​Winter Storm Fern hit MISO on January 23-26, 2026, bringing some of the coldest temperatures in decades to the Upper Midwest. Grand Rapids recorded -19°F on January 24, Minneapolis hit -21°F on January 23, and Flint reached -24°F, just one degree above its all-time record.

MISO was prepared for the worst as the bulk power system held and no load was shed due to generation shortfalls.

Prices told a more complex story: Minnesota saw real-time LMPs spike to 5.3x historical P99 levels—meaning prices exceeded the 99th percentile of the prior year's hourly prices by more than five times. Louisiana, by contrast, barely exceeded normal winter ranges at 1.4x P99, still notable but far less extreme. Fuel diversity and regional transmission constraints explain the divergence.

Key Takeaways

• Minnesota real-time prices hit $1,351/MWh while Louisiana peaked at $314/MWh. The 4x gap reflects transmission bottlenecks that prevented lower-cost generation from reaching Minnesota.
• Gas and coal provided 69% of generation. Less efficient peaking units running at elevated fuel costs contributed to price spikes in constrained regions.
• BESS capture opportunities were highest in MISO North. Minnesota's TB4 real-time spread reached $2,873/MW-day on January 23 compared to $650-730/MW-day in MISO South.
• A 200 MW, 4-hour BESS at the Minnesota Hub would have earned approximately $2,875/MW-day on January 23—4.5x higher than the same asset in Louisiana at $640/MW-day.

​How the storm played out on MISO's grid

​The stress came fast and markets responded in stages:

• January 23: Demand exceeded forecasts by 3,100 MW. Prices spiked that evening—Minnesota hit $1,247/MWh at 6 PM.
• January 24: Day-ahead markets priced in the stress at $366-420/MWh. Wind swung from 2,900 MW overnight to 19,500 MW by morning. Gas plants absorbed the variability.
• January 26: Markets overcorrected. Demand came in 3,600 MW below forecast as traders overestimated lingering cold.

​Day-ahead markets struggled to price regional divergence accurately. DA underestimated Minnesota Hub by $894/MWh at the peak while overestimating Louisiana Hub by $712/MWh—a $1,600/MWh swing in forecast error between North and South.

For BESS operators, these DA-RT spreads represent additional capture opportunity beyond pure arbitrage.

​Prices diverged by a factor of four between North and South

The price divergence reflects MISO's unique geography. The North-South constraint is contractual, not physical.

When Entergy joined MISO in 2013, only about 1,000 MW of direct transfer capability existed between the regions; with the remainder flowing through SPP and TVA systems. A 2016 settlement capped transfers at 3,000 MW northbound and 2,500 MW southbound. During Fern, cheaper generation stayed trapped while prices spiked elsewhere.

​Minnesota's average real-time LMP across the storm reached $206/MWh. Illinois averaged $118/MWh. The 75% gap stems from congestion: Minnesota saw +$31/MWh average congestion while Illinois experienced -$42/MWh. Illinois could access cheaper sources of generation while Minnesota sat behind transmission bottlenecks.

The divergence matters for BESS siting. A battery in Minnesota would have captured the $1,351/MWh spike. The same asset in Louisiana would have seen $314/MWh. Location drove a 4x difference in peak revenue opportunity.

​Fuel diversity prevented a repeat of Winter Storm Uri

Winter Storm Uri's defining feature—which forced widespread blackouts across Texas in 2021—was forced outages of thermal generation through loss of fuel supply or plant-level failure. Over 40% of gas and coal capacity went offline. Fern was different: MISO reported forced outage rates well below 10%, a fraction of Uri's failures.

​Natural gas plants ramped flexibly, providing 36% of total generation across the storm. Coal added another 33%. Nuclear held constant at 13%, providing baseload stability. The reliance on thermal generation, particularly less efficient peaking gas units, contributed to elevated prices in constrained regions.

Wind proved volatile but net positive. Output swung from 2,900 MW to 22,900 MW hour-to-hour, stressing the grid. Gas plants absorbed the variability, ramping down 43% during wind surges. The fuel mix worked because it could flex.

​Three findings matter for BESS in MISO:

• Storm capture is real, but location dependent. Minnesota offered $2,873/MW-day TB4 spreads, while Mississippi offered $678. Same storm, same weekend, 4x difference in returns.
• Grid improvements have compressed the tail. Uri saw Minnesota TB4 spreads above $10,000/MWh. Fern delivered $2,873. Weatherization and fuel supply contracts since 2021 have reduced extreme spikes. Don't underwrite for Uri.
• Congestion patterns are predictable. Minnesota's +$31/MWh average congestion versus Illinois's -$42/MWh reflects transmission topology that persists across stress events. Site accordingly.

​BESS is purpose-built for this kind of volatility.

Unlike gas plants that face fuel delivery risk and elevated commodity costs during winter stress, batteries respond in seconds rather than minutes. At scale, BESS discharging into scarcity hours would compress the spreads themselves, capturing value while reducing system costs.