PJM filed the fix on Thursday. On October 29, the grid operator submitted an amended Reliability Backstop Procurement to the Federal Energy Regulatory Commission, addressing the three defects that led FERC to suspend the original plan a month earlier: cost allocation, load-serving-entity collateral, and exit responsibilities. PJM’s own account of the filing puts the procurement on course to launch March 1, 2027, with the bid window closing March 28, a final target set April 28, and results posted May 10.
That sentence — filed, not accepted — is the most important discipline for reading what follows. FERC has not ruled on the amended proposal. The September 29 order that suspended the original backstop for five months, to February 28, 2027, still stands, as does the paper hearing in the companion Section 206 docket, EL26-108, unless FERC holds it in abeyance while it considers the new filing. PJM asked for that abeyance on October 12. What October 29 produced is a revised proposal and a test of whether it cures what FERC found wanting. It is not yet a procurement anyone can bid into.
The July auction for the 2028/29 delivery year cleared at the $325/MW-day cap and still procured only 138,318 MW of unforced capacity, plus 10,864 MW under Fixed Resource Requirement arrangements, leaving a shortfall of 6,831 MW against a reliability requirement of 156,013 MW. The backstop was designed to buy that gap, on contracts of up to 15 years, at a volume-weighted maximum willingness to pay of $555/MW-day. Everything in the amended filing is an argument about who bears the cost of that purchase, and on what terms they post security for it.
Cost allocation: from a snapshot to a growth measure
The central change is the cost-allocation formula, and it is a direct answer to FERC’s core objection. The original filing allocated backstop costs on a snapshot of current load. FERC found PJM had not shown that method consistent with cost causation, because a snapshot of today’s load does not capture the forecast growth from large new users — the very loads driving the shortfall. The Commission suggested allocation based on updated load forecasts that reasonably capture all forecasted load growth. PJM now proposes that costs be allocated to load-serving entities based on large-load growth between the actual summer peak load in 2026 and the forecast for the 2028/29 delivery year. Electric distribution companies will be required to provide firm large-load growth figures for that period, and the costs will be assigned to each zone based on the zone’s contribution to that growth. In plain terms: zones where large load grew fastest carry the largest share of the backstop bill, and the measure of growth is firmer than a forecast alone, because it is anchored in reported, firm figures from the distribution companies that serve those loads.
That is a meaningful shift in principle, and it is worth stating what it does not settle. A growth-based allocation still depends on the quality of the underlying numbers — which loads count as firm, and whether load already embedded in PJM’s baseline forecast is double-counted or missed. FERC’s September order worried precisely that some large loads may never have been accounted for as load adjustments, leaving households to pay for data-center growth. The Department of Energy made the same point more bluntly in its October 7 statement of position in ER26-3380 and EL26-108, arguing that large electric loads, “not American households or other business ratepayers,” must fund the generation and related infrastructure their projects require. The amended formula gives FERC a cleaner mechanism. Whether the firm-growth data fed into it are complete is the question intervenors will now test.
There is also a distributional consequence worth naming. A growth-based allocation concentrates costs in the zones where the load arrived — Northern Virginia’s data-center cluster above all — and relieves zones where it did not. That is the cost-causer-pays principle working as its advocates intend. It also means the political fight will now be fought zone by zone, with the heaviest bills landing where load-serving entities have the strongest incentive to challenge the growth figures assigned to them. The formula does not end the allocation dispute. It relocates it, from an argument about method to an argument about measurement.
Collateral: lower, but not yet proven proportionate
The second change addresses the collateral requirement that drew some of the sharpest criticism of the original filing. FERC found PJM’s proposed collateral for load-serving entities potentially flawed, saying it did not strike a reasonable balance between protecting the market against default risk and giving participants adequate flexibility to manage their requirements. The illustration that made the point concrete was Northern Virginia Electric Cooperative, which said it would have faced roughly $2 billion in collateral postings under the original proposal — a figure that, applied to a cooperative serving one of the fastest-growing load pockets in the country, showed why the Commission hesitated.
PJM’s amended filing replaces that approach with what it describes as a revised lower uniform credit rate and revised payment terms, aimed at striking the balance FERC asked for. At the October 22 stakeholder meeting where PJM previewed the revision, the collateral figure presented was 40 percent of the discounted obligation — about $0.68 million per MW in PJM’s example, against the roughly $1.5 million-per-MW figure questioned in the original proposal. PJM’s summary of the filed proposal confirms a lower uniform rate without restating that percentage, so the 40 percent figure should be read as the previewed design, with the filed tariff text as the authoritative version.
The direction of travel is clear, and it matters for who can bear the backstop’s costs at all. Collateral that prices smaller load-serving entities out of the process distorts the allocation itself, because entities that cannot post cannot bear their share on the terms the tariff assumes. A lower, uniform rate is easier to defend as non-discriminatory than a requirement that falls unevenly by size or credit standing. But “lower” is not the same as “right.” FERC will still ask whether the revised rate protects PJM’s markets against a default by a large, concentrated obligor — the failure mode that matters most when a 15-year commitment is at stake — without recreating the barrier the original requirement posed. The test is not whether the number went down. It is whether it went down to a level that is both protective and survivable, and that judgment belongs to the Commission, not to the filing.
Exit rules and the end of the opt-out
The third change closes two doors the original filing left open, and both closures follow the same principle: backstop obligations, once assigned, should not be escapable by corporate restructuring or categorical exemption. On exit, the amended filing provides that a load-serving entity leaving PJM remains responsible for its backstop charges for the remainder of the commitment term. That replaces the original approach, under which FERC found PJM had not demonstrated that stranded costs would land on the entities causing them, and aligns with the Commission’s direction that such costs be assigned to the load-serving entities within the zone rather than to an exiting transmission owner as a corporate matter.
The more politically charged closure is the removal of the opt-out. The original filing let qualifying cooperatives and municipal utilities opt out of the procurement. FERC rejected that carve-out as potentially unduly discriminatory against other load-serving entities with data centers in their footprints, and the amended filing removes it. Cooperatives and municipal utilities in high-growth zones will now bear backstop costs on the same growth-based terms as everyone else — a significant change for entities that argued their member-owned structure warranted different treatment. FERC’s answer, adopted here by PJM, is that cost causation does not vary with corporate form: if the load in your zone grew, the zone pays, whoever serves it. A related tightening requires a Peak Shaving Adjustment plan for a minimum of five years as a condition of that opt-out, and the filing also adjusts site-control requirements, allows more time to cure sell-offer deficiencies, and clarifies demand-response and distributed-energy-resource requirements for qualifying offsets.
What happens to the 6,831 MW
Here is the part of the story that most needs careful reading. The amended filing does not simply re-propose buying 6,831 MW. PJM states that the shortfall will be recalculated with updated information given the new timeline, and that the target will be reduced by the megawatts procured through qualifying bilateral contracts. The 6,831 MW figure is the July auction’s shortfall, measured against the forecasts and accreditation factors then in effect. By March 2027, the reliability requirement, the load forecast, and the accreditation of cleared capacity will all have been updated, and the bilateral track will have had months longer to place megawatts privately.
That recalculation cuts both ways. If updated forecasts show less large-load growth than the July forecast assumed, the target could shrink, and the backstop that eventually opens could be materially smaller than the hole it was conceived to fill — the cost-causation principle working as designed. If bilateral deals stall and updated forecasts hold or grow, the target could remain near its original size, and the full weight of a near-$555 procurement would fall on the growth-based allocation the amended filing creates. Either way, the number that matters in March will not be 6,831 MW. It will be whatever the updated arithmetic produces, minus whatever the bilateral track has already placed.
The arithmetic of the ceiling is worth keeping in view, with its limits stated honestly. If the full original target cleared at the $555 maximum, the annual cost would be roughly $1.38 billion, or about $20.8 billion over 15-year terms. That is a ceiling calculation, not a forecast: the $555 figure is a volume-weighted average maximum, not a single clearing price, and lower bids or bilateral offsets would reduce the total. But it frames what is at stake in the allocation fight — a billion-dollar-a-year procurement, assigned by zone on contested growth figures, with 15-year commitments attached.
There is also a timing problem the amended schedule does not solve, only compresses. Results would be posted May 10, 2027, for capacity serving a delivery year that begins June 1, 2028 — barely a year later. The resources the backstop buys must be new or previously uncommitted, and they must reach commercial operation by June 1, 2032, under the original design. Turbine backlogs measured in years and interconnection queues measured longer mean the backstop cannot conjure steel on a one-year horizon. What it can do is give financeable revenue certainty to projects already far enough along to commit — and to life extensions, uprates, and returning capacity that can meet the deadline. Judged against the July auction’s roughly 525 MW of new and upgraded supply, even a partial backstop success would be material. Judged against a 6.8 GW hole, it would still leave the question of what fills the rest.
The December auction, and what FERC must decide next
The backstop’s new timeline also reframes the December auction for the 2029/30 delivery year, which closes December 15. When this desk previewed that auction, the suspended backstop hung over bidding incentives: a generator that could wait for a 15-year contract at up to $555 had a reason to hold its best offer out of a one-year auction capped at $337.83. The amended filing, if accepted, sharpens that incentive rather than removing it, because it makes the second channel more credible — a defined March window, a published results date, and an allocation rule that answers FERC’s objection. December’s supply response should therefore be read with the backstop in mind: thin new supply in December may reflect rational waiting for March as much as physical absence.
Either outcome leaves the deeper question untouched. A capacity market that caps its regular auction at $325 — $337.83 for 2029/30 — while blessing $555 for a parallel procurement of the same product has split itself into two tiers, and the honest debate is whether that two-tier system is a sensible transitional design or an admission that the primary price has become decorative. The amended filing makes the second tier fairer in how its costs are assigned and more survivable in how its security is posted. It does not reconcile the two prices. That reconciliation is the design work for the first auction with no collar, and the backstop’s fate — filed October 29, awaiting FERC’s answer — is the first test of whether that work will be done on a schedule the reliability problem respects.
Sources: PJM, “PJM Files Amended Reliability Backstop Proposal,” Inside Lines (Oct. 29, 2026); PJM, Tariff Section 9.2(b) stakeholder consultation presentation, Special Members Committee (Oct. 22, 2026); FERC, 196 FERC ¶ 61,245, Dockets ER26-3380-000 and EL26-108-000 (Sept. 29, 2026); U.S. Department of Energy, Notice of Intervention and Statement of Position in ER26-3380-000 and EL26-108-000 (Oct. 7, 2026); PJM, 2028/2029 Base Residual Auction results (July 14, 2026); prior Fracmoo coverage: “FERC Froze PJM’s Backstop Auction” (Oct. 13, 2026) and “December’s Auction Will Test What FERC’s Order Changed” (Oct. 28, 2026).