization of CRL streams, technology basis for control, site-specific feasibility — has to come from individual utilities if it is going to make it into the administrative record that supports the final rule and any subsequent litigation.

Seven Decisions That Have to Be Made in the Comment Window

Translating the analysis into specifics, here are the seven decisions that utility EHS leads should be working through in the next four weeks.

Read the proposed rule and the docket record. The pre-publication FRN text and the underlying technical support documents are available through regulations.gov under Docket EPA-HQ-OW-2009-0819.
Inventory current and pending NPDES permit conditions at every coal-fired generating station in the fleet. Identify which permit limits trace to the 2024 CRL provisions, which trace to FGD wastewater, bottom ash transport water, or legacy wastewater, and which were already negotiated under BPJ before the 2024 rule.
Quantify stranded-cost exposure for any plant where CRL treatment design, procurement, or construction has started. Capture sunk cost, in-flight contract value, change-order exposure, and projected operating cost differential under the alternative BPJ scenarios.
Assess state-NPDES posture in delegated jurisdictions. For multi-state operators, map each plant to its state agency, identify the next renewal cycle, and determine whether the state has signaled a position on CRL limits independent of the federal rollback.
Decide whether to file individual comments. Trade groups will file consolidated comments; the question is whether plant-specific technical data — CRL characterization, site conditions, feasibility analysis — warrants an individual filing.
Prepare for the litigation reopening. When the final rule publishes, the 8th Circuit abeyance ends 30 days later and the underlying 2024-rule challenge resumes. Permit conditions established between now and the abeyance ending should be reviewed for litigation-risk exposure.
Refresh internal monitoring data on arsenic, mercury, bromide, and selenium concentrations in CRL streams. If the final rule lands on case-by-case BPJ, every NPDES renewal becomes a data-defense exercise — current, defensible monitoring data is the foundation of every permit negotiation that follows.

The Permit-by-Permit Era Requires a Different Operating Model

A national ELG with numeric limits is a static compliance problem. A BPJ permitting regime is a moving compliance problem. For a multi-plant utility, that means the next several years of NPDES renewals will produce non-uniform outcomes across the fleet — each plant negotiating its own discharge envelope with its own state permit writer, on its own renewal cycle.

The capability that matters in that environment is not single-point regulatory expertise. It is sustained, plant-by-plant compliance program management — keeping monitoring data current, tracking renewal calendars, sustaining technical relationships with each state agency, and translating each permit negotiation into operational reality at the plant. That is the work that does not fit cleanly into a single-discipline EHS role and does not scale by adding headcount.

Replacing this scope with a full-time EHS hire would cost a utility $130,000 to $195,000 annually in salary and burden alone — for one person, in one location, with one skill profile. iSi’s environmental compliance program management as an EHS COOP retainer covers the same scope as a plug-in augmentation: NPDES support, permit-renewal tracking, monitoring data management, and state-agency engagement across a national footprint in 40 states, at a fraction of that cost. The retainer model fits the permit-by-permit era precisely because it scales by capability, not by headcount.

The 32-day decision window is the immediate problem. The operating model question is the one that determines how the next decade of permit cycles gets managed.