The US Department of Energy issued an emergency order allowing extra power generation across the PJM Interconnection as unusual October heat and rising demand raise blackout risks for more than 67 million people.

Energy Secretary Chris Wright signed the directive under Section 202(c) of the Federal Power Act. The order runs from October 13 through October 16, directing PJM to dispatch specified units and permitting backup generation as a last resort before or during an Energy Emergency Alert Level 3.

Weather and maintenance tighten supply

The intervention comes during the fall maintenance season, when weather conditions are constraining grid flexibility. The National Weather Service forecast record or near-record warmth across parts of the Ohio Valley and Mid-Atlantic. Highs are expected in the upper 80s Fahrenheit in central Indiana and well into the 80s around Washington and Baltimore.

PJM coordinates electricity across all or parts of 13 states plus Washington, D.C. The grid operator stated that recent capacity auctions reflected "tightening supply and increasing demand outpacing new supply," while it works to connect large data centers without sacrificing reliability or affordability.

AI infrastructure drives long-term pressure

The immediate emergency order highlights a structural challenge facing US utilities: the rapid expansion of artificial intelligence infrastructure. Federal regulators recently approved a PJM registry for data centers as electricity demand from those facilities is projected to triple to 29 gigawatts by 2030.

Power availability has emerged as a major bottleneck for the AI data-center buildout. Separate projections indicate that AI-related electricity demand could surge sharply through the next decade, exacerbating the supply-demand imbalance visible in current capacity auctions.

Broader reliability efforts expand

This is not the first use of emergency authority by the administration this year. In July, the Department of Energy issued similar PJM orders during a severe heat wave as electricity demand approached record levels and generator outages tightened supply. That earlier intervention also authorized additional generation to protect grid reliability.

Separately, the Department of Energy announced plans on Tuesday to support 84 Tennessee Valley Authority transmission and distribution projects across eight states. The roughly $581 million package, including $250 million in federal funding, is expected to add about 2.5 gigawatts of grid capacity and improve reliability for 2.58 million families and businesses.

What the numbers show

The juxtaposition of short-term emergency measures with long-term infrastructure spending reveals a widening gap between immediate capacity needs and future demand growth. While the current order addresses a four-day window of weather-driven stress, the projection that AI demand will triple to 29 GW by 2030 suggests that temporary dispatch orders may become insufficient without permanent capacity additions. The $581 million investment in TVA projects adds only 2.5 GW, a fraction of the projected AI-driven load increase, indicating that near-term reliability will likely continue to depend on regulatory interventions rather than solely on new build-out.

PJM Interconnection’s wholesale electricity market recorded a sharp rise in costs during the first half of 2026, with the total cost per MWh increasing 50.3% to $114.50 from $76.16 in the same period of 2025. According to the 2026 Quarterly State of the Market Report for PJM: January through June, released by Monitoring Analytics, LLC, the Independent Market Monitor (IMM), this surge was primarily driven by a 207.1% spike in capacity costs and a 47.7% rise in energy costs.

While the IMM concluded that the energy market results were competitive, it found that capacity market auctions for the 2025/2026, 2026/2027, and 2027/2028 delivery years were not competitive. Joseph Bowring, the Independent Market Monitor, attributed this lack of competitiveness to the inclusion of forecast demand for data centers in the capacity market. The report recommends excluding forecast data center demand from the capacity market and requiring data centers to bring their own new generation to prevent imposing significant costs on other customers.

Cost Drivers and Market Performance

The real-time load-weighted average Locational Marginal Price (LMP) increased 40.2% to $72.54 per MWh from $51.75 per MWh in H1 2025. Of the $20.79 per MWh increase in LMP, nearly half ($9.43 per MWh or 45.3%) was attributed to transmission constraint penalty factors, followed by fuel and consumables costs ($7.26 per MWh or 34.9%).

The inclusion of data center load in the capacity market directly contributed to an $11.11 per MWh (9.7%) increase in the total cost of wholesale power, raising it from $103.40 to $114.50 per MWh. This figure excludes the impact on energy or transmission costs.

Generation Mix and Load Trends

Real-time hourly average load rose 2.5% to 93,187 MWh from 90,914 MWh in H1 2025. The generation mix shifted significantly, with solar unit generation increasing 23.9% and oil unit generation rising 29.7%. Natural gas generation grew 2.6%, while coal generation declined 3.2%. Wind generation saw a modest 2.1% increase.

Theoretical energy market net revenues surged across most generation types, indicating strong investment incentives. Revenues for new combustion turbines increased 108%, combined cycle plants 76%, and coal plants 125%. Solar installation revenues rose 13%, while onshore and offshore wind revenues increased 25% and 40%, respectively.

What the Numbers Show

A significant divergence exists between congestion revenue generated and revenue returned to customers. Total congestion revenue increased 179.9% to $3,539.7 million from $1,264.7 million in H1 2025. However, only 55.7% of total congestion paid by customers was returned through Annual Revenue Rights (ARR) and self-scheduled Financial Transmission Rights (FTR) revenues. This resulted in a $2.2 billion underpayment to load in the 2025/2026 planning period, marking the largest single-period underpayment in PJM history. Cumulatively, from the 2011/2012 period through 2025/2026, customers have received $7.1 billion less in congestion revenues than entitled, citing flaws in the FTR market design.

Additionally, total energy uplift charges nearly doubled, rising 98.9% to $1,132.5 million from $569.2 million in H1 2025. This suggests that while marginal units generally operated near short-run marginal costs, high markups for some units and binding transmission constraints continued to impose additional costs on consumers beyond standard energy payments.