Midcontinent Independent System Operator [MISO]

Executive Summary​

• All zones met resource adequacy requirements across all four seasons​

• Summer price fell 36% YoY from $666.50(2025/26) to $424.30 as new capacity additions (+5.6 GW) outpaced retirements​

• Summer surplus recovered from 2.6 GW to4.6 GW, even as PRMR increased by 2.7 GW​

• RBDC in year 2 performed as designed as evidenced by the fact that all seasons cleared above reliability targets.​

  
  

Total Offered Capacity​

• Surplus above Initial PRMR grew 2.0 GW YoY despite PRMR rising 2.7 GW, confirming that new additions outpaced both retirements and higher requirements​

• OMS-MISO survey had projected 1.4–6.1 GW range; actual 4.6 GW (total) / 4.7 GW(waterfall chart) fell within range​

  
  

All Seasons Above Target​

• The sloped demand curve priced incremental reliability value above the minimum instead of collapsing to zero — a fundamental improvement over the prior vertical demand curve design​

• N/C effective summer margin: 12.0%; South:9.7%.​

Zonal Pricing Dynamics​

• N/C (Z1–Z7): $424.30. South Z8 & Z10:$384.10. South Z9: $412.10 (binding LCR needed more local capacity)​

• Fall, Winter, Spring cleared at uniform system-wide prices​

• No transmission congestion binding outside summer was observed​

• LRZ 9 cleared at $412.10, a $28/MW-day premium over the rest of the South because it faced a binding Local Clearing Requirement, not just a PRMR shortfall​

• This signals insufficient locally deliverable capacity and is a developer siting signal​

  
  

Wind and Solar are Growing But Concerns Mount in the Winter​

• Solar is now 8.6% of summer cleared SAC​

• Accreditation: 50% for Summer/Fall/Spring,5% for Winter. ​

• The 5% winter cap is the binding seasonal constraint - solar contributes only 0.8 GW in winter vs 12.2 GW in the summer​

• Wind summer ELCC fell from 20.8% to 18.2%per the LOLE study - a methodology-driven decline, not a fleet reduction. ​

• Wind remains critical in winter (7.0% of winter SAC vs. 3.9% summer), filling the gap left by Solar's 5% winter accreditation.​

  
  

Load Growth​

• Summer CPF rose from 122.6 GW (2025) to125.1 GW (2026) - the largest single-year jump in the dataset. ​

• PRM held flat at 7.9%; the full 2.5 GW CPF rise translated directly into a 4.8 GW increase in Final PRMR.​

• Member submissions escalated across each survey cycle. High scenario: +7 GW by 2030(2.1% CAGR). Low: +5.5 GW (0.9% CAGR).2025 summer peak was 121 GW. Drivers: data centers, re-shore manufacturing, electrification. ​

• Without accelerating additions, 2027/28risks scarcity-level pricing.​

  
  

Resource Mix​

• Winter PRMR is 6.6 GW (4.8%) below summer. Solar's 5% winter accreditation drops its contribution from 12.2 GW(summer) to 0.8 GW (winter). ​

• Gas rises from 38.9% to 41.8% of cleared SAC​

• Coal/Nuclear/Hydro/Oil combined has fallen30% since Summer 2016.​

• Batteries cleared 893.8 MW in summer,870.4 MW in winter. Year-over-year trend:~50 MW (2024/25) → ~500 MW (2025/26) →893.8 MW (2026/27). Summer capacity revenue: $424.30/MW-day × 92 days × 0.95 ≈$37,084/MW-year ($37.08/kW-year). ​

• Updated GVTC hourly-discharge methodology in effect for 2026/27.​

  
  

Price Relief, But Still Elevated​

• Annualized prices fell from ~$217/MW-day(2025/26) to $126.19/MW-day (2026/27 N/C) a~42% decline:​

  • 2022/23: ~$17/MW-day​

  • 2023/24: ~$6/MW-day​

  • 2024/25: ~$8/MW-day​

  • 2025/26: ~$217/MW-day ← spike​

  • 2026/27: $126.19/MW-day ← relief​

• Still ~15x above the 2023-2025 average​

• LSEs and retail customers will see meaningful relief but no return to pre-2025norms​

  
  

CONE Still Far Above Clearing​

• Summer cleared at $424.30 vs. N/C seasonal CONE of $1,453.99/MW-day (29.2%). South CONE: $1,348.59. Annual CONE by zone:$123,250–$142,970/MW-yr​

• New dispatchable thermal cannot be financed on capacity revenue alone​

• Bilateral contracts and ERAS fast-track approvals remain essential​

• ~92% of load was self-supplied or bilaterally contracted before the auction. Only 11,305.4MW of non-self-scheduled capacity cleared in summer out of 142,374.3 MW total committed​

• Direct PRA price exposure is limited but not zero — particularly for retail-choice customers in IL, MI, OH, and other competitive states.

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Advantage BESSt​

• Solar cleared 12.2 GW in summer but only 0.8 GW in winter (5% accreditation vs. 50%). Summer/winter accreditation gap creates a 15:1 capacity value imbalance. Hybrid solar + BESS structures are commercially advantaged. Future DLOL-based accreditation (in development) may shift these values​

• At $424.30/MW-day × 92 summer days × 0.95 (four-hour credit) = $37,084/MW-year ($37.08/kW-year) in summer capacity revenue alone. Combined with energy arbitrage and ancillary services, this increasingly anchors BESS project economics​

• DR cleared 9,099.5 MW in summer (up from 9,004.4MW) and 7,789.6 MW in winter. Cleared Load Modifying Resources (including BTMG) total 9.1 GW in summer, 7.7 GW in winter​

• MISO's tightened DR compliance means that performance tests will be required, not mock drills. This raises the bar but rewards credible programs​

  
  

2026 PRA RDBC Offer Curves​

Things to Watch​

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