NERC Sees 20.2 GW Capacity Gain for Next Winter but Data Centre Growth Strains Grid Planning
US bulk power capacity is expanding faster than peak demand in MISO and PJM, yet data centre load growth and fuel-switching economics are complicating the reliability picture.
The US bulk power system is forecast to add 20.2 gigawatts of net capacity — a 2.5% increase — ahead of winter 2026-27, according to NERC's Winter Reliability Assessment published on June 2 (2026-06-02).5 MISO Indiana Hub spot power was priced at $42.00 on Thursday (2026-07-02), a level that reflects neither the summer heat stress that regional operators are currently managing nor the residual structural tightness exposed during January's cold snap.
When temperatures in MISO dropped to 6.5°F on January 15-17 (2026-01-15 to 2026-01-17), peak demand hit 108 GW while renewable output reached only 19 GW and incremental outages totalled between 9 and 17 GW depending on the day, MISO seasonal readiness data show.7 Three-day uplift costs reached $1.5 million. January's performance showed that capacity additions on paper do not translate directly into reliability when the thermal stack runs against simultaneous extreme demand.
The fuel economics driving dispatch choices in the Midcontinent have shifted materially. EIA data show that in 2025 the dark spread — the margin between coal's fuel cost and the wholesale electricity price in MISO — averaged $23 per megawatthour, up 111% from $11/MWh in 2024.1 The spark spread for gas-fired generation rose only 18% to $14/MWh over the same period. MISO electricity prices increased 44% between 2024 and 2025, while coal fuel costs rose just 3% against a 63% increase in natural gas prices. Coal units have been running harder than their physical headroom might suggest, which raises utilisation questions heading into the next heating season.1
ERCOT tells a different story. EIA's Annual Energy Outlook 2026 projects solar generation in the Texas grid at 78 billion kilowatthours in 2026, above coal's 60 BkWh — a reversal that marks a shift in how the state covers midday demand.2 But solar's generation profile means thermal resources still set prices at morning and evening ramps, and the Texas grid has documented heat derating risks. A July 2025 Burns and McDonnell engineering analysis found that gas turbine output falls roughly 1% for every 4°F rise in inlet temperature, with unmitigated units losing approximately 10% of capacity above 90°F ambient.8 Inlet air cooling retrofits can recover roughly 10% of that derating, but adoption is not uniform across the fleet.8
Demand-side pressure is changing the planning baseline. The IEA found that data centres now account for approximately half of US incremental electricity demand growth.3 EIA projections show data centre servers consuming an estimated 7% of US commercial building electricity in 2025, rising to between 22% and 33% of commercial sector consumption by 2050.2 Regional grid operators requested an extension on a FERC deadline — originally set in late 2021 — to upgrade transmission infrastructure, citing permitting bottlenecks, supply chain constraints, and interconnection queues that cannot match the pace of data centre build-out.4 The US needs roughly 5,000 miles of new high-voltage transmission per year to accommodate the projected load growth, according to grid planning analysts.3
NERC's Summer Reliability Assessment published on June 3 (2026-06-03) describes elevated risk in several regions where generation additions are outpaced by demand growth projections.6 PJM Western Hub spot power was at $42.83 on Thursday (2026-07-02). Both MISO and PJM spot prices are currently well below levels that would signal summer scarcity, but the summer assessment identifies the same demand-growth asymmetries that shaped January's stress event.
The unresolved pressure heading into winter is whether the 20.2 GW of projected capacity additions arrive in the right locations before cold weather arrives. NERC's winter figure is a net system total; additions do not distribute uniformly across PJM, ERCOT, and MISO. For coal units running at elevated utilisation because of the dark-spark advantage, the relevant question is whether gas prices repeat the January spike — natural gas in MISO spiked from $25/MWh on January 20 (2026-01-20) to $549/MWh by January 27 (2026-01-27) during Winter Storm Fern while coal prices held flat — before the capacity math in critical zones has materially improved.1 Industrial natural gas consumption set a record 23.6 billion cubic feet per day in 2025, adding a further competing demand source if winter heating load coincides with cold-related production disruptions.2