MISO's Capacity Crunch

When MISO's Zone 4 capacity prices cleared at $236/MW-day in the 2024/25 Planning Resource Auction—up from $10/MW-day the prior year—utility executives across the Midwest stopped treating resource adequacy as a planning abstraction. That 2,000% increase wasn't a market glitch. It was the sound of years of deferred investment colliding with physical reality.

The spike lands amid a broader capacity market reckoning. PJM's July 2024 auction delivered record-high clearing prices, with the RTO Rest pool hitting $269.92/MW-day—a ninefold increase from the previous year. ISO-NE capacity prices climbed to $119.33/MW-day after holding near $86/MW-day for two years. Across organized markets, the price signal is unambiguous: dispatchable capacity commands a premium that planners failed to anticipate.

The Arithmetic of Inadequacy

MISO's supply stack tells the story. The footprint lost 12,400 MW of coal capacity between 2020 and 2024, with another 8,500 MW holding retirement dates before 2028. These weren't marginal units—they were the baseload fleet that defined Midwest reliability for decades.

Replacement resources paint a different picture. Solar additions totaled 9,200 MW during the same period; wind added 6,800 MW. But nameplate capacity and deliverable capacity diverge sharply under MISO's effective load carrying capability methodology. Solar receives roughly 50% capacity credit; wind roughly 15%. The math doesn't balance.

Battery storage should bridge the gap. MISO's interconnection queue holds 48 GW of storage projects—more than enough on paper. Yet only 1,900 MW reached commercial operation by 2024. The queue that should deliver reliability sits in engineering purgatory, stalled by study backlogs and upgrade cost allocations that can exceed $100/kW for storage projects in congested zones.

Meanwhile, demand accelerated. Data center development in Illinois and Indiana—driven by hyperscaler expansion and AI compute buildout—added an estimated 2,400 MW of firm load between 2022 and 2024. Industrial electrification contributed another 1,100 MW. Summer 2024's persistent heat pushed peak demand 4% above forecast. Planning margins that appeared adequate evaporated under operating conditions.

Coal Exits, Renewables Enter—But Capacity Doesn't Balance

Coal Exits, Renewables Enter—But Capacity Doesn't Balance. Source: MISO data 2020-2024. While 16,000 MW of solar and wind nameplate capacity was added, effective deliverable capacity totals only ~5,600 MW—far short of replacing 12,400 MW of retired coal.

Why Zone 4 Broke First

MISO's capacity market fragments into zones with constrained transfer capability. Zone 4—covering Illinois and Chicago's industrial load center—imported capacity from neighboring zones until transmission constraints bound. At that point, local scarcity drove prices.

The zonal disparity is striking. Louisiana and Texas zones cleared at $47/MW-day, benefiting from different resource mixes and load patterns. But Zone 4's exposure reveals a structural vulnerability: when transmission limits bind, regional markets become local markets, and local markets reflect local scarcity.

The situation echoes PJM's experience in its recent auction, where transmission constraints similarly amplified price divergence across locational deliverability areas. As FERC staff noted in their Summer 2025 assessment, PJM required reliability must-run agreements to retain the Brandon Shores and H.A. Wagner facilities through mid-2029—stopgap measures that signal inadequate market incentives for resource retention.

The Regulatory Response Takes Shape

MISO's proposed seasonal capacity construct, pending in FERC Docket ER25-234, represents the most significant structural reform since the Planning Resource Auction's inception. The current annual structure fails to differentiate between summer and winter reliability needs—a distinction that matters increasingly as load patterns shift and intermittent resources dominate additions.

The filing also proposes availability-based accreditation replacing unforced capacity methodology. Resources would receive credit based on expected performance during highest-risk hours rather than average forced outage rates. It's a methodology convergence: MISO joins PJM, ISO-NE, and SPP in moving toward accreditation frameworks that discount intermittent resources more aggressively during scarcity conditions.

Demand Growth Outpaces Supply

Demand Growth Outpaces Supply. Source: MISO load data 2022-2024. New firm load from data centers and industrial electrification added ~3,500 MW of demand, while Summer 2024 peaks exceeded forecasts by 4%.

MISO's adoption of a downward-sloping Reliability Based Demand Curve, which FERC accepted in 2024, should moderate future price volatility by setting prices that scale with capacity shortfall severity. The mechanism arrived too late to prevent Zone 4's spike but establishes a "warning signal" structure for future auctions.

At the state level, Illinois Commerce Commission proceedings examine whether ComEd should conduct supplemental capacity procurement beyond MISO auction requirements. The proceeding raises fundamental questions about market reliance: when capacity prices spike 2,000%, is market-based procurement a feature or a failure?

The Transmission Bottleneck

MISO's Long Range Transmission Planning identified $10.3 billion in network upgrades needed by 2030. The investment would relieve congestion between zones and enable efficient capacity sharing across the footprint.

Progress remains glacial. Permitting timelines extend five to seven years for major transmission projects. State siting approval adds uncertainty. Cost allocation disputes between beneficiary states delay advancement.

The Grain Belt Express project illustrates the challenge. The 800-mile HVDC line would deliver 5,000 MW of Kansas wind to Illinois and Indiana load. Regulatory processes began in 2014. Commercial operation now targets 2029—fifteen years from inception to energization for a project that would materially improve Zone 4's supply position.

Capacity Prices Spike Across All Major Markets

Capacity Prices Spike Across All Major Markets. Source: 2024/25 capacity auction results. PJM and MISO Zone 4 lead the price surge, while MISO's southern zones cleared at a fraction of the cost—revealing how transmission constraints fragment regional markets.

Each year of transmission delay increases reliance on local generation carrying higher capacity costs. The irony compounds: MISO holds 48 GW of storage in its interconnection queue, but many projects require the same transmission upgrades that face decade-long timelines.

Investment Signals and Strategic Implications

For generation developers, MISO's pricing now supports new-build economics decisively. At $236/MW-day, a 200 MW solar project with 50% capacity credit earns approximately $8.6 million annually from capacity revenue alone—before energy margins. That changes project finance assumptions across the footprint.

For load-serving entities, the procurement imperative is immediate. Self-build options require three to five years from commitment to operation. Bilateral PPA markets have tightened as developers price in capacity value. Utilities that deferred procurement decisions face a seller's market.

For industrial load, particularly data center developers driving Midwest demand growth, the calculus shifts toward demand flexibility. Interruptible service contracts, on-site generation, and geographic diversification offer hedges against capacity-driven rate increases. The economics of behind-the-meter resources improve materially when grid capacity carries a $236/MW-day price tag.

What Determines the Trajectory

MISO's 2025/26 auction in April 2025 will test whether Zone 4's price signal was a one-time adjustment or the new normal. Early indicators suggest continued tightness: additional coal retirements take effect before the planning year begins, while interconnection queue clearance remains constrained.

Three variables will determine whether relief comes before 2028. First, FERC's disposition of MISO's seasonal capacity and accreditation reforms—acceptance would align market signals with physical reliability needs. Second, state regulatory treatment of supplemental procurement authority for utilities facing inadequate market outcomes. Third, interconnection queue velocity—specifically, whether the cluster study reforms FERC required in Order 2023 accelerate storage deployment.

The Midwest is learning what California discovered in 2020 and Texas in 2021: resource adequacy margins that appear adequate under normal conditions vanish during system stress. The difference is that MISO's organized capacity market now reflects that scarcity in price. Whether the signal arrives in time to avoid reliability consequences depends on how quickly capital responds to a $236/MW-day invitation.