Electricity markets pay generators for two different things, and confusing them is the reason a lot of recent bill increases look inexplicable.
The first is energy: actual megawatt-hours produced and delivered. The second is capacity: a commitment to be available if called upon, whether or not you are ever called. The capacity payment is not for electricity. It is for readiness.
Why readiness has to be paid for separately
A power system has to meet demand on its single worst hour, which in most of the country is a January evening or a July afternoon. Meeting that peak requires plants that will run for a few dozen hours a year and sit idle the rest of the time.
A plant like that cannot survive on energy sales. It has fixed costs every day of the year: staff, maintenance, insurance, fuel contracts, debt service. If it were paid only for the megawatt-hours it produced, it would close, and the grid would then be short precisely on the day it could least afford to be.
The capacity market exists to solve that. Generators bid the annual payment they need to stay available. The market operator buys enough to meet forecast peak demand plus a reserve margin, and everyone who clears is paid the same clearing price. Utilities buy that capacity on behalf of their customers, and the cost lands on retail bills.
What happened in PJM
PJM is the wholesale market covering thirteen states and the District of Columbia, from Illinois east to New Jersey and south to Virginia. Its capacity auction for the 2025/2026 delivery year cleared at a record price, and the 2026/2027 auction stayed high.
Three things moved at once.
- Demand grew faster than forecast. Data centres are the largest single driver, concentrated in northern Virginia, central Ohio and northern Illinois. Load forecasts were revised upward repeatedly.
- Supply shrank. Older coal and gas units retired on economics and environmental compliance, removing capacity from the pool.
- Replacements did not arrive. New generation sat in an interconnection queue that takes years to clear, so the projects that would have offset the retirements were not yet available to bid.
A tighter reserve margin means a higher clearing price. That is the mechanism working as designed: a high price is the signal that the system needs more capacity. The signal is expensive for the people paying it.
How it reached residential bills
In restructured states, utilities no longer own generation. They buy default supply through periodic auctions, and those auctions price against the wholesale market including capacity. When capacity repriced, the next default-service auction repriced with it, and the increase appeared on bills within months rather than being spread over years.
This is why the increase looks so uniform across states with nothing else in common. Illinois and Ohio are Midwestern; Maryland and the District are import-dependent; Pennsylvania is a large net exporter of electricity; New Jersey is dense and restructured. Their generation mixes, politics and utility structures differ completely.
PJM states, year over year
Change measured May 2025 to May 2026. The average across these nine jurisdictions is +14.8%.
| State | May 2026 (¢/kWh) | May 2025 | Change | vs. U.S. |
|---|---|---|---|---|
| Illinois | 23.85 | 18.58 | +28.4% | +29.3% |
| District of Columbia | 25.40 | 20.43 | +24.3% | +37.7% |
| Virginia | 17.61 | 15.26 | +15.4% | -4.5% |
| Maryland | 21.77 | 19.00 | +14.6% | +18.1% |
| Ohio | 19.52 | 17.09 | +14.2% | +5.9% |
| New Jersey | 23.27 | 20.48 | +13.6% | +26.2% |
| Pennsylvania | 21.55 | 19.29 | +11.7% | +16.9% |
| Delaware | 19.38 | 18.13 | +6.9% | +5.1% |
| West Virginia | 16.80 | 16.18 | +3.8% | -8.9% |
Northern Illinois cleared even higher than the rest of PJM because it was treated as a separate constrained zone, which is why ComEd customers saw the sharpest single-year move in the country.
Where capacity markets do not exist
Texas is the deliberate counter-example. ERCOT has no capacity market at all. Generators earn from energy and ancillary services only, and scarcity pricing during tight conditions is the mechanism meant to signal new investment. The design is philosophically cleaner and it puts more risk on generators, but it also means Texas prices can spike violently when the system tightens, as they did during Winter Storm Uri.
Most of the South and West have no organised capacity market either, for a different reason: their utilities are vertically integrated. A regulated utility plans its own capacity, builds it, and recovers the cost through rate base under commission supervision. The capacity still gets paid for; it just happens through a rate case rather than an auction.
What you can do about it
Not much directly, which is worth saying plainly. Capacity costs are a wholesale market outcome and no household action changes them.
Two things are worth knowing, though. First, if you are shopping for a competitive supplier, ask whether capacity is included in the quoted rate. Some contracts quote energy only and pass capacity through separately, which makes the headline number look better than the bill will be.
Second, demand response programmes exist precisely because reducing peak demand reduces how much capacity has to be bought. Many utilities in PJM states pay households to let a thermostat or water heater be controlled during a handful of peak hours a year. The payments are modest but the programme is one of the few places where a household interacts with the capacity market directly.
For where your own state landed, the year-over-year comparison shows all 51 jurisdictions, and each state page explains what drove its particular number.