​784 MW of BESS operate in MISO today while 49 GW move through the interconnection queue. Merchant revenues are currently insufficient for batteries in MISO’s 49 GW queue to pencil.

State mandates and utility integrated resource plans (IRPs) can close the financing gap. All together, they target 7,730 MW by 2030. Illinois and Michigan through legislative mandates, and Minnesota, Missouri, and Indiana through utility offtake.

State mandates convert policy targets into bankable revenue. Utilities must sign long-term offtake agreements regardless of merchant conditions, giving lenders the contracted cash flows needed to underwrite project finance.

​Key takeaways

• Merchant BESS cannot rely on arbitrage revenues alone as day-ahead spreads for four-hour systems stay below $200/MW-day across MISO.
• Illinois and Michigan mandate 5,500 MW combined by 2030. Just 119 MW operates between them in MISO’s footprint. This is the largest mandate-to-deployment gap in any US market.
• Indiana leads MISO at 337 MW operational BESS through utility offtake from NIPSCO and AES Indiana, not mandates. This model works but offers no legislative certainty.
• Minnesota offers the strongest 2025 real-time TB4 spreads of $243/MW-day, adding arbitrage potential. However, interconnection costs as high as $80 million create execution risk.

​Why can't merchant revenue justify MISO BESS alone?

MISO's system is tightening. Summer capacity auction prices rose from $30/MW-day in 2024 to $666/MW-day in 2025 . Yet even at current clearing prices, capacity revenue covers less than 15% of a four-hour BESS project's annual revenue requirement. Energy arbitrage and ancillary services must fill the rest.

But spreads swing too widely to bankroll a project alone. Average four-hour day-ahead spreads at Indiana Hub moved from $202/MW-day in 2022 to $101/MW-day in 2023, then recovered to $163/MW-day in 2025. That 50% year-on-year swing makes revenue projections unreliable for project finance. Outside Minnesota, no state consistently produces returns that support a merchant business case.

​​Three developer profiles emerge:

• Conservative (Indiana, Missouri): Proven utility offtake, manageable queues, and existing grid infrastructure. Lower upside but lower execution risk.
• Growth-oriented (Illinois, Michigan): Mandate-backed procurement guarantees the largest capacity targets but requires navigating untested permitting paths and legal uncertainty.
• Arbitrage-focused (Minnesota): The strongest merchant economics in MISO, but only viable for developers who can absorb interconnection costs.

​Illinois and Michigan mandate 5,500 MW but operate only 119 MW

Legislative mandates give utilities no discretion. They must procure specified BESS capacity regardless of merchant conditions. Illinois and Michigan are the only MISO states with this mechanism. Together they target 5,500 MW. Today, 119 MW operates. Both states face a gap between policy ambition and current operational deployment.

​Illinois targets 3,000 MW by 2030 from a 4 MW base

Illinois enacted the Clean and Reliable Grid Affordability Act in January 2026. The law mandates 3,000 MW of BESS by 2030 across Ameren and ComEd territories. Only 4 MW operates within MISO's Illinois footprint today; an additional 96 MW operates in ComEd territory within PJM. Ameren's MISO footprint presents a greenfield opportunity with near-zero queue congestion relative to Michigan or Minnesota. However, no completed MISO-side project exists and therefore lenders have no performance benchmark to underwrite against.

Michigan targets 2,500 MW by 2029 with the most aggressive timeline

Michigan set a 2,500 MW target for DTE Energy and Consumers Energy by 2029, one year ahead of every other MISO state. The state operates 115 MW today. Public Act 233 allows developers to bypass local zoning by routing projects above 50 MW through the Michigan Public Service Commission. In a market where county-level opposition has historically stalled projects, this is a meaningful advantage.

​Two risks threaten this advantage:

• Transmission Constraints: Michigan's Lower Peninsula connects to the broader MISO grid through a handful of high-voltage corridors. Until MISO's long-range transmission upgrades land, BESS projects siting away from existing capacity face material network upgrade cost exposure.
• PA 233 challenges: 109 Michigan municipalities are challenging the MPSC's PA 233 implementation order before the Michigan Court of Appeals. If they prevail, developers lose the right to bypass hostile local permitting entirely.

​Minnesota, Missouri, and Indiana rely on utility offtake, not mandates

Mandates give Illinois and Michigan statutory certainty that IRP states cannot match. The remaining three states rely on utility planning cycles that can be revised or abandoned on three-to-five-year timelines. For developers, this creates a fundamentally different risk profile.

Minnesota combines the strongest arbitrage with the highest interconnection risk

Xcel Energy's IRP targets 1,230 MW of BESS by 2030. The state's 60% wind penetration drove four-hour day-ahead spreads of $243/MW-day, higher than other MISO states.

Nevertheless, interconnection costs offset these strengths. One developer withdrew a 100 MW project after MISO assigned $80 million in network upgrade costs. Developers who can absorb this risk gain first-mover advantage.

Missouri plans 1,000 MW by 2030 through coal retirement replacements

Ameren's Missouri IRP commits 1,000 MW of BESS by 2030, driven by coal plant retirements. Land costs at $4,800 per acre are almost half the cost in Illinois or Indiana. Its six-project queue is the smallest in MISO.

However, Missouri has no state permitting framework for standalone BESS. Every project requires local county approval, and some jurisdictions restrict BESS to solar-accessory use only.

As of Februray 11, 2026, Missouri’s first 400 MW BESS project was approved, meeting 40% of Ameren’s announced IRP.

Indiana proves utility offtake works without mandates

Indiana leads MISO with 337 MW of operational BESS, all built through utility offtake from NIPSCO and AES Indiana. AEP's 765 kV backbone provides high-voltage injection points at retiring coal plants with minimal upgrade costs.

​How should developers choose between these five states?

Projects backed by utility offtake in mandate states are most likely to reach operation. The rest of the 49 GW queue will thin dramatically. Between the 5 states, the question is which risks a developer can manage and which ones they cannot. In mandate states, the offtake agreement is the revenue. Utilities procure by law, not by choice. That obligation converts a legislative target into a contracted revenue stream that project finance lenders will accept.