MISO Dark Spread Doubled in 2025 as Coal Undercut Gas, Complicating Winter Grid Planning
Coal-fired generation delivered margins in 2025 that gas plants could not match across much of the US Midwest, a reversal with direct implications for how grid operators plan their winter fuel mix. The dark spread in the Midcontinent Independent System Operator footprint — the difference between the coal generation cost and the wholesale electricity price — doubled from $11 per megawatt-hour in 2024 to $23 per megawatt-hour in 2025, according to EIA data.1
NERC's winter reliability assessment, published June 2 (2026-06-02), flagged capacity adequacy concerns across parts of the Eastern Interconnection. The bulk power system is forecast to add 20.2 gigawatts, or 2.5%, of new capacity relative to the prior winter, but the split between dispatchable and intermittent resources remains a pressure point as thermal retirements accumulate.5
The arithmetic behind the MISO spread shift was stark. Average electricity prices in the footprint rose 44% from 2024 to 2025, while coal fuel costs increased just 3%.1 Gas plants did not benefit at the same scale: natural gas prices rose 63% over the same window, compressing the spark spread gain to 18%, with gas margins moving from $12 per megawatt-hour in 2024 to $14 per megawatt-hour in 2025.1
MISO's own seasonal readiness data underlines why fuel economics matter. During recent cold events, peak demand in the footprint reached 108 gigawatts while renewable output contributed only 19 gigawatts, leaving the dispatchable thermal fleet to cover the remainder.6 Incremental outages during those periods reached 9 gigawatts, triggering uplift costs of $1.5 million over a three-day window — a narrow outcome that illustrates how little room exists in the stack during cold snaps.
ERCOT faces a different composition challenge. Texas solar is forecast to generate 78 billion kilowatt-hours in 2026, overtaking coal at 60 billion kilowatt-hours, according to EIA projections.2 The shift makes ERCOT's thermal backup capacity more critical during winter mornings and evening peaks, when solar output drops near zero and temperatures fall.
Load growth forecasts are steepening the reliability challenge across all three regions. Data centers now account for roughly half of incremental US power demand growth, according to the International Energy Agency's global energy assessment.3 The EIA's long-run projections show server electricity consumption reaching between 446 billion and 818 billion kilowatt-hours annually by 2050, from an estimated 7% of commercial building electricity use in 2025.2 Reserve margin calculations are being revised faster than utilities can complete interconnection studies for the infrastructure needed to serve the load.
Extreme heat adds a generation-side constraint. Gas turbine output drops roughly 10% at high ambient temperatures without mitigation, with each 4-degree-Fahrenheit reduction in inlet temperature recovering about 1% of capacity, according to a July 2025 Burns & McDonnell engineering analysis.7 Inlet air cooling retrofits can recover approximately 10% of that performance loss for unmitigated units. For MISO and PJM, where summer demand records have tested dispatchable limits in recent years, this becomes a reliability variable rather than a one-off operational concern.
Current spot markets reflect summer balance. PJM Western Hub stands at $42.83 per megawatt-hour and MISO Indiana Hub at $42.00 as of Tuesday (2026-07-07). NYMEX Henry Hub front-month natural gas trades at $3.22.
The contrarian read on coal's margin improvement centres on supply-side vulnerability. The dark spread advantage depends on coal prices remaining contained, which is sensitive to rail disruption and US mine production constraints. International price signals are moving in the opposite direction: API2 coal front-month is showing bearish momentum, suggesting softer global demand that could create divergence between export coal pricing and US domestic delivery costs. Whether utilities rebuild coal stockpiles this summer — or draw them down into winter — is a direct variable for the reliability margin.
NERC's assessment also coincides with unresolved transmission constraints slowing the interconnection queue across PJM, MISO, and ERCOT.4 FERC's transmission upgrade deadlines, which regional operators have sought to extend, determine whether new capacity reaches the grid before the next stress event. The resources exist in the queue; permitting and construction timelines determine whether they arrive before demand does.