A single scarcity event on March 17 defined March spreads in MISO, similar to Winter Storm Fern. Real-time prices at Indiana Hub hit $1,288/MWh at 10 AM local time, more than 20 times the monthly average of $41.45/MWh. Top-bottom spreads expanded at northern hubs, led by Michigan ($293/MW-day real-time) and Indiana ($288/MW-day). MISO North day-ahead (DA) prices averaged $35.36/MWh against MISO South at $30.95/MWh, a gap that widened sharply during the event.

Key takeaways

• Top-bottom spreads expanded system-wide: Indiana Hub four-hour real-time spreads averaged $288/MW-day (up 38% year over year) while Michigan posted the highest at $293/MW-day. Southern hubs experienced minimal YoY change, unlike February 2026.
• Indiana day-ahead prices cleared $9.14/MWh above Arkansas, reflecting tighter northern reserve margins; four-hour real-time spreads rose 38-39% year over year at Indiana and Michigan, while Indiana day-ahead spreads ran 27% above Arkansas.
• Real-time prices hit $1,288/MWh at 10 AM on March 17, the only hour above $200 all month. Operators not positioned to discharge during that window missed the bulk of March's incremental value.
• Natural gas generation averaged 22,146 MW, up 29% year over year filling gaps left by lower wind output and reduced nuclear availability.
• Day-ahead regulation averaged $16.65/MWh, while real-time regulation spiked to $47/MWh on March 17 when co-optimized dispatch drove all ancillary prices higher simultaneously.

Hub prices diverged between MISO North and South

Indiana Hub day-ahead prices averaged $38.82/MWh for the month, up 4.9% year over year, while real-time averaged $41.45/MWh, up 10%. Michigan Hub posted the highest day-ahead average at $39.53/MWh. In MISO South, Arkansas Hub cleared $29.68/MWh day-ahead, a $9.85/MWh discount to Michigan, with Louisiana and Texas hubs clustered near $31.80/MWh.

​Four-hour top-bottom spreads expanded across the system. Indiana Hub led in day-ahead at $137/MW-day, up 21% year over year. RT spreads in Indiana reached $288/MW-day, a 38% increase, while Michigan posted the highest RT spread at $293/MW-day, up 39%. The northern outperformance is consistent across both day-ahead and real-time: Indiana exceeded Arkansas by 27% on DA TB4 spreads.

​The north-south divergence reflects higher industrial load density and fewer import paths in MISO North versus surplus Gulf Coast gas capacity in MISO South. Constrained transfer capability between regions amplifies the gap when supply tightens.

The March 17 scarcity event made that structural gap visible. Day-ahead prices peaked at $62.08/MWh that day, while real-time hit $94.28/MWh. On quiet days like March 8, day-ahead fell to $28.34/MWh and real-time to $23.08/MWh.

March 17 scarcity event

Winter Storm Iona swept through the MISO footprint from March 14 to 16. By March 17, the post-storm arctic air mass pushed system demand to 91 GW at 6 AM, the highest hourly load of the month. Gas generation surged to 45 GW, nearly double the March average, but wind had collapsed to half its normal level and 30 GW of generation sat offline for planned spring maintenance. The system was running 17 GW above its typical output and it still was not enough.

Total generation peaked at 87 GW at 7 AM then began falling as gas units ramped down through the morning. Load was falling too, but generation fell faster. At 10 AM the gap closed: real-time prices at every MISO hub jumped to more than 30 times the monthly average. By noon, wind had doubled from its morning trough and solar was generating 15 GW. Prices collapsed back to $30/MWh. One hour of scarcity on a system already stretched to its limit.

The supply stack behind those price levels shifted sharply toward gas

Natural gas averaged 22 GW in March 2026, up from 17 GW a year earlier. That 30% increase filled two gaps. Nuclear output fell from 10 GW to 8 GW as spring refueling took approximately 1.85 GW offline. Wind generation declined 7.4% year over year on weaker resource conditions.

Coal ran at 19 GW, near minimum economic dispatch. Neither sustained low gas prices nor higher renewable penetration materialized in March, capping the midday price floor for BESS charging. Solar peaked at 12.5 GW at midday, cutting net load by over 26 GW compared to overnight hours. BESS charged an average of 316 MW at 1 AM, exploiting overnight low prices.

The fleet discharged 331 MW at 5 PM as solar output fell and the evening ramp steepened. The installed BESS fleet in MISO remains small relative to the midday surplus, leaving room for more storage before charging economics deteriorate.

Ancillary services: regulation dominated, co-optimization amplified the spike

Day-ahead regulation averaged $17/MWh, the most bankable ancillary product for BESS given its lower hour-to-hour variance. Real-time regulation cleared the highest ancillary average at $20/MWh. Day-ahead spinning reserve averaged $2.81/MWh, with supplemental reserve marginal at $0.31/MWh.

MISO's dispatch drove all ancillary prices higher in lockstep with the energy spike on March 17: real-time regulation averaged $47/MWh, spinning reserve $33/MWh, and supplemental reserve $33/MWh. Outside the event, real-time spinning reserve averaged roughly $1/MWh.

Year over year, ancillary prices varied by product outside the March 17 spike: day-ahead regulation edged up 6 percent while real-time regulation fell 13 percent. The event itself accounted for the bulk of the monthly change. Capacity committed to lower-value services that day missed the spike entirely.

MISO Outlook

The March 17 scarcity event was the defining moment of the month. BESS positioned to discharge during that window captured the month's highest spreads.

Northern hubs maintained a structural premium throughout March. Four-hour real-time spreads at Michigan and Indiana exceeded Arkansas by 31% and 29% respectively. As heating demand fades into spring, the midday solar trough will replace supply-side scarcity events as the primary spread driver, but the north-south gap is likely to persist as long as transfer constraints keep MISO North supply-tight.