Coal Holds a $19/MWh Edge Over Gas in MISO as Fuel Cost Gap Widens

Coal plants in the Midcontinent Independent System Operator region earned roughly three times the margin of gas-fired units in the first four months of 2026, as natural gas price volatility eroded the economics that had made gas the default dispatch choice across the 12-state grid. The dark spread—power prices minus coal fuel costs—averaged $28/MWh through April, up 39% from $20/MWh a year earlier, according to EIA data. The equivalent spark spread for gas plants averaged $9/MWh, a $19/MWh gap that has shifted which fuel wins the dispatch order when grid operators clear the market. The divergence traces to sharply different fuel cost trajectories. Gas for power generation in MISO rose 63% between 2024 and 2025, while coal costs climbed 3%. That pushed the dark spread from $11/MWh in 2024 to $23/MWh in 2025—a 111% increase—even as wholesale electricity prices rose 44%. Gas plants captured almost none of that power price gain; the spark spread moved only $2/MWh over the same period because higher fuel costs absorbed the revenue. The dynamic was acute during Winter Storm Fern. On January 27, gas for power generation spiked from $25/MWh a week earlier to $549/MWh as heating demand competed with generation for pipeline supply. Coal prices were unmoved. Unlike gas, which can be rerouted to pipeline-connected plants within hours, coal requires roughly a month of transport lead time, insulating spot prices from demand shocks. Over six days surrounding the storm, MISO power prices exceeded $260/MWh from January 26 through 28, even though electricity demand ran 11% below typical weekday levels. The dark-spark differential reached $530/MWh—the widest on record—as gas generators faced margin compression and coal units captured the spread. MISO's experience contrasts with both PJM to the east, where different transmission constraints produce different dispatch outcomes, and ERCOT in Texas, where solar is forecast to generate 78 billion kilowatthours in 2026 against 60 BkWh for coal—the first year renewables have outrun coal annually in that grid. Coal retirements across MISO have slowed despite long-run pressure from renewables and environmental regulation. On-site fuel storage—typically 30 to 90 days of inventory—provides a buffer that gas plants lack when pipelines tighten during weather events, and that reliability is now priced into dispatch economics. The test comes this summer. June-through-August air conditioning demand will push day-ahead prices higher across MISO, but summer gas volatility is typically lower than winter. If heat events stress gas supply the way January's cold snap did, dark-spark differentials will widen again. Forward dark spreads beyond August will indicate whether utilities see coal's current advantage as a weather-driven anomaly or durable enough to push retirement decisions past 2027.