MISO requires generators to guarantee they can deliver power during peak demand. MISO trades that obligation through a capacity market. Batteries can sell it.

The MISO Planning Resource Auction (PRA) clears just 10% of the region's capacity needs. Utilities self-supply the rest through bilateral contracts and integrated resource plans. In three of the four pre-seasonal planning years (PY 2019-22), the auction cleared under $10/MW-day. Summer 2025-26 changed that: $666.50/MW-day, a 22x increase over the prior year's approximately $30/MW-day.

Two structural changes drove the increase. The system surplus fell 60%, from 6.5 GW to 2.6 GW. That removed the cushion that had kept prices low. A new downward-sloping demand curve then replaced the old all-or-nothing pricing. The shrinking cushion now translates directly into higher prices.

Key takeaways

• MISO summer PRA clearing price rose 22x year over year, from $30/MW-day in PY 2024-25 to $666.50/MW-day in PY 2025-26, lifting the annualized price to approximately $215/MW-day.
• The system surplus fell 60% across three planning years (PY 2023-24 to 2025-26), from 6.5 GW to 2.6 GW, as 3.3 GW of thermal generation retired or entered suspension in PY 2025-26 alone.
• Summer captures 78% of annual capacity value, creating seasonal revenue concentration risk.
• Four-hour batteries receive a 95% administrative capacity credit, the highest among US ISOs. A new Direct Loss of Load (DLoL) methodology replaces this default in planning year 2028-29 and is expected to lower the credit to 50-65%.

How does a capacity auction work in MISO?

The table below summarizes MISO auction mechanics. Results are published by subregion (North/Central and South), with individual zones separating when local constraints bind.

The key detail: because the PRA handles only the residual margin, small changes in the surplus produce large price swings.

Did the MISO demand curve redesign reprice capacity?

The auction previously used a vertical demand curve. A one-gigawatt shift in supply could move the price from near-zero to the full Cost of New Entry (CONE) cap. Nothing existed in between. The old curve paid near-zero whenever supply exceeded the Planning Reserve Margin Requirement (PRMR), regardless of how slim the margin.

The result was extreme outcomes. In planning year 2022-23, North/Central zones were 1.2 GW short of the PRMR and hit CONE. South zones, in surplus, cleared near zero. The first seasonal auction (PY 2023-24) saw prices collapse to $10-15/MW-day as North/Central's surplus recovered. Planning year 2024-25 crept higher to $30/MW- day in summer. The vertical curve could not price the narrowing margin between surplus and deficit.

FERC approved a downward-sloping Reliability-Based Demand Curve (RBDC) for planning year 2025-26. The RBDC prices each MW according to its reliability contribution. Tighter supply now produces proportionally higher prices. Planning year 2025-26 CONE ranges from $321/MW-day (LRZ 10) to $373/MW-day (LRZ 5). These set the ceiling in each zone.

The RBDC also introduced an opt-out mechanism. Load-serving entities (LSEs) that self-supply their full requirement can exit the PRA for three consecutive planning years. Consequently, the auction now concentrates on genuinely uncommitted capacity. This produces a sharper price signal.

Tightening margins drove a 22x summer price increase

The price escalation tracks a shrinking surplus. Specifically, three factors drove the decline in planning year 2025-26:

• 3.3 GW of thermal generation retired or entered suspension
• 4.9 GW of existing capacity received lower accreditation under the new four-season framework
• A 0.8 GW increase in the planning reserve margin requirement compounded the gap

New additions partially offset these losses. Nevertheless, the system surplus fell 2.0 GW year over year.

The tightening started earlier at the zonal level. In particular, Zone 5 (Missouri) hit its CONE cap of $719.81/MW-day in planning year 2024-25. An 872 MW local deficit drove the breach. That zonal stress foreshadowed the system-wide repricing one year later.

The Organization of MISO States (OMS) 2025 survey projects 1.4 to 6.1 GW of surplus for summer 2026. By planning year 2027-28, the low end turns negative at -1.4 GW. Load growth of 2.2% per year is outpacing new interconnections. Data centers and re-shored manufacturing drive the demand. More than 300 GW sit in the queue across all technologies. If this trajectory holds, elevated PRA prices will persist through at least planning year 2027-28. MISO has introduced a fast-track queue for natural gas and BESS to meet this data center demand in the short term.

Where does the value land across seasons and zones?

Summer dominates, capturing 78% of annual capacity value. Fall 2025 diverged: North/Central at $91.60/MW-day, South at $74.09/MW-day. That was the first subregion-level price split since the seasonal redesign.

The subregion split matters for battery siting, even though the gap is small today. However, it could widen if South retirement patterns diverge.

MISO planning year 2026-27 Loss of Load Expectation (LOLE) study signals a seasonal shift. Winter's Planning Reserve Margin rose to 18.9%. Summer held at 7.9%. If winter tightening continues, capacity value could shift away from summer.

How do batteries earn capacity revenue in MISO?

Batteries participate in the PRA as Electric Storage Resources (ESRs). MISO launched this participation model on September 1, 2022, under FERC Order 841. The order required ISOs to create dedicated models for energy storage.

MISO assigns ESRs a default capacity credit based on maximum output duration:

• Two-hour systems: No official MISO figure published
• Four-hour systems: 95%
• Eight-hour systems: 95%

The 95% credit applies equally to four-hour and eight-hour systems. Duration beyond four hours adds no extra capacity value under the current methodology.

At planning year 2025-26 clearing prices, that credit yields approximately $75/kW-year for North/Central zones (price x days x 0.95 credit, summed across four seasons). That said, developers should stress-test against summer clearing prices reverting toward $200-300/MW-day.

How does this compare to other ISOs?

By comparison, other ISOs credit four-hour batteries significantly less. The chart below compares accreditation across PJM, NYISO, and MISO.

Developers entering MISO today are pricing a two-year window before that reset. ​Alongside ancillary services and energy arbitrage, capacity payments can anchor a BESS investment case in MISO. The new demand curve redesign, coupled with scarcity conditions, mean MISO’s capacity market may clear higher than previous auctions until a new methodology reset in PY 2028-2029.

For more information on Modo Energy’s MISO research offerings, reach out to william@modoenergy.com.