By Jason Charles Guck, Business Development, Delta Edge CI
In the space of two days at the end of September, the largest grid in the United States demonstrated two completely different answers to the same problem. One is now frozen by regulators for five months. The other was signed and announced the following morning.
For anyone buying power in PJM territory, the contrast is the story.
The shared fix, now suspended
PJM operates the grid across 13 states and the District of Columbia. It is short roughly 6,831 megawatts of capacity for the 2028/29 delivery year.
That gap exists despite the regular capacity auction doing everything it could. The auction for that year cleared at its price cap of $325 per megawatt-day and still brought in only about 525 megawatts of new generation. A market hitting its ceiling and returning that little new supply is telling you something plainly: the price signal is maxed out and the resource is not appearing.
To close the shortfall, PJM proposed a one-time Reliability Backstop Procurement with an offer cap of $555 per megawatt-day, calculated on a megawatt-weighted average basis across the delivery period. Bidding was scheduled to run from September 30 to October 21.
It did not open. On September 29 the Federal Energy Regulatory Commission accepted parts of the proposal and suspended it until February 28, 2027, finding that three elements may be unjust and unreasonable: how the costs would be allocated among customers, the rules governing a transmission owner that leaves PJM, and the collateral required from the utilities that buy power on customers’ behalf.
That collateral question is not academic. Northern Virginia Electric Cooperative put its own exposure at roughly $2 billion.
FERC Chair Laura Swett was unusually direct about the filing: “This commission will not be forced into accepting a deeply flawed, eleventh-hour procurement mechanism with billion-dollar implications for consumers.”
The private deal, now signed
One day later, on September 30, Constellation and Amazon announced a 20-year power purchase agreement at the Calvert Cliffs Clean Energy Center in Lusby, Maryland.
The agreement covers 690 megawatts, a figure that includes a planned uprate of approximately 190 megawatts of new generating capacity coming online between 2030 and 2032, alongside more than $3 billion of infrastructure investment in Maryland. The power supports Amazon’s operations across the PJM footprint, and the plant continues to serve the regional grid.
Worth noting the difference in mechanism. The uprate adds genuinely new megawatts to an existing plant. Most of the 690, however, is existing output now committed under contract for two decades.
What this actually means for a commercial buyer
Three things follow, and none of them require a view on nuclear policy or data centre growth.
The market-wide remedy is not arriving this winter
A five-month suspension means the shared mechanism for filling a 6,831 megawatt hole is paused until the end of February, and then has to survive a review of how its costs get divided. Planning on that resolving quickly, or on the terms PJM proposed, is planning on an outcome nobody can currently predict.
Who pays is genuinely unsettled
The specific thing FERC flagged is cost allocation. That is the question of which customer classes carry the bill for new capacity. For a commercial operator, that is not a technicality. It is the difference between a cost that lands on your rate class and one that does not, and it will be decided over the next several months in a public docket.
The largest buyers are not waiting
This is the part that deserves the most attention. While the shared process is frozen, the biggest consumers of power are contracting directly, for twenty years at a time, for firm output from existing plants.
Capacity committed under a long-term bilateral agreement is capacity that is no longer available to the rest of the market. That is not a criticism of the buyers, who are behaving rationally. It is simply the arithmetic. Scarcity plus private contracting means the terms available to everyone else tend to get worse, not better, as more of these deals are signed.
What to do about it
An operator cannot sign a twenty-year nuclear agreement. What an operator can do is know their own exposure before the costs land.
- Find your capacity charge and write down the number. It appears on the bill as capacity, installed capacity or peak load contribution, usually stated in kilowatts. It is set by your demand during a handful of system peak hours in the prior summer, and the mechanics are covered in our post on how capacity tags are set.
- Establish which service class you are in. Cost allocation decisions are made by class. If you do not know yours, you cannot read a FERC docket that applies to you, and you will find out what it decided when the bill changes.
- Put your supply contract end date in the budget. If you are fixed through a date, you are insulated until then and exposed afterwards. In a market where the largest buyers are locking in twenty-year terms, knowing your own renewal window is the minimum.
- Plan next summer’s peaks now. Your capacity cost for the following year is set during a few hours next June through September. That is the one input in this entire story you control directly.
The honest limits
This is a developing regulatory matter and the dates above are the ones on record as of early October 2026. The suspension could end differently, the cost allocation could be revised, and PJM could refile. Anything here that affects a budget should be confirmed against the current docket before you build a number on it.
What is not in doubt is the shape of the problem. Capacity is scarce, the rules for who pays are open, and the organisations that understand their own position early will negotiate from a better place than those who discover it on an invoice.
If you operate in PJM territory and want your capacity exposure quantified against your actual bills and renewal calendar, that is work we do at Delta Edge CI.