Coal's dispatch edge in MISO widens as dark spreads outpace gas margins into 2026
EIA data show coal's generation economics in MISO pulling further ahead of gas, with dark spreads averaging $28/MWh in early 2026 against a spark spread of just $9/MWh.
The MISO Indiana Hub spot price closed Friday (2026-08-14) at $44.52/MWh, according to market data. The number itself is unremarkable for mid-August. The fuel economics underneath it are not.1
EIA data published on May 20 show that dark spreads in MISO averaged $28/MWh in the first four months of 2026, up 39% from the same period in 2025. Spark spreads over the same window averaged just $9/MWh, a 15% year-on-year gain that looks thin beside coal's margin. The gap between those two numbers is the clearest single measure of how dispatch economics in the region have shifted.1
The divergence has been building for two years. From 2024 to 2025, average MISO electricity prices rose 44% while coal costs climbed only 3%, pushing the dark spread from $11/MWh to $23/MWh — an increase of 111%. Natural gas fared worse: prices jumped 63% over the same period, compressing the spark spread to just a $2/MWh gain, from $12/MWh to $14/MWh in 2025.1
A coal plant with a $23/MWh dark spread in 2025 could absorb far more price pressure before going uneconomic than a gas unit running a $14/MWh spark spread. With spreads now sitting at $28/MWh versus $9/MWh, that bidding advantage has widened further. Coal units can set the marginal clearing price at levels that leave gas peakers out of the money.1
Winter Storm Fern adds a complication to the first-quarter 2026 picture. Daily average MISO power prices exceeded $260/MWh from January 26 (2026) to January 28 (2026), even as electricity demand during those six days ran 11% below the same weekday period before the storm. Those extreme prices inflated the early-2026 dark spread average, and the EIA flagged that the $28/MWh figure reflects Fern's pricing effects. Strip out the storm window, and spreads likely sit closer to the $23/MWh 2025 average — still strongly supportive of coal dispatch, but less emphatic than the headline number suggests.1
Policy is adding pressure on a separate axis. In April, incumbent utilities in MISO and SPP used grid strain from data center demand growth and aging transmission to argue against competitive transmission development, as Vanderbilt Law School professor Jim Rossi wrote on August 10 (2026-08-10). If incumbents succeed in limiting new competitive entrants, renewable capacity faces higher interconnection barriers, which over time preserves coal's share of real-time dispatch. That outcome is far from settled.4
NERC's Summer Reliability Assessment noted that emergency orders extended plant availability requirements into late May and early June, keeping some units in service that had not been counted in summer resource adequacy calculations.2 MISO's own June 3 seasonal readiness data showed two discrete stress windows: one with 17 GW of incremental outages, peak demand at 108 GW, and renewable output at 19 GW, requiring 5 GW of uplift at a three-day cost of $4 million; a second window with 9 GW of incremental outages and $1.5 million in three-day uplift costs.3
The drop from 17 GW to 9 GW in incremental outages between those two windows points to improving availability. If that trajectory extends into the autumn shoulder season, uplift requirements shrink and real-time prices could soften even with coal's spread advantage intact. Five signals in the consensus view weight toward higher MISO real-time prices at 59% directional strength. But a contrarian bearish signal on the supply side carries a -0.70 reading at 45% confidence, suggesting some market participants see generation availability recovering faster than demand into the fall.3
The transmission fight will not resolve quickly. Rossi's August 10 piece frames the April utility push as the opening move in a longer regulatory contest over who builds the grid serving data center load growth. How that plays out determines how much new renewable capacity can reach MISO dispatch — and by extension, how long coal holds its current marginal pricing position.4
For traders pricing the fall shoulder, the September incremental outage tally is the more immediate signal. If MISO's availability continues recovering from the 9 GW level seen in the June data, scarcity uplift shrinks and real-time prices face downward pressure. If outages stall or transmission constraints tighten ahead of winter, coal's grip on marginal dispatch holds — and the $28/MWh dark spread, storm distortion or not, keeps gas peakers on the sidelines.3