By Mark Jaffe, EUCI energy writer
Wholesale electricity prices in the U.S. are projected to rise by an average 12% this summer, and while the margin between demand and generation capacity will be thinner, there should be adequate capacity, according to a Federal Energy Regulatory Commission (FERC) assessment.
Electricity demand this summer is expected to be higher than it was for the last four years and reach a new peak demand.
The U.S. Energy Information Administration (EIA) projects this summer’s demand will be 3.2% above the five-year average of 1,469 terawatt-hours (TWh). For August, the highest use month, the load is forecast to be 420 TWh, a 3.7% increase from August 2024.
“If anticipated warmer-than-average temperatures occur, the electric grid will likely be challenged throughout the continental United States with increased uncertainty due to weather events, weather forecasting, and energy demand,” FERC said.
Utilities are required to have a “reserve margin” – generating capacity above the projected need. FERC said “margins are getting tighter as generation resources retire and load increases largely due to hyperscale users, such as data centers.”
The shift from retiring baseload generation, such as coal-fired plants, to variable capacity, including wind and solar, is part of the challenge.
“We are losing dispatchable generation at a pace that is not sustainable and we are not adding sufficient equivalent generation capacity,” FERC Chairman Mark Christie said in a statement. “Today’s assessment brings that point home.”
Regional grids facing tight generating margins include New England, the Midcontinent Independent System Operator (MISO), the PJM Interconnection, the Southwest Power Pool (SPP) and the Electric Reliability Council of Texas (ERCOT).
While the EIA projects an average wholesale electricity price of $43.90 per megawatt-hour (MWh), prices will vary widely by region.
The New York Independent System Operator (NYISO) is forecasted have the biggest increase – 30% over 2024, with an average summer price of $51.65/MWh.
The prices for the SPP, which covers all or parts of 14 states from Texas to North Dakota, are projected to rise 22% to $52.96 a MWh, compared to last summer. ISO New England will see a 14% increase with an average summer price of $48.47 a MWh.
The only region set to see a decline in wholesale electricity prices is Texas, where the grid operator, ERCOT plans to add about 20 gigawatts of new summer capacity.
ERCOT summer prices are projected to drop 10% to $35.02 a MWh compared to the summer of 2024.
“The increase in prices is partially due to higher natural gas prices at all major trading hubs across the country because of lower natural gas storage levels due to a colder winter than previous years,” FERC said.
Natural gas prices will likely be higher at all major trading hubs across the country compared to summer 2024.
At the Henry Hub, the futures contract price as of May 1 averaged $3.76 per million British thermal units (MMBtu) for this summer, 68% higher than last summer’s futures price average of $2.24 for MMBtu.
The FERC assessment warned that extreme weather and wildfire risks may create added challenges for grid reliability this summer.
Persistent high temperatures and sparse rainfall, already forecast for July will create an elevated risk of wildfires for several states, including California, Northwest Texas, and Oklahoma.
“Increased uncertainty—driven by factors such as tight electricity supply and demand, the growing frequency of extreme weather events, and weather forecast uncertainty—poses significant challenges to the electric grid for summer 2025, particularly with respect to load forecasting,” FERC said.
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