PJM Large Load Curtailment Rule: What FERC Kept

FERC rejected the PJM large load curtailment rule on October 9, 2026. In Docket ER26-3515-000 the Commission accepted only two pieces of PJM’s filing, a definition of Large Load and a Large Load Registry, effective October 12, 2026, and required PJM to submit a compliance filing within 30 days. It rejected the Interim Resource Adequacy Service (IRAS), under which new large loads without dedicated supply would have had to reduce load when the system neared emergency conditions, and it rejected the rest of the package with it. So for now there is no PJM rule that makes curtail on command a condition of connecting. There is a registry, and a definition of who has to be in it.

The auction is the headline. As filed, the Reliability Backstop Procurement targets 6.8 GW and pays on a 15 year commitment with an online deadline of June 1, 2032. The 6.8 GW is the amount by which the most recent Base Residual Auction missed PJM’s 20% reserve margin. Across PJM’s 13 states and the District of Columbia, large load is projected to grow 70 GW by 2038 while roughly 15 GW of generation has retired since 2022.

The number that tells you how serious PJM is about the shortfall is the backstop’s price limit: $555 per MW-day, against the $325 per MW-day cap that bound the last auction. It is not a ceiling on each offer. PJM’s filing sets it as a maximum willingness to pay applied to the MW-weighted average levelized cost of all selected offers over the term, “while not restricting Sell Offers to a hard price cap,” so individual offers can clear above it.

PJM proposed opening a three-week bid window on September 30. FERC acted on September 29, 2026: it accepted the Reliability Backstop Procurement for filing but suspended it for five months, to become effective February 28, 2027, subject to refund, and set a paper hearing on cost allocation, transmission owner exit rules and LSE collateral requirements. The September 30 window was tied to that filing, so treat any fall 2026 auction date as superseded until PJM posts a new schedule. The planning question for anyone selling into or buying for the footprint is what registering a large load requires, what curtailment terms a utility contract or state tariff attaches to it, and whose purchase order that work lands on.

What FERC kept and what it rejected in the PJM large load curtailment rule

As filed, IRAS was a condition of service rather than a demand response program: a large load without its own dedicated supply would have been curtailed by its electric distributor when PJM called for a reduction. FERC rejected it, and its companion Bring Your Own New Capacity rules, on two grounds. First, jurisdiction: the order says the proposed construct “appears to regulate the terms and conditions of a retail customer’s service in ways that are beyond the Commission’s authority,” because it appeared to direct which retail customers would be curtailed and to set what amounts to a retail rate. Second, PJM had not shown that IRAS and Bring Your Own New Capacity were just and reasonable and not unduly discriminatory or preferential. Because the rest of the package (the related capacity obligation and the other pieces tied to IRAS) was “an integrated package that must be viewed as a whole,” FERC rejected it too. It also gave guidance on how PJM could modify the proposal “should PJM seek to refile it.” Whether PJM refiles is not settled by the order.

What survived is the definition and the registry. FERC found PJM’s Large Load definition just and reasonable: end-use customer load with a cumulative peak of 50 MW or more at a single electrical site behind one or more points of interconnection, where affiliated load facilities within a one mile radius count as a single site. The tariff records PJM filed for the definition also carried IRAS and Bring Your Own New Capacity language, so FERC rejected those records and directed PJM to file, within 30 days, revisions that include only the accepted Large Load definition, without the rejected IRAS, Bring Your Own New Capacity or New Large Load language. Read the compliance filing before relying on any registry detail.

The registry is the part with an equipment question attached. As PJM described it in the filing, the registry would collect each Large Load’s location, peak load quantity and ramp schedule, telemetry specifications and backup generation, among other details; confirm the final field list against the compliance filing. Facility location is a form field. Ramp schedules and telemetry are not. A ramp schedule is a claim about how fast a facility can shed and restore load, and a registry that collects it implies somebody can verify it. That requires measurement at the point of delivery at a resolution most large loads do not have today, plus a path for a dispatch signal to reach equipment that can act on it.

Curtailment terms have not gone away. Duke Energy has a temporary curtailment provision in its Customer Protection Plus framework, and federal regulators have been pressing every RTO on large load terms since the June show cause orders on large load tariffs. The October 9 order does not prohibit curtailment terms. It found that this tariff appeared to regulate retail service beyond FERC’s authority. Unless PJM refiles a version FERC accepts, large load curtailment terms in PJM remain largely a matter for utility contracts and state proceedings.

Why the $555 backstop limit is not a step up from $325

PJM’s 2028/2029 Base Residual Auction, whose results published July 14, procured 138,318 MW and cleared at the $325 per MW-day cap across all four load zones with no locational separation. It was not the first auction to end that way. The cap has bound the outcome in consecutive auctions now, which is the context the backstop price has to be read against.

Absent the cap, PJM’s own simulation in its 2028/2029 BRA results report has the auction clearing at $554.72 per MW-day, roughly 71% above the cap, with ComEd separating out to $776.69 per MW-day. PJM puts cleared supply times clearing price at $29.7 billion in that simulation against $16.4 billion in the actual auction, and notes the actual figure does not equate to a total cost to load, because load hedged through self-supply or bilateral contracts is not exposed to auction prices.

PJM’s filing says where the backstop number comes from. $555 per MW-day is Point 1 on the Variable Resource Requirement curve, the uncollared price cap the Commission accepted for the 2028/2029 auction, and “but for the collared price cap” it would have been that auction’s cap. So it is not a number PJM picked by stepping up from $325. It is the uncollared ceiling, reused as the average price load will pay across a 15 year term.

That matters to a procurement calendar more than it matters to a market analyst. A 15 year commitment with a 2032 online deadline is a financeable revenue stream, and projects that penciled out only above the $325 collar could become buildable. The clock is no longer known, though. With the procurement suspended until at least February 28, 2027 and parts of it sent to a paper hearing, the award date that would pull substation, interconnection and step up scope forward has moved, and it will move again with any revised PJM filing.

The counter argument is live and it comes from PJM’s own market monitor. Joseph Bowring of Monitoring Analytics argues that keeping data center load in the capacity auctions is itself what raised capacity costs by $29.4 billion over the last four auctions. If FERC accepts that cost causation framing, the remedy tilts away from paying more for capacity and toward removing large loads from the auction entirely. The closest filed version of that remedy, PJM’s proposal to exclude eligible new large loads from the auction demand curve beginning with the 2029/2030 delivery year, was part of the package FERC rejected on October 9, 2026. Julia Hoos of Aurora Energy Research reads the backstop as addressing an immediate gap while the underlying build challenges persist.

What the rest of this piece answers

PJM, ERCOT, Duke and North Carolina use different instruments to address large loads. Service conditions, queue requirements, individual agreements and proposed rate classes need separate readings of their status and scope.

The rest of this piece compares those instruments, identifies questions about who specifies and buys the equipment, and explains how to read a load pipeline’s stages without applying an unsupported conversion factor. It also lists planning dates and questions to check against current filings and project agreements.

For a distribution buyer, the practical question is whether a registry or curtailment requirement creates additional metering, communications or control work on a specific project. Confirm the technical requirements and responsible counterparty before treating that possibility as funded scope.

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