MISO's Coal Windfall Is Masking a Gas Volatility Trap

MISO's Coal Windfall Is Masking a Gas Volatility Trap Dark spreads are at multi-year highs, spark spreads are compressed, and Entergy is still queuing gigawatts of new gas capacity into MISO. Entergy's capacity additions to MISO have an unusual look. According to a Utility Dive analysis of the updated fast-track interconnection list released on Wednesday (2026-05-27), Entergy's gas-fired projects account for nearly a third of the roughly 28 gigawatts in the Midcontinent Independent System Operator's expedited approval queue, with about 70% of Entergy's planned additions gas-fired.³ That bet on gas is being placed against spread data that should raise questions. EIA figures show dark spreads — the margin for coal-fired generation in MISO — averaged $28 per megawatt-hour through the first four months of 2026, 39% wider than the same period in 2025.¹ Spark spreads for gas generation averaged just $9/MWh over the same stretch. Coal is generating more than three times the margin of gas in the same grid region. The divergence has accelerated sharply. From 2024 to 2025, average electricity prices in MISO rose 44%, while coal costs increased only 3%, pushing the dark spread from $11/MWh to $23/MWh.¹ Natural gas prices rose 63% over the same period, compressing the spark spread to a gain of just $2/MWh from $12/MWh to $14/MWh. A year ago, coal and gas were generating roughly comparable margins in the region. They no longer are. The consensus sits firmly bearish on MISO real-time power prices, with bearish signals outweighing bullish by more than two to one. That read may be missing what the spread data reveal about structure, not just direction. Coal's dispatch dominance doesn't eliminate intraday volatility — it concentrates it. When coal capacity runs at its limit and demand pushes into gas units, gas becomes the price-setter, and the gaps can be severe. Winter Storm Fern showed the mechanism. Daily average power prices in MISO exceeded $260/MWh from January 26 to January 28, 2026, EIA data showed, even though electricity demand during those days ran 11% lower than comparable pre-storm levels.¹ The storm drove prices not through demand but through fuel-cost pressure on the marginal gas units clearing the market. Dark spreads through the first four months of 2026 still carry the Fern premium — the $28/MWh average is partly a consequence of those January days.¹ The second signal is in the interconnection queue. Entergy's gas projects filling a third of MISO's fast-track slots are not a bet on $9/MWh spark spreads persisting. They are a medium-term wager that power prices will rise — through load growth, coal retirements, or weather-event frequency — fast enough to justify gas generation at a far higher clearing level.³ Capital queuing for gas capacity in a region where gas currently captures thin margins is not irrational if you expect intraday spikes to become more frequent, not less. US grid operators have stretched federal deadlines on transmission infrastructure upgrades. Regional operators requested extensions on FERC-directed capacity programmes established in late 2021, according to industry reporting, slowing the reinforcement that would otherwise absorb load growth and dampen intraday swings.² AI data centre load arriving in MISO's territory before transmission can be expanded is a concrete demand increment rather than a distant hypothetical. None of this makes the bearish case on average power prices wrong. Coal's economics keep it in merit order, and a mild summer could easily keep MISO real-time prices subdued for months. But the distribution of outcomes is fatter on the upside than compressed spark spreads imply. The intraday hedging market launching new MISO and CAISO contract suites is pricing for tail events that the consensus is smoothing over. The test is practical. If peak cooling demand through July and August keeps gas units on the margin more frequently than seasonal norms, spark spreads will start recovering from $9/MWh. If Entergy's interconnection projects advance and capital allocation accelerates, that confirms the generation market sees higher long-run prices than spot spreads currently reflect. Either data point arrives before year-end.^3,1