EAGLEVILLE, PA — Wholesale electricity costs across the nation’s largest regional power market surged 50.3% during the first half of 2026, driven by higher energy prices and a tripling of capacity costs that an independent market monitor attributed in part to projected data center demand.
The total cost of wholesale power within PJM Interconnection’s territory increased to $114.50 per megawatt-hour from $76.16 a year earlier, according to a report from Monitoring Analytics, the independent monitor overseeing PJM’s markets across 13 states and the District of Columbia.
Capacity costs climbed 207.1%, reaching $19.61 per megawatt-hour from $6.39 during the first six months of 2025. Energy costs increased 47.7% to $72.68 per megawatt-hour, while transmission costs rose 5.6% to $19.88.
The market monitor calculated that including projected data center demand in PJM’s capacity market increased overall wholesale power costs by $11.11 per megawatt-hour during the first half of 2026, accounting for 9.7% of the total. That estimate excludes any additional effects on energy and transmission costs.
Independent Market Monitor Joseph Bowring determined that PJM’s energy market produced competitive results but concluded its capacity auctions for the 2025-26, 2026-27 and 2027-28 delivery years did not.
“Our analysis concludes that the results of the capacity market auctions for the 2025/2026, 2026/2027, and 2027/2028 Delivery Years were not competitive, primarily as a result of the inclusion of forecast demand for data centers,” Bowring stated.
The monitor recommended excluding forecast data center demand from capacity auctions and requiring data centers to provide their own new electricity generation to prevent other customers from absorbing the associated costs.
PJM’s real-time, load-weighted average electricity price increased 40.2%, rising to $72.54 per megawatt-hour from $51.75 during the same period in 2025.
Transmission-constraint penalty factors accounted for $9.43, or 45.3%, of the $20.79 increase. Fuel and consumables contributed $7.26, market-power components added $1.82, and emissions costs accounted for $1.06.
Transmission congestion costs climbed 179.9% to approximately $3.54 billion from $1.26 billion.
Customers recovered only 55.7% of congestion charges during the 2025-26 planning period through auction revenue rights and self-scheduled financial transmission rights, leaving them underpaid by $2.2 billion, according to the monitor.
The report identified that shortfall as the largest customer underpayment recorded during a single planning period. Since the 2011-12 planning period, customers have received $7.1 billion less in congestion revenue than they should have because of flaws in PJM’s financial transmission rights market, the monitor concluded.
Additional charges used to cover certain power system operating costs nearly doubled, increasing 98.9% to approximately $1.13 billion from $569.2 million.
Average hourly electricity demand rose 2.5% to 93,187 megawatt-hours from 90,914 megawatt-hours during the first six months of 2025.
Natural gas generation increased 2.6%, while oil-fired generation climbed 29.7%. Solar output rose 23.9%, wind generation increased 2.1%, and coal-fired generation declined 3.2%.
Higher electricity prices also increased theoretical energy-market net revenue across generation technologies, a measure used to assess incentives for building power plants.
Projected net revenue rose 198% for a new diesel facility, 125% for a new coal plant, 108% for a new combustion turbine and 76% for a new combined-cycle plant.
Comparable revenue increased 40% for new nuclear and offshore wind facilities, 25% for onshore wind installations and 13% for solar projects.
Support the local news that supports Chester County. MyChesCo delivers reliable, fact-based reporting and essential community resources—free for everyone. If you value that, click here to become a patron today.