Where electricity rates rose fastest

Six of the largest increases in the country happened in states that share almost nothing except a wholesale market. Illinois and Ohio are Midwestern; Maryland and the District of Columbia are mid-Atlantic import zones; Pennsylvania is a large net exporter of electricity; New Jersey is a dense restructured state. Their generation mixes, politics and utility structures differ completely. What they have in common is PJM.

PJM does two things. It runs an energy market, where generators are paid for the electricity they actually produce, and a capacity market, where they are paid simply to be available. The capacity auction for the 2025/2026 delivery year cleared at a record price. Demand had grown faster than forecast, with data centres the largest single driver, while older coal and gas units retired and new projects sat in an interconnection queue that takes years to clear. A tighter reserve margin means a higher clearing price, and capacity costs pass through to default-service customers.

The average increase across those six jurisdictions was 17.8%, against a national average of +6.2%.

Hawaii's increase is the largest in the country and has nothing to do with capacity markets. Hawaii burns imported petroleum to generate a large share of its electricity, on island grids with no interconnection to anywhere. Oil sets the marginal price, so the state's rate tracks world oil markets more directly than any other's. When crude moves, Hawaii moves, by more than any mainland state and faster.

The state has built enormous quantities of rooftop and utility-scale solar with battery storage, and that is steadily displacing oil. But displacing oil at the margin is the hard part: as long as an oil-fired unit is the last one dispatched on a given evening, it sets the price for everyone.

6 jurisdictions recorded a lower rate than a year earlier. None of them did so because of a general improvement in market conditions. Each has a specific mechanism behind it, and reading them together is the clearest available lesson in what actually moves an American electricity rate.

Connecticut is a base-effect story. Its public benefits charge rose steeply in 2024, driven by a long-term contract with the Millstone nuclear station and the recovery of pandemic-era arrears utilities had been ordered not to collect. Those items rolled off, and the charge fell back. Connecticut is not cheap. It remains well above the national average, just less inflated than it was.

New Mexico is the most instructive case. Its Energy Transition Act let the utility securitise the undepreciated cost of retiring coal plants, refinancing stranded cost with low-interest bonds instead of recovering it at a utility's much higher cost of capital, while replacement solar was procured at prices low enough that the transition lowered costs. That is a genuine, permanent saving rather than a deferral, and it is a model other states have started to copy.

Arizona benefits from the largest power plant in the country by output, the Palo Verde nuclear station, plus a rapidly growing solar fleet well matched to an air-conditioning load shape. California was essentially flat, which after several years of steep increases is itself notable.