​Combined four-hour BESS revenue potential in MISO reached $60/kW-month at Indiana Hub in February, driven by a two-day cold snap that sent real-time prices above $1,100/MWh. Northern hubs averaged above $50/MWh in the day-ahead market while southern hubs stayed in the low $30s. From February 10 onward, day-ahead prices at northern hubs fell to $30–45/MWh.

In this benchmark, Modo Energy reviews MISO wholesale prices, BESS arbitrage spreads, generation mix, and ancillary service trends for February 2026.

Key takeaways

• Michigan and Indiana hubs averaged above $50/MWh in the day-ahead market while Arkansas and Texas stayed below $34/MWh.
• Four-hour real-time TB4 spreads outpaced day-ahead by 148%, rewarding operators with intraday market exposure.
• Wind output fell 4.6% year over year and missed the highest-priced hours, dropping the capture rate to 91.2%. Higher system prices still lifted absolute wind revenues 23.6%.
• Natural gas prices swung from $2.98 to $6.88/MMBtu, pushing implied heat rates above 27 MMBtu/MWh during the cold event. Scarcity, not fuel cost, set wholesale prices.
• BESS charged during midday solar surplus and discharged at the evening peak, demonstrating the arbitrage cycle that will intensify if solar capacity grows into summer.

MISO North priced at a $20/MWh premium to the South after early-February cold snap

On February 1–2, Winter Storm Fern drove heating demand across the Midwest while forced thermal generator outages reached 11,000–13,300 MW. Real-time prices at Indiana Hub, the reference hub, topped $1,100/MWh. A late-month spike on February 26 briefly lifted prices, but day-ahead prices otherwise averaged $30–45/MWh from February 10 onward.

Full-month day-ahead averages by hub:

• Michigan Hub: $51.84/MWh (highest)
• Indiana Hub: $51.55/MWh
• Texas Hub: $33.48/MWh
• Arkansas Hub: $31.07/MWh

The $20/MWh north-south gap reflects transmission constraints that kept cold-snap pricing concentrated in the Midwest. Indiana and Michigan offered the strongest BESS arbitrage signals; southern hubs saw muted price action throughout.

MISO’s generation stack shaped the arbitrage window as gas and coal ramped around solar output

Gas and coal provided the bulk of MISO's generation, with gas units ramping sharply during morning and evening peaks. Nuclear ran flat as baseload. Wind contributed most overnight; solar carved a midday trough in net load that defined the BESS charge window.

Henry Hub natural gas ranged from $2.98/MMBtu on February 18 to $6.88/MMBtu on February 4. The $3.90/MMBtu swing widened the gap between gas-on-the-margin hours and off-peak, directly expanding the BESS arbitrage window.

On February 2, the day-ahead implied heat rate hit 27.6 MMBtu/MWh — scarcity pricing well above marginal gas costs. By mid-month, heat rates fell to 9–11 MMBtu/MWh. When heat rates exceeded 20 MMBtu/MWh, day-ahead prices at Indiana Hub averaged above $100/MWh while off-peak held near $30/MWh, producing the wide spreads BESS captured. As heat rates normalized, peak and off-peak converged and the arbitrage window compressed.

Four-hour real-time BESS spreads at Indiana Hub doubled year over year

Day-ahead averages reflect 24 trading days (day-ahead market data unavailable for February 9, 20, 21, and 22). Real-time averages are matched to the same 24 days for comparability.

Winter Storm Fern drove most of this outperformance. Day-ahead prices were roughly $80/MWh below real-time on February 1–2, with midday real-time prices at $27–30/MWh and evening peaks averaging $90/MWh at hour 17.

Indiana and Michigan offered the highest spreads. Illinois Hub day-ahead four-hour spreads reached $144/MW-day (+10.7% year over year); Arkansas fell 30.6% to $85/MW-day. Indiana Hub's four-hour day-ahead spread exceeded Arkansas Hub's by 109%.

Four-hour real-time spreads at Indiana Hub exceeded day-ahead by 148%. Operators with real-time exposure captured nearly 2.5 times the revenue available through day-ahead scheduling alone.

Wind capture rate fell 5.7 points as output missed the highest-priced hours

Wind's capture rate fell to 91.2%, down 5.7 percentage points from 96.9% a year earlier. Generation-weighted prices averaged $53.33/MWh versus the time-weighted system price of $58.46/MWh.

Price spikes on February 1–2 occurred when wind output was well below its hourly norm. Because those hours carried an outsized share of the monthly price average, even modest underperformance dragged the capture rate down. Total wind generation fell 4.6% year over year to 8,839 GWh, reducing wind's share of the supply stack during the hours when prices were highest.

Wind's generation-weighted price of $53.33/MWh still exceeded last February's $43.16/MWh by 23.6%. Higher system-wide prices lifted absolute revenues even as the capture ratio fell.

Midday solar surplus and evening ramp defined the BESS arbitrage cycle

Net load ranged from approximately 53,000 MW at hour 14 to 69,300 MW at hour 18. The 16.3 GW swing between midday and evening defines the arbitrage window.

Solar surplus pushed midday real-time prices to daily lows ($27–30/MWh, hours 12–15). Batteries charged during those hours, absorbing 245 MW on average at hour 13 (source: MISO real-time generation data for registered BESS assets), and discharged 335 MW at the evening peak (hour 17) when gas and coal ramp to meet post-solar demand.

The scatter of hourly price against system demand separates into two regimes: an early-February cluster above $100/MWh at moderate demand, and a post-event cluster below $60/MWh at comparable demand. Temperature, not load alone, determined price during the cold event.

Regulation spiked to $94/MWh during MISO’s cold days

Day-ahead Regulation averaged $17.45/MWh for February; real-time averaged $22.11/MWh. On February 2, real-time regulation hit $94.48/MWh. Co-optimization amplified the spike: when energy prices surge, opportunity costs pull regulation higher.

Day-ahead Spin Reserve averaged $2.63/MWh and real-time averaged $4.13/MWh — marginal compared with $444/MW-day from four-hour real-time energy arbitrage.

Regulation has grown structurally. After MISO raised regulation procurement to 600 MW and tripled the value of lost load (VOLL), the penalty price for unserved energy, to $10,000/MWh, day-ahead regulation climbed from $10.91/MWh in 2023 to $17.34/MWh in 2025, with early 2026 averaging $23.59/MWh. As energy spreads narrow into spring, Regulation's share of the BESS revenue stack will grow because spreads compress faster than regulation prices soften.

Outlook for MISO

Winter Storm Fern created outsized BESS opportunities in MISO for the second month running, particularly at Indiana and Michigan hubs. The more actionable finding is the widening day-ahead to real-time gap: four-hour real-time spreads at Indiana Hub exceeded day-ahead by 148%.

As heating demand fades into spring, the midday solar trough will replace cold snaps as the primary spread driver.