On Friday morning, PJM will open the most consequential conversation about its capacity market since the market itself was designed. From 9 a.m. to noon, in a Webex workshop under the Power Reliability Through Market Design initiative, PJM staff and stakeholders will work through more than 30 papers filed in response to the grid operator’s May white paper, which offered the region three broad pathways and recommended none of them. The agenda is narrow in form — state feedback, then PJM’s next steps — but the substance is the question every other fight in this market has circled all year: when a market cannot buy enough capacity at any price it is allowed to charge, what changes — the market, the promise, or the price?
That question is no longer abstract. PJM’s July auction for the 2028/29 delivery year cleared at the $325/MW-day price cap in every zone and still procured only 138,318 MW of unforced capacity, plus 10,864 MW under Fixed Resource Requirement arrangements, against a reliability requirement of 156,013 MW — a shortfall of 6,831 MW, the second consecutive auction in which the region as a whole missed its requirement. The miss was driven by a roughly 2 GW rise in forecast demand, largely from data centers, against a supply response of about 525 MW of new generation and upgrades.
The paper that framed the choice
The workshop’s starting document is PJM’s May 6 white paper, Powering Reliability Through Market Design, written at the direction of the PJM Board, which in January told staff to examine whether the capacity market design and investment incentives still fit a region where demand was rising faster than at any point in decades and new supply was taking longer to build. The diagnosis was blunt: a single-year commitment procured three years forward may not match the financing needs of new supply, capped prices send signals investors discount, and demand is growing faster than the system can add generation. PJM President and CEO David Mills put it in one sentence: “The current situation is not tenable.”
The paper then did something unusual for a grid operator: it laid out three paths and refused to choose. Path A, “Stabilized Markets,” would preserve the capacity market but require most load to be covered through long-term forward commitments — either mandatory hedging by load-serving entities or PJM-administered long-term procurement. Path B, “Differential Reliability,” would accept that scarce capacity must be rationed and build a formal plan for deciding who gets curtailed, and in what order, when there is not enough to go around. Path C, “Energy Market Transition,” would shift revenue recovery from the capacity market to the energy and ancillary services markets, with the capacity market demoted to a backstop, paired with long-term forward energy contracting to protect consumers from price volatility. PJM’s own framing is that the paths are not mutually exclusive — and that the region may need to move on several tracks at once.
Path A: make the promise financeable
Stabilization is the least disruptive of the three paths, and the one with the most visible machinery already in motion. Its logic is straightforward: the capacity market fails as an investment signal not because the price is too low — three auctions at the cap have shown the price can be high and still not finance entry — but because a one-year commitment cannot support a power plant. A developer weighing a gas turbine with a lead time of three years or more, against a backlog that GE Vernova put at 116 GW in the second quarter of 2026, cannot underwrite construction on a single year of capped capacity revenue.
The attractions are real. Long-term commitments are the one mechanism in this debate with a demonstrated ability to get steel in the ground: the Reliability Backstop Procurement, PJM’s one-time 15-year contracting channel for the July shortfall, was designed on exactly that logic, at up to $555/MW-day. And Path A preserves what the states most want to keep — the shared reliability compact, the principle that capacity is bought for all network load alike and that no customer class is formally ranked for curtailment. The Organization of PJM States, in principles its board approved unanimously on October 15, made preservation of both its first principles.
The costs are equally real, and they land on the bill. Long-term commitments transfer risk from developers to whoever signs them: if load forecasts prove wrong — and this year they have been wrong in both directions, with the market monitor documenting that 4,017 MW, or 42 percent, of the forecast increase in data-center load between the 2026/27 and 2028/29 delivery years had been canceled or delayed as of September 21 — somebody is paying for capacity the region does not need, for years. Path A also leaves the hardest design question unanswered: who decides how much hedging is enough, and what counts as a hedge.
Path B: say out loud who loses power first
Differential reliability is the path nobody wants to discuss and the one the facts keep forcing onto the agenda. Its premise is that the shared reliability compact — one standard, one pool of capacity, one price for all — cannot be maintained for all load under structural scarcity, and that the honest response is to ration on principle rather than by accident. PJM is already working on one element of it — the “connect and manage” process for large loads that connect without their own new power supplies. The harder extensions are formal curtailment priorities among customer classes or regions.
The political shape of this path is already visible. Commissioner David Rosner, concurring in FERC’s October 9 order on PJM’s large-load package, warned against a market that reports adequate capacity while shedding load involuntarily, and said that in an emergency, data centers not serving critical functions should be curtailed before homes, hospitals, and schools. That is a statement about emergency priorities, not a tariff rule — curtailment decisions remain with states and distribution utilities — but it signals where the Commission’s sympathy lies.
The case for Path B is that rationing is already happening informally, and informality is the worst form of it. When the July auction came up 6,831 MW short, load hedged through self-supply or bilateral contracts was not exposed to the clearing price, and PJM has noted that such load eats first in a rationed market. A formal plan would at least make the ranking explicit and contestable. The case against it is that explicit rationing is a political act no institution in this region has the authority to perform cleanly: FERC rejected the curtailment and bring-your-own-capacity frameworks in PJM’s large-load package precisely because aspects of the proposal intruded on retail rate regulation. A curtailment list written by states would differ by state — thirteen lists, not one. And Path B does nothing, by itself, to build generation. It manages the shortage; it does not end it.
Path C: rebuild around energy, and accept the volatility
The energy market transition is the most ambitious path and the slowest to arrive. Its logic is that the capacity market has become a crutch: if energy and ancillary services prices were allowed to reflect scarcity — through higher scarcity pricing, stronger reserve and flexibility incentives, and performance requirements — generators would earn their investment case from operating in tight hours rather than from a one-year capacity payment. The capacity market would shrink to a backstop, catching revenue shortfalls rather than setting the investment signal. Paired with long-term forward energy contracting requirements, the path is meant to protect consumers from the price volatility that scarcity pricing would otherwise deliver straight to the bill.
The appeal is coherence. A market that pays for energy, reserves, and flexibility in the hours they are actually scarce rewards the resources the system increasingly needs — fast-start generation, storage, flexible demand. Maryland’s consumer advocate urged PJM to keep improving energy and ancillary services incentives without prematurely shifting away from the capacity construct.
The risks are the reason Path C is framed as a multi-year transition rather than a switch. Scarcity pricing strong enough to finance new entry is strong enough to produce bills that no regulator wants to defend — and the forward energy contracting meant to shield consumers is itself a long-term commitment, carrying the same forecast-error risk as Path A’s hedging. There is also a sequencing problem: the energy market reforms that would make the transition feasible are, by PJM’s own timeline, a 2028-and-beyond project, while the capacity shortfall is a 2028/29 delivery-year fact. Path C cannot fix the auction that closes December 15. It can only promise that the auction after next will operate in a different market.
The states arrive with their own document
Friday’s agenda gives the first word to the states, and that ordering matters. The Organization of PJM States will present its market reform principles, summarized by OPSI’s Ben Sloan, and the Public Utilities Commission of Ohio will present Ohio’s statement on PJM market reforms, summarized by Tim Benedict. OPSI’s document, approved unanimously by its board on October 15, is a guardrail exercise: preserve the capacity construct, preserve the shared reliability compact, address the incremental risks new large loads create during scarcity, and do not expect market redesign alone to solve a challenge driven by unprecedented forecast growth from large loads.
A complaint, a deadline, and an auction that will not wait
The workshop does not happen in a vacuum. Eight days ago, Exelon filed a complaint at FERC asking the Commission to order PJM to move to a prompt capacity auction held two months before the delivery year, starting with the 2030/31 delivery year, arguing that the three-year-forward schedule is no longer just and reasonable because forecasts keep proving wrong after the price is set. The complaint, docketed as EL27-11, asks FERC to rule by January 31 — the last day before PJM is due to publish planning parameters for the 2030/31 Base Residual Auction, scheduled for May 2027. PJM has said it is reviewing the complaint; FERC has not ruled.
Exelon’s complaint and Friday’s workshop are different instruments aimed at the same diagnosis, and they pull in different directions. The complaint is narrow and fast: change the timing of the purchase, price the forecast error out of the bill, and let FERC decide by January. The workshop is broad and slow: redesign the market’s foundations through a stakeholder process with no deadline. But the two are linked by the calendar. If FERC orders a prompt auction for 2030/31, the first auction with no price collar — the May 2027 auction, the one the workshop’s redesign is supposed to inform — would be conducted under a schedule the workshop never contemplated. The region is, in effect, running two redesigns at once, on two clocks, with no mechanism to reconcile them.
December’s auction is the third clock, and the fastest. The Base Residual Auction for the 2029/30 delivery year closes December 15 — the fourth and final auction under the price collar, capped at $337.83/MW-day, against a reliability requirement of 158,712 MW, 2,699 MW higher than the year before. It is also the first auction since FERC’s October 9 order accepted the Large Load Registry and rejected the curtailment and bring-your-own-capacity frameworks, and the first in which generators must weigh a one-year commitment at the capped price against holding their best offers for the backstop’s 15-year contracts at up to $555/MW-day — a backstop FERC suspended until February 28, 2027, pending a paper hearing. December’s results will be read as evidence in every argument Friday’s workshop produces — and December is the last auction under the current design.
What to watch on Friday
Three things, in the order they will become visible. First, whether the states’ presentations converge or diverge. OPSI’s principles and Ohio’s statement are both state documents, but they are not the same document, and the distance between them will show whether the states can present a united position to FERC or whether PJM will be arbitrating among its own regulators. Watch in particular for daylight on Path A: the states’ support for long-term commitments is the closest thing to a consensus in the filings so far.
Second, how the 30-plus stakeholder papers divide. The count itself is the news: more than 30 responses to an August call for papers, from generators, consumer advocates, states, and environmental groups, is a measure of how widely the market’s failure is now felt. But the division matters more than the count. If the papers cluster around targeted fixes — hedging, the registry, connect-and-manage — the workshop will ratify incrementalism. If a bloc forms around one of the three paths, Friday becomes the day the redesign acquired a constituency.
Third, whether anyone says the quiet part out loud: that the December auction and the May 2027 auction are the last two data points before the market either gets a new design or gets one imposed on it. The collar expires after December. Exelon has asked FERC to decide by January 31. The backstop’s paper hearing runs to February 28.