Illinois Market Design has moved from an abstract electricity-economics debate to a near-term reliability question. The 2025 Resource Adequacy Study, released on December 15, 2025, found that PJM is projected to face a capacity shortfall beginning in 2029 and MISO beginning in 2031 unless more capacity is added, according to the 2025 Resource Adequacy Study. Those findings do not mean outages are inevitable. They do mean Illinois policymakers are evaluating a narrower margin for error as demand grows, thermal plants retire, and new resources face slow interconnection timelines.
The Stanford economists referenced in the research frame these issues as market-design problems rather than purely technology problems. Their point is narrower than saying clean energy cannot scale: price signals, queue rules, capacity accreditation, and reliability compensation can determine whether available technologies are built in the right places and at the right times. That distinction matters for Illinois because the state operates across two regional markets, PJM in northern Illinois and MISO in much of downstate Illinois. For those interested in industrial energy topics within this network, Kilburn Chemicals offers insight into related sectors outside the electricity-policy frame.
Why Illinois Market Design Is Under Pressure
Illinois Market Design And Resource Adequacy
The central resource-adequacy problem is not simply a lack of projects in development. The 2025 study reported nearly 87 GW of new nameplate capacity under development in PJM and more than 72 GW in MISO through 2030. After accreditation adjustments, which account for how much capacity is expected to be available for reliability purposes, those figures fall to 27 GW in PJM and 28 GW in MISO. That gap between nameplate capacity and accredited capacity is one of the main reasons Illinois Market Design is now a policy focus rather than a narrow market-operator concern.
The same study identified rapid, geographically concentrated load growth from data centers as a primary driver of increased demand in both PJM and MISO. The research notes state that this expected demand growth is well above observed historic trends over the past 20 years. Concentrated load growth is harder to manage than broad, gradual growth because local transmission capability, substation capacity, and deliverability constraints can matter as much as the total amount of generation on the system.
What The Regional Split Means
Illinois does not plan resource adequacy in a single, isolated power market. Northern Illinois is tied to PJM, while much of the rest of the state is tied to MISO. That split creates different timelines and different market signals. PJM’s projected shortfall date of 2029 arrives earlier than MISO’s projected 2031 date in the study. The distinction is significant because market rules, capacity auctions, and interconnection processes differ across the two systems. A policy tool that fits one region may not produce the same reliability outcome in the other.
The timing also intersects with retirements of existing thermal resources. The research notes cite about 15 GW of PJM coal and gas retirements and 18 GW in MISO over the projection periods. These numbers should be read as part of a planning analysis, not a direct forecast of a specific operating emergency. Still, they clarify the scale of replacement capacity needed if Illinois and neighboring states are to preserve reliability while retiring older resources.
Capacity Accreditation And The Entry Problem
Nameplate Capacity Is Not The Same As Firm Supply
Capacity accreditation is where market design becomes visible to consumers, developers, and regulators. A wind, solar, storage, gas, or hybrid project may all add nameplate megawatts, but the capacity market counts resources based on expected contribution to reliability during system stress. The sharp reduction from nameplate additions to accredited additions in both PJM and MISO shows why project announcements alone do not settle the adequacy question.
From a market-design standpoint, the challenge is to reward the attributes the system needs without overpaying for capacity that is not available during peak risk periods. The Stanford analysis cited in the research notes emphasized misaligned price incentives, rigid interconnection procedures, and mismatches between supply availability and demand patterns. Applied to Illinois, that means the policy question is not only how many megawatts are proposed, but whether market rules bring forward resources that can meet accredited reliability needs.
Interconnection Delays As A Barrier To Entry
The research notes identify interconnection queue delays as a major barrier, with median delay times of 41.8 months for PJM requests and 38.2 months for MISO requests. These delays matter because capacity markets rely on new entry to discipline prices and replace retiring units. If qualified projects wait years for study, network-upgrade assignments, and approval, the market may show a shortage signal without allowing supply to respond quickly.
This is one reason a shortened forward period in a capacity auction can create stress. The research notes describe non-price barriers, including queue delays and a sharply shortened forward period, as weakening new generation entry and market-power mitigation in PJM’s 2025/2026 Base Residual Auction. That finding fits the Stanford-style diagnosis: the issue is not only whether a technology exists, but whether rules permit timely entry when prices signal scarcity.
Price Signals, Storage, And Reliability Value
Auction Results Show Tight Conditions
Recent auction data show why policymakers are paying close attention. PJM’s 2026/2027 Base Residual Auction cleared at an 18.9% reserve margin, slightly below the 19.1% target. The cleared resources exceeded demand by only 0.1%, or about 138.8 MW, above a requirement of 146,105 MW. MISO’s 2025/2026 Planning Resource Auction cleared 137,559.3 MW for summer, exceeding the 135,213.4 MW target by 2,345.9 MW, or about 1.7%, according to the legislative copy of the RA Study.
Prices reflected that tightness. The research notes state that PJM-wide capacity prices reached the FERC-approved cap of $329.17 per MW-day in all PJM zones during the most recent auctions. In MISO, average annual capacity prices were around $212 to $217 per MW-day in various zones. High prices can encourage entry, but only if projects can actually move through permitting, supply chains, financing, and interconnection in time to serve the need.
Storage Value Is Hard To Price
The Stanford economist Ömer Karaduman, as summarized in the research notes, highlighted a specific storage problem in September 2026: batteries can reduce the price volatility that makes them profitable. That creates a difficult market-design question. If storage earns revenue mainly when prices swing sharply, then successful storage deployment can reduce its own future revenue opportunity. The result may be underinvestment unless markets compensate standby capacity, flexibility, or reliability contribution more directly.
This is not a claim that storage alone can solve Illinois reliability concerns. The available research supports a more limited point: pricing structures can affect whether storage is financed and operated in ways that support resource adequacy. Cost, location, duration, deliverability, and accreditation rules all matter. The same caution applies to gas turbines, transformers, copper, and steel, where the research notes state that costs have risen sharply since about 2018 and lead times for critical components can now often run five to seven years.
What Illinois Market Design Can Support
Policy Tools Under The 2026 Planning Process
Recent Illinois legislation, Senate Bill 25, directed the Illinois Commerce Commission, in consultation with the Illinois Power Agency and other agencies, to develop an Integrated Resource Plan. The research notes state that the plan must address resource-adequacy challenges in the five years immediately following approval while also taking into account the following 10 years. The 2025 Resource Adequacy Study was intended to feed into that IRP process during 2026.
That planning structure gives Illinois a way to compare market reforms, transmission needs, and procurement choices across different time horizons. The five-year window is relevant because PJM’s projected shortfall begins in 2029. The 10-year window is relevant because MISO’s projected shortfall begins in 2031 and because major equipment lead times can stretch across much of a decade. A credible plan will need to account for both timelines without treating either as certain.
Evidence-Based Limits For Illinois Market Design
Illinois Market Design can support reliability by improving entry conditions, aligning compensation with accredited reliability value, and reducing avoidable delays. The evidence in the 2025 study supports concern about capacity shortfalls, queue delays, price pressure, and demand growth. It does not support a single definitive remedy. Any reform will have tradeoffs for ratepayers, developers, incumbent generators, and local communities affected by infrastructure siting.
The most defensible reading is cautious. Illinois has proposed capacity in the development pipeline, but accredited capacity is much lower than nameplate capacity. Regional auctions have cleared with narrow margins and elevated prices. Data center load growth is creating demand pressure beyond historic trends. Thermal retirements are reducing dispatchable supply. Stanford economists’ market-design framing helps explain why those facts are connected: reliability outcomes depend not just on technology availability, but on whether market rules, interconnection procedures, and price signals support timely investment where the grid needs it.