Coal Holds Generation Edge in MISO as Gas Cost Gap Persists Into Summer
Coal-fired generation in the Midcontinent Independent System Operator held a widening economic advantage over natural gas through the first months of 2026, with EIA data published in May showing that a steep rise in gas prices had largely eroded the spark spread gains that gas-fired units needed to compete for dispatch.1
The dark spread for coal in MISO — the margin a generator earns above fuel costs when running coal-fired capacity — rose from $11 per megawatt-hour in 2024 to $23 per megawatt-hour in 2025, a 111 percent increase. The spark spread for gas-fired units moved from $12 to $14 per megawatt-hour over the same period, an 18 percent gain.1 Average wholesale electricity prices in MISO climbed 44 percent between 2024 and 2025, while coal costs edged up just 3 percent. Natural gas surged 63 percent, absorbing most of the electricity price tailwind before it could widen gas margins.1
The numbers describe a fuel-stack shift that most participants in the MISO dispatch market did not anticipate entering 2025. Gas had been gaining market share in recent years as low hub prices held spark spreads competitive. The reversal does not indicate any lasting recommitment to coal — regulatory pressure on the sector continues to accumulate — but it does mean coal plants are capturing a larger share of economic runtime than the region's long-run trajectory would suggest is sustainable.1
MISO seasonal readiness data from early June showed peak demand projections at 108 gigawatts, with 17 gigawatts of incremental outages anticipated during high-stress periods and renewable output of 19 gigawatts at those intervals.3 Uplift costs over three-day stress windows were running between $1.5 million and $4 million depending on temperature and unit commitment efficiency, a range consistent with a grid that remains tight enough to lift real-time prices materially when demand spikes.3
MISO Indiana Hub spot power was priced at $42.00 per megawatt-hour as of June 28, 2026. The consensus among market signals leans modestly bullish for MISO real-time power, but a contrarian supply-side view argues the upside is constrained — a split that reflects the underlying dynamic in which improved coal economics have added available generation to the stack at precisely the price levels that would otherwise support a more definitive upward move.
Grid policy adds another variable. Following a Federal Energy Regulatory Commission directive in late 2021, major regional transmission organizations including MISO were instructed to upgrade infrastructure and expand capacity. Several operators requested an extension of that deadline in May 2026, citing the pace of construction and interconnection work.2 Delayed transmission investment tends to keep cheaper renewable generation bottled up away from load centers, which sustains congested-zone real-time prices but also extends the economic life of thermal plants — including coal — that operate inside those transmission constraints.2
NYMEX Henry Hub front-month gas was at $3.23 per million British thermal units as of June 28, 2026. That level still leaves the fuel cost differential between coal and gas largely intact. If storage injection-season volumes build strongly enough to pull hub prices lower through the summer, coal's dark spread advantage would compress and dispatch would shift modestly back toward gas peakers. A sustained stretch of demand above the 108-gigawatt seasonal projection would push in the opposite direction, keeping real-time prices elevated and sustaining coal's current position in the merit order.3
Whether summer heat or a cooling injection season settles the current dispatch balance will be clearer by mid-July, when peak demand patterns and storage trends typically diverge from the range of forecasts framing the market now.