Illinois energy policy increasingly connects electric-grid reliability, utility affordability, clean-energy development, transmission investment, natural-gas infrastructure, and growing demand from data centers and other large users. Explore Illinois Capitol Group’s analysis and official resources concerning the laws, regulatory proceedings, regional markets, and implementation decisions shaping the state’s energy future; select an article below to expand it.
Illinois is implementing major changes to its energy-planning and procurement framework while confronting increasing electricity demand, regional capacity constraints, aging infrastructure, consumer-cost concerns, and the transition to cleaner energy resources.
Grid reliability and resource adequacy. Illinois participates in two regional electricity markets—PJM in northern Illinois and MISO across most of central and southern Illinois. The state’s reliability outlook therefore depends on conditions throughout both regions, including electricity-demand growth, power-plant retirements, new-resource development, transmission availability, and the performance of capacity markets. The state’s December 2025 Resource Adequacy Study found increasing reliability pressures and initiated further mitigation planning by the Illinois Power Agency, Illinois Commerce Commission, and Illinois Environmental Protection Agency.
Clean and Reliable Grid Affordability Act implementation. Public Act 104-0458, the Clean and Reliable Grid Affordability Act, took effect June 1, 2026. The law expands state energy planning and supports energy storage, virtual power plants, demand flexibility, grid-enhancing technologies, geothermal systems, thermal energy networks, utility-data transparency, and other measures intended to improve reliability and affordability. Many of its practical effects will depend on agency implementation, procurement results, regulatory proceedings, and project development.
Energy storage and flexible demand. Illinois completed its first procurement under the new energy-storage framework in 2026. Although the procurement sought 1,038 megawatts of standalone storage, approved contracts supported 600 megawatts of new projects, with additional procurement activity anticipated. Storage, demand response, time-varying rates, distributed generation, and virtual power plants may help reduce peak demand and use existing grid infrastructure more efficiently.
Renewable energy and generation policy. Illinois continues implementing the Climate and Equitable Jobs Act through renewable-resource procurement, solar programs, workforce and equity initiatives, and statutory emission-reduction requirements. Current policy discussions increasingly focus not only on clean-energy targets, but also on whether generation, storage, transmission, and interconnection infrastructure can be developed quickly enough to maintain reliability and control costs.
Transmission and regional coordination. New generation and storage resources cannot address reliability needs without adequate transmission and timely interconnection. Illinois policy therefore intersects with planning and cost-allocation decisions made by the Federal Energy Regulatory Commission, MISO, PJM, the Illinois Commerce Commission, utilities, and transmission developers. Competitive development, rights of first refusal, project siting, regional cost allocation, and grid-enhancing technologies remain important policy questions.
Large-load and data-center growth. Data centers, advanced manufacturing, electrification, and other large new loads are changing electricity-demand forecasts. Policymakers and regulators must consider how quickly those customers can connect, what infrastructure is required, who should bear associated costs, and how economic-development goals can be reconciled with reliability and protections for existing customers.
Utility rates and consumer affordability. Customer bills reflect several different components, including energy supply, capacity, transmission, and utility delivery charges. Changes in wholesale markets, infrastructure investment, rate design, and state energy programs may affect those components differently. Illinois policymakers continue to consider affordability alongside reliability, clean-energy development, utility investment, and consumer protection.
Natural-gas infrastructure and long-term planning. Natural-gas policy presents related questions concerning pipeline safety, utility capital spending, delivery rates, customer affordability, electrification, non-pipeline alternatives, and the risk that long-lived infrastructure costs could be recovered from a changing customer base. The Illinois Commerce Commission’s ongoing Future of Gas process is examining potential regulatory and legislative approaches to these issues.
This snapshot summarizes major policy developments as of September 2026. Agency proceedings, procurement results, regional-market conditions, and implementation schedules continue to evolve.
Sources & Further Reading:
Illinois energy policy is implemented through multiple agencies, regulatory proceedings, procurement processes, regional grid organizations, and public programs. The resources below provide current information about electricity procurement, grid reliability, renewable energy, utility regulation, natural gas, consumer assistance, and related policy developments.
State Energy Laws, Planning & Implementation
Illinois Power Agency—Clean and Reliable Grid Affordability Act Implementation: Implementation updates, timelines, stakeholder opportunities, and program materials concerning Public Act 104-0458.
Illinois Power Agency—Resource Adequacy Planning Hub: The 2025 Illinois Resource Adequacy Study and materials addressing projected electricity needs in the PJM and MISO regions.
Illinois Power Agency—Resource Adequacy Mitigation Plan: Current work by the IPA, Illinois Commerce Commission, and Illinois Environmental Protection Agency to evaluate and respond to potential reliability shortfalls.
Illinois Power Agency—Climate and Equitable Jobs Act Implementation: Background and implementation materials concerning CEJA’s renewable-energy, equity, workforce, and procurement provisions.
Illinois Environmental Protection Agency—Climate and Equitable Jobs Act: Information concerning power-sector emissions, electric-vehicle programs, charging infrastructure, and Illinois EPA responsibilities under CEJA.
Illinois General Assembly—Legislation and Laws: Bill status, public acts, committee activity, legislative calendars, and statutory text.
Electricity Procurement, Renewable Energy & Storage
Illinois Power Agency—Electricity Procurement: Annual electricity-procurement planning for eligible utility customers and information about Illinois’ competitive procurement process.
Illinois Power Agency—Long-Term Renewable Resources Procurement Plan: The state’s principal implementation plan for renewable-energy-credit procurements, distributed solar, community solar, equity requirements, and related programs.
Illinois Power Agency—Energy Storage: Procurement information, implementation materials, and results concerning utility-scale storage under the Clean and Reliable Grid Affordability Act.
Illinois Power Agency—Utility-Scale Renewable Energy Projects: Information concerning competitive procurements supporting new utility-scale wind, solar, hydropower, and brownfield-site projects.
Illinois Shines: Program requirements, project-capacity information, consumer resources, and application materials for distributed-generation and community-solar projects.
Illinois Solar for All: Solar opportunities for income-eligible households, nonprofit organizations, public facilities, and environmental-justice communities.
Illinois Clean Energy Dashboard: State data concerning renewable-energy development and implementation progress.
Utility Regulation, Rates & Consumer Information
Illinois Commerce Commission: Regulatory information concerning electric, natural-gas, water, telecommunications, transportation, and other public-utility matters.
Illinois Commerce Commission e-Docket: Searchable filings, testimony, orders, and procedural information for utility rate cases and other Commission proceedings.
Illinois Power Agency—Customer Electric Choice: Explanation of electricity supply and delivery charges, utility supply service, municipal aggregation, and alternative retail electric suppliers.
Citizens Utility Board: Consumer-oriented explanations of utility bills, rate cases, energy programs, and available assistance. CUB is an independent nonprofit consumer organization rather than a state agency.
Natural Gas Policy & Infrastructure
Illinois Commerce Commission—Future of Gas Workshop Resources: Materials addressing long-term gas-system planning, affordability, decarbonization, infrastructure investment, workforce issues, and potential regulatory or legislative changes.
Illinois Commerce Commission e-Docket: Official source for natural-gas rate cases, utility infrastructure proposals, testimony, and final Commission orders.
Illinois Environmental Protection Agency—Climate and Equitable Jobs Act: State information concerning energy-sector emissions and the statutory transition framework.
Regional Grid Planning & Electricity Markets
Midcontinent Independent System Operator: Regional market, reliability, operational, and planning information affecting most of central and southern Illinois.
MISO Transmission Expansion Planning: Project, planning, cost-allocation, interconnection, and long-range transmission materials.
PJM Interconnection: Wholesale-market, reliability, capacity, and transmission information affecting northern Illinois and the ComEd service territory.
PJM Planning: Transmission planning, generation interconnection, load forecasting, and regional project information.
Federal Energy Regulatory Commission—Electric Power: Federal regulation of interstate transmission, wholesale electricity markets, regional grid operators, and related rate and planning matters.
North American Electric Reliability Corporation: Reliability standards, seasonal assessments, long-term reliability analysis, and information about risks affecting the interconnected North American grid.
Clean-Energy Workforce & Economic Development
Illinois Department of Commerce and Economic Opportunity—Climate and Equitable Jobs Act: Clean-energy workforce hubs, contractor-development programs, economic assistance, and other CEJA workforce initiatives.
Illinois Energy Workforce Equity Portal: Resources connecting clean-energy businesses, contractors, training providers, and Equity Eligible Persons.
Illinois Power Agency—Diversity, Equity & Inclusion: Equity requirements and resources associated with state-supported renewable-energy projects and procurements.
Related Illinois Capitol Group Policy Resources
Illinois Advanced Technology & Innovation Policy: Data centers, computing infrastructure, quantum technology, life sciences, research commercialization, workforce, and innovation incentives.
Illinois Infrastructure Policy & Investment: State capital programs, transportation infrastructure, project selection, funding, and local implementation.
Illinois Nuclear Energy Policy: Nuclear-generation policy, state incentives, plant operations, and related legislative developments.
Illinois Carbon Capture Policy: Carbon capture, transport, storage, project development, regulation, and community considerations.
Agency programs, procurement schedules, market rules, and regulatory proceedings change over time. Readers should confirm current requirements through the responsible agency or official docket before relying on a resource for a particular project, filing, or compliance decision.
Illinois must ensure that sufficient electricity is available not only during ordinary conditions, but also during periods of unusually high demand, extreme weather, generator outages, transmission constraints, or other system stress. This requires coordination among state agencies, utilities, power generators, regional grid operators, federal regulators, large energy users, and customers capable of reducing or shifting demand.
Energy, Capacity & Resource Adequacy
Energy and capacity are related but different concepts:
Energy is the electricity generated and consumed over time.
Capacity represents a resource’s commitment and accredited ability to be available when the system needs it.
Resource adequacy asks whether the power system is expected to have enough dependable capacity to meet forecast demand plus an appropriate reliability reserve.
Operational reliability concerns the grid operator’s ability to balance supply and demand in real time and respond to outages, weather, transmission limitations, and other immediate conditions.
A region can produce enough electricity during most hours while still facing a resource-adequacy concern if too few dependable resources are expected to be available during peak or emergency conditions. Similarly, adding a large amount of nameplate generation does not produce an equal amount of accredited capacity because technologies differ in when and how reliably they can operate.
Why Illinois Is Divided Between PJM and MISO
Illinois participates in two regional transmission organizations:
PJM Interconnection operates the regional transmission system and wholesale electricity markets that include northern Illinois and the ComEd service territory.
Midcontinent Independent System Operator, or MISO, performs corresponding functions across most of central and southern Illinois, including the Ameren Illinois service territory.
PJM and MISO coordinate transmission operations, administer wholesale energy and capacity markets, plan regional transmission, manage generator-interconnection processes, and establish resource-adequacy requirements. They do not own most power plants or local utility distribution systems.
Illinois therefore cannot evaluate reliability solely by counting power plants located within the state. The availability of generation and imports throughout PJM and MISO, regional transmission constraints, capacity-market rules, and conditions in neighboring states can affect both reliability and electricity costs for Illinois customers.
The 2025 Illinois Resource Adequacy Study
The Illinois Power Agency, Illinois Commerce Commission, and Illinois Environmental Protection Agency released a joint Resource Adequacy Study in December 2025. The study evaluated the ComEd zone in PJM, Illinois’ principal MISO zone—Local Resource Zone 4—and broader conditions throughout both regional systems.
The study did not conclude that an electricity shortage is inevitable. Its projections depend on assumptions about future demand, generator retirements, new-resource development, transmission availability, imports, market rules, and technology performance. It did, however, identify credible circumstances under which Illinois and the surrounding regional systems could experience tightening capacity conditions by 2030.
Principal findings included:
Both PJM and MISO are expected to need substantial new capacity by 2030.
Electricity demand is increasing because of data centers, transportation electrification, industrial expansion, and other new loads.
Coal, natural-gas, and oil generators are expected to retire because of age, economics, environmental requirements, or announced business decisions.
New generation may take years to plan, permit, finance, interconnect, and construct.
Wind, solar, and storage projects face interconnection backlogs, transmission limitations, supply-chain issues, and other development barriers.
Illinois’ ability to rely on imported capacity becomes less certain when PJM or MISO is also experiencing tight regional conditions.
The timing of replacement resources is as important as the announced timing of generator retirements.
Under several modeled scenarios, neither the ComEd zone nor MISO Local Resource Zone 4 would have sufficient in-state and already-planned resources to meet projected 2030 requirements without additional development or increased imports. That finding does not mean those zones currently lack sufficient electricity. It identifies a forward-looking planning risk if demand grows and existing resources retire faster than replacement capacity becomes available.
Generator Retirements & Illinois Emissions Requirements
The Climate and Equitable Jobs Act established emissions-reduction requirements affecting fossil-fueled electric generating units. These requirements operate alongside market-driven retirements caused by plant age, operating costs, maintenance needs, fuel economics, and wholesale-market conditions.
Delaying the retirement of an individual Illinois generator may provide temporary capacity, but it does not by itself resolve a regional resource-adequacy problem. Reliability planning must also consider whether a plant is operationally dependable, where it is located, whether transmission can deliver its output, how often it is expected to operate, and whether more durable alternatives can be developed.
Illinois law permits a mitigation process to consider limited adjustments to emissions-reduction schedules when necessary to address an identified reliability need. That process must also evaluate renewable energy, storage, demand response, transmission development, and other potential solutions. Any adjustment should therefore be understood as one possible component of a broader reliability plan, not an automatic response to every projected capacity concern.
A Portfolio of Potential Reliability Resources
No single resource is likely to address all of Illinois’ reliability, affordability, and emissions objectives. Potential components of a diversified strategy include:
Utility-scale and distributed solar
Onshore wind and other renewable generation
Short-duration and long-duration energy storage
Nuclear generation and other clean firm resources
Demand response and voluntary load reductions
Energy efficiency
Virtual power plants and coordinated distributed resources
Time-varying rates and incentives to shift consumption away from system peaks
Transmission expansion and grid-enhancing technologies
Faster and more predictable interconnection processes
Strategic use of existing thermal generation during the transition
Flexible operation by data centers and other large customers
Long-term contracts or other procurement mechanisms supporting new dependable capacity
These resources provide different services. Solar may contribute strongly during summer daytime hours, while storage can shift electricity into periods of greater need. Demand response can reduce peak usage, transmission can provide access to resources elsewhere, and firm generation may remain available during extended periods when weather-dependent output is limited. Planning must evaluate how the resources perform together rather than treating each installed megawatt as interchangeable.
Resource Adequacy Mitigation Plan
Following the study, the Illinois Power Agency and Illinois Environmental Protection Agency began developing a Resource Adequacy Mitigation Plan, in coordination with the Illinois Commerce Commission. The process is intended to evaluate supply, storage, demand-side, transmission, and other strategies that could reduce identified reliability risks.
The mitigation process includes stakeholder workshops, publication of a draft plan, an opportunity for public comment, and eventual review through an ICC proceeding. Because forecasts and project schedules can change, the plan will need to distinguish immediate actions from longer-term options and periodically reassess whether projected shortfalls remain likely.
Statewide Integrated Resource Planning
The Clean and Reliable Grid Affordability Act established a broader statewide integrated resource-planning process led by the Illinois Commerce Commission in coordination with the Illinois Power Agency, Illinois Environmental Protection Agency, Illinois Finance Authority, and other participants.
The initial Integrated Resource Plan is due to the Commission by November 15, 2026. It is expected to address resource-adequacy needs during the first five years after approval while considering conditions over a ten-year horizon.
Integrated resource planning can compare different combinations of:
New generation
Energy storage
Energy efficiency
Demand flexibility
Transmission investment
Distributed energy resources
Long-term capacity or clean-energy procurements
Changes or expansions to existing state programs
Limited adjustments to emissions-reduction schedules when justified by reliability needs
The mitigation plan and integrated resource plan address overlapping questions and are being developed in coordination. The integrated process is broader, however, because it can evaluate competing resource portfolios, costs, risks, implementation timelines, and effects on Illinois customers within a common planning framework.
Affordability & Cost Allocation
Reliability investments are not cost-free. New generation, storage, transmission, distribution upgrades, demand-response programs, and long-term contracts may all create customer costs or financial risks.
Important questions include:
Whether new investments reduce wholesale energy or capacity prices
Whether Illinois customers receive the financial benefits of resources they fund
How contract prices compare with future market prices
Whether large new loads pay an appropriate share of required infrastructure
How costs and benefits are allocated among customer classes and regions
Whether demand-side alternatives can avoid or defer more expensive construction
How low-income customers and other vulnerable consumers are affected
Whether procurement commitments remain useful under changing demand, technology, and federal policy
Building resources within Illinois can improve local supply and produce economic benefits, but it may not fully insulate customers from high regional capacity prices when PJM or MISO as a whole remains constrained. State procurement decisions must therefore account for regional market design as well as in-state development.
Implementation Questions to Monitor
The significance of Illinois’ new planning framework will depend on how agencies resolve several issues:
The demand forecasts used for data centers and other large loads
Assumptions concerning generator retirement dates and operating performance
The amount and type of capacity credited to renewable energy and storage
Progress in PJM and MISO interconnection queues
Transmission projects required to deliver new resources
Whether large customers can reduce or shift demand during critical hours
The timing and structure of long-term procurement decisions
Coordination between the mitigation plan and Integrated Resource Plan
The treatment of affordability, emissions, environmental justice, and workforce effects
How frequently forecasts and approved actions will be updated
Whether authorized investments are completed quickly enough to meet projected needs
The central challenge is not choosing between reliability and the clean-energy transition. It is coordinating demand forecasts, retirements, generation, storage, transmission, and flexible consumption early enough to maintain reliability while controlling costs and advancing Illinois’ statutory energy objectives.
Featured Illinois Capitol Group Analysis
Midwest Energy Capacity Crunch
Published in September 2026, this podcast reviews the principal findings of Illinois’ 2025 Resource Adequacy Study and explains the distinction between energy and capacity, the roles of PJM and MISO, increasing demand from data centers and other large users, regional capacity constraints, generator retirements, and the range of potential policy responses.
Listen to the Illinois Capitol Group podcast review
Podcast analysis reflects the information and policy status existing on its publication date.
Sources & Further Reading:
Illinois’ electricity policy combines renewable-energy targets, fossil-generation emissions requirements, support for existing carbon-free generation, competitive procurement, consumer programs, workforce initiatives, and regional reliability obligations. The principal challenge is translating statutory goals and awarded contracts into operating projects that can deliver energy and dependable capacity when and where the grid needs them.
Climate and Equitable Jobs Act Framework
The Climate and Equitable Jobs Act, or CEJA, became law in 2021 as Public Act 102-0662. It expanded Illinois’ Renewable Portfolio Standard, established emissions-reduction requirements for fossil-fueled generating units, supported continued operation of qualifying nuclear facilities, and created clean-energy workforce, contractor-development, transportation-electrification, and community-transition programs.
Illinois’ Renewable Portfolio Standard calls for participating electric utilities to obtain renewable energy credits corresponding to 40 percent of eligible retail electricity sales by 2030 and 50 percent by 2040. These requirements support the state’s broader goal of reaching 100 percent clean energy by 2050.
Those percentages should not be confused with a real-time description of the electricity flowing to every Illinois customer. Renewable-energy compliance is generally measured through the acquisition and retirement of renewable energy credits, while the physical electricity system operates through interconnected regional markets.
Renewable Energy Credits & State Procurement
A renewable energy credit, or REC, represents the environmental attributes associated with one megawatt-hour of electricity generated by an eligible renewable resource. The Illinois Power Agency uses REC contracts and related programs to support development of renewable projects and compliance with the state’s Renewable Portfolio Standard.
The IPA’s Long-Term Renewable Resources Procurement Plan governs the design and administration of those programs. The current approved document is the 2026 Long-Term Renewable Resources Procurement Plan, as modified effective June 1, 2026 to reflect changes under the Clean and Reliable Grid Affordability Act.
The plan addresses matters including:
Utility-scale wind and solar procurements
Distributed solar and community solar
Illinois Shines
Illinois Solar for All
Renewable-energy-credit pricing and contracting
Project eligibility and development milestones
Consumer protections
Equity and workforce requirements
Renewable Portfolio Standard budgets
Project-development risks and contract administration
Many utility-scale projects receive indexed REC contracts. Under this structure, REC payments may adjust in relation to wholesale electricity prices. The mechanism is intended to provide projects with greater revenue stability while allowing contract settlements to move upward or downward as market conditions change.
A REC award or executed contract is an important development milestone, but it does not mean a facility has been constructed or is producing electricity. Projects must still obtain financing, site control, local approvals, interconnection agreements, equipment, transmission access, and permission to operate.
Utility-Scale Wind & Solar
Competitive procurements support new utility-scale wind, solar, brownfield-site photovoltaic, hydropower, and other eligible projects. These resources can provide substantial quantities of lower-emission electricity, but development schedules are affected by:
Generator-interconnection studies and network-upgrade requirements
Transmission congestion and available delivery capacity
Local zoning, permitting, and land-use procedures
Financing and construction costs
Equipment availability and supply chains
Federal tax and trade policy
Contract milestones and collateral requirements
Community acceptance and landowner participation
Environmental, agricultural, and wildlife considerations
A project selected through an IPA procurement may therefore take several years to become operational, and some selected projects may not ultimately be completed. Evaluating Illinois’ progress requires examining both contracted capacity and the smaller subset of projects that have reached commercial operation.
Distributed Solar & Community Solar
Illinois Shines—also known as the Adjustable Block Program—supports distributed solar, community solar, and other qualifying photovoltaic projects through long-term REC contracts.
Distributed generation typically serves a customer at or near the site where electricity is used. Community-solar projects allow subscribers to receive bill credits associated with electricity generated at a separate project. These models can expand participation beyond property owners able to install rooftop systems, but customer benefits depend on subscription terms, utility billing, project performance, and applicable program rules.
Current implementation questions include:
Availability of capacity within different program categories
Interconnection timelines and upgrade costs
Consumer marketing and disclosure requirements
Subscription savings and cancellation terms
Treatment of projects that have received program capacity but are delayed
Coordination among developers, utilities, municipalities, and subscribers
The relationship between distributed resources and local grid needs
Illinois Shines provides program documents, consumer-protection information, approved-vendor resources, project-status data, and current capacity information.
Illinois Solar for All
Illinois Solar for All supports solar development benefiting income-eligible households, qualifying nonprofit organizations and public facilities, and communities that have experienced disproportionate environmental or economic burdens.
The program uses REC incentives and consumer protections intended to produce measurable savings while limiting upfront costs for eligible participants. Its subprograms include residential solar, community solar, nonprofit and public-facility projects, and projects serving environmental-justice communities.
Implementation should be evaluated not only by the number or capacity of supported projects, but also by:
Actual household or organizational savings
Geographic distribution
Participation by renters and customers unable to install rooftop systems
Consumer-protection compliance
Project completion and performance
Community involvement
Benefits delivered over the full contract period
Nuclear Generation
Nuclear facilities provide a substantial portion of Illinois’ carbon-free electricity and dependable generating capacity. State policy has supported certain existing plants through zero-emission and carbon-mitigation credit mechanisms, while plant safety and operating licenses remain primarily under federal Nuclear Regulatory Commission jurisdiction.
Illinois previously maintained a general moratorium on construction of new nuclear power reactors. Legislation enacted in 2023 created an exception allowing development of qualifying small modular reactors beginning in 2026. The Clean and Reliable Grid Affordability Act subsequently removed the broader state construction moratorium, allowing consideration of larger new nuclear facilities as well.
Removing the state prohibition does not approve or finance a particular reactor. Any proposal would still require federal licensing, site review, financing, transmission arrangements, construction planning, waste-management compliance, and resolution of cost and schedule risks.
Current nuclear-policy questions include:
Continued operation and possible license extension of existing plants
Costs and benefits of state-supported credit programs
Development prospects for small modular and advanced reactors
Whether new nuclear generation could serve data centers or other large loads
Allocation of construction and financial risk
Transmission and site requirements
Federal licensing timelines
Decommissioning and spent-fuel responsibilities
Additional background is available on Illinois Capitol Group’s Illinois Nuclear Energy Policy page.
Fossil-Fueled Generation & Emissions Requirements
CEJA requires covered electric generating units and large greenhouse-gas-emitting units to reduce carbon dioxide and specified co-pollutant emissions according to statutory schedules. The applicable requirements vary based on facility type, emissions, ownership, and location.
The transition is affected by more than statutory deadlines. Generators may also retire because of age, operating economics, maintenance needs, fuel costs, market revenues, corporate decisions, or federal environmental requirements. Conversely, reliability concerns may arise when dependable resources are scheduled to retire before replacement generation, storage, transmission, or demand-side resources can be completed.
Illinois’ resource-adequacy and integrated-planning processes are intended to evaluate these timing issues. State law permits consideration of narrowly tailored adjustments when necessary to address a demonstrated reliability need, but also requires examination of renewable energy, storage, demand response, transmission, and other alternatives.
Clean and Reliable Grid Affordability Act
Public Act 104-0458, the Clean and Reliable Grid Affordability Act, took effect June 1, 2026 and added new tools to Illinois’ energy-transition framework. Relevant generation-policy provisions include:
Expanded long-term energy planning
New energy-storage procurements
Changes affecting renewable-energy procurement and contract administration
Support for virtual power plants and flexible customer demand
New geothermal renewable-energy-credit programs
Additional measures intended to accelerate project development
Removal of the remaining statewide moratorium on new nuclear construction
Greater coordination of reliability, affordability, and clean-energy planning
The Act’s practical effects will depend on implementation by the IPA, ICC, Illinois EPA, utilities, regional grid operators, project developers, and local governments.
Workforce, Equity & Community Transition
CEJA connects energy investment with workforce and economic-development objectives. Programs administered principally through the Illinois Department of Commerce and Economic Opportunity support clean-energy training, contractor development, workforce hubs, returning residents, and communities affected by plant or mine closures.
IPA-supported projects are also subject to equity and labor-related requirements, including the Minimum Equity Standard applicable to participating project workforces.
Relevant implementation measures include:
Whether training leads to sustained employment
Participation by Equity Eligible Persons and eligible contractors
Availability of apprenticeship and career pathways
Geographic distribution of jobs and investment
Opportunities for small and diverse businesses
Support for communities affected by energy-facility closures
Compliance with prevailing-wage and project-labor requirements
Coordination between project schedules and workforce preparation
Contracts, Projects & Operating Capacity
Illinois’ progress should be evaluated through several distinct measures:
Statutory targets establish the state’s intended policy direction.
Procurement authorizations allow agencies to seek qualifying resources.
Selected bids and REC awards identify projects approved for contracts.
Executed contracts create enforceable rights and obligations.
Interconnection milestones determine whether projects can connect to the grid.
Construction progress shows whether a selected project is being physically developed.
Commercial operation confirms that the facility is generating electricity.
Accredited capacity measures the resource’s recognized contribution to regional reliability.
Reporting only the capacity of announced, selected, or contracted projects can overstate near-term progress if projects remain delayed or fail to reach operation. Reporting only operating projects can understate the development pipeline. A complete assessment should disclose both figures and explain the stage reached by each project category.
Implementation Questions to Monitor
Important issues include:
Progress toward the 2030 and 2040 Renewable Portfolio Standard requirements
The difference between contracted and operational renewable capacity
Project delays, defaults, substitutions, or contract renegotiations
Available Renewable Portfolio Standard funding
Effects of changing federal tax, tariff, and domestic-content policies
Interconnection-queue processing and transmission availability
Local implementation of siting standards
Consumer savings and protections in distributed and community solar
Performance of workforce and equity programs
Continued operation or retirement of existing nuclear plants
Development prospects and cost allocation for new nuclear generation
Coordination among renewable procurement, storage procurement, resource-adequacy planning, and the statewide Integrated Resource Plan
Illinois’ clean-energy transition ultimately depends less on the number of goals or announced projects than on whether policies produce completed, dependable, affordable resources while protecting consumers and supporting affected workers and communities.
Sources & Further Reading:
Illinois Power Agency—2026 Long-Term Renewable Resources Procurement Plan
Illinois Power Agency—Climate and Equitable Jobs Act Implementation
Illinois Power Agency—Clean and Reliable Grid Affordability Act Implementation
Illinois Power Agency—Renewable Portfolio Standard Budget Forecasts
Illinois Environmental Protection Agency—Climate and Equitable Jobs Act
Illinois EPA—Electric Generating Units and Large Greenhouse-Gas-Emitting Units
Illinois Department of Commerce and Economic Opportunity—CEJA Workforce Programs
Energy storage and flexible customer demand can help Illinois use existing generation and grid infrastructure more efficiently. These resources do not eliminate the need for dependable generation or transmission, but they can move electricity from lower-demand periods to higher-demand periods, reduce system peaks, provide operational services, and improve resilience.
The Clean and Reliable Grid Affordability Act, enacted as Public Act 104-0458, moved Illinois from studying large-scale storage toward procuring projects and developing statewide programs for utility-scale batteries, solar-plus-storage, virtual power plants, and other distributed resources.
What Energy Storage Does
An energy-storage resource absorbs electricity or another form of energy and makes it available later. Storage technologies differ in how quickly they respond, how long they can operate, where they can be installed, and which grid services they provide.
Potential technologies include:
Lithium-ion and other electrochemical batteries
Flow batteries
Pumped-hydroelectric storage
Compressed-air storage
Thermal-energy storage
Hydrogen and other chemical storage
Emerging long-duration technologies
Battery systems can respond quickly to changing grid conditions and may provide energy shifting, peak reduction, frequency regulation, operating reserves, and other services. Some systems can also provide backup power, although a grid-connected battery does not automatically supply a building during an outage unless the system is designed and configured for that purpose.
Storage is generally classified by both power and duration:
Megawatts, or MW, measure how much power the system can deliver at one time.
Megawatt-hours, or MWh, measure how much energy it can store and deliver over time.
A 100 MW battery capable of operating for four hours has substantially different capabilities from a 100 MW battery designed for one hour. Procurement and planning decisions should therefore consider duration and performance rather than relying only on nameplate megawatts.
Illinois’ Utility-Scale Storage Target
CRGA directs the Illinois Power Agency to facilitate development of 3,000 MW of cumulative utility-scale storage capacity committed to commercial operation by December 31, 2030.
The IPA conducted the first procurement on August 26, 2026, seeking 1,038 MW of standalone storage. On September 1, the Illinois Commerce Commission approved contracts supporting 600 MW of new projects located in Illinois.
This distinction is important: the procurement resulted in 600 MW of contracted projects, not 600 MW of immediately operating storage. Selected projects must still satisfy contract milestones, obtain necessary permits and interconnection approvals, finance and construct their facilities, and reach commercial operation.
Additional procurements are expected in 2027 and, if necessary, 2028. Future solicitations may use different allocations between the MISO and PJM regions based on planning needs and prior results.
Indexed Storage Credit Contracts
Projects selected through the initial procurement entered into 20-year contracts involving Indexed Storage Credits, or ISCs. The indexed structure is intended to provide a long-term revenue framework while accounting for value the project may earn in wholesale electricity markets.
The contracts can support project financing, but they also create long-term obligations that must be evaluated against future market conditions. Important considerations include:
Project-development and completion risk
Contract price and adjustment provisions
Wholesale energy and capacity revenues
Availability and performance requirements
Benefits delivered to Illinois customers
Geographic location and regional-grid needs
Interconnection and transmission-upgrade costs
Consumer exposure if future market conditions differ from current forecasts
The IPA must publish a draft Energy Storage Resources Procurement Plan by June 1, 2027. The plan will address progress toward the 3,000 MW target, additional procurement needs, coordination with integrated resource planning, and alignment with Illinois’ clean-energy policies. It must then proceed through public comment and ICC review.
Distributed Energy Resources
Distributed energy resources are smaller resources located on customer premises or within local distribution systems. They may include:
Rooftop and community solar
Residential and commercial batteries
Electric vehicles and managed charging
Smart thermostats and controllable building systems
Energy-efficiency measures
Backup generation
Flexible industrial or commercial loads
Microgrids
Geothermal and thermal-energy systems
Individually, many distributed resources are too small to affect regional grid conditions. When coordinated across many customers, however, they may reduce peak demand, supply electricity, or provide services comparable to a larger power plant.
The value of a distributed resource depends on where it is located, when it operates, whether it can respond when requested, and whether utility systems and market rules allow its capabilities to be recognized.
Virtual Power Plants
A virtual power plant coordinates multiple distributed resources through communications and control technology. Rather than constructing one large facility, a virtual power plant may aggregate batteries, thermostats, solar systems, electric vehicles, water heaters, or flexible commercial loads across many locations.
A well-designed program may:
Reduce demand during peak periods
Discharge customer batteries when the grid is stressed
Shift electric-vehicle charging to lower-demand hours
Coordinate solar generation and storage
Provide wholesale-market or utility services
Defer some distribution-system upgrades
Compensate participating customers for making resources available
CRGA directs development of a statewide virtual-power-plant framework under Illinois Commerce Commission oversight. Important implementation questions include customer compensation, enrollment, data access, cybersecurity, equipment interoperability, utility control, performance measurement, consumer protections, and whether aggregated resources can participate effectively in PJM and MISO markets.
Participation terms also must address customer needs. A battery reserved entirely for grid use may provide less backup power during an outage, while a battery reserved entirely for customer resilience may provide fewer grid benefits. Programs can balance those objectives by establishing minimum customer reserves, notice requirements, event limits, and clear opt-out provisions.
Demand Response & Flexible Loads
Demand response reduces or shifts electricity consumption during periods of high demand or system stress. Participating customers may receive compensation or bill savings for temporarily adjusting operations.
Potential participants include:
Industrial facilities able to modify production schedules
Commercial buildings with automated energy controls
Data centers with flexible computing loads or backup resources
Residential customers with smart thermostats
Electric-vehicle owners using managed charging
Customers with batteries or thermal storage
Water and wastewater systems able to shift selected operations
Demand flexibility can be faster to deploy than new generation, but it must be measurable and dependable. Planning should not assume a customer will reduce demand during a critical event unless enforceable program terms, operational experience, or verified performance support that assumption.
Time-Varying Rates
Traditional rates may charge the same supply price throughout the day even though the cost of producing and delivering electricity changes by hour. Time-of-use, hourly, critical-peak, and other time-varying rates attempt to reflect those differences.
These rates can encourage customers to move discretionary electricity use—such as vehicle charging, water heating, battery charging, or some industrial processes—to lower-cost periods. They may also improve the economics of batteries that charge when prices are lower and discharge or reduce customer purchases when prices are higher.
Consumer outcomes depend on rate design and individual usage patterns. Customers unable to shift essential use may pay more under a poorly designed program. Effective protections may include:
Voluntary participation or meaningful opt-out options
Clear price and peak-period disclosures
Bill-comparison tools
Introductory guarantees or transition periods
Protections for medically vulnerable and low-income customers
Access to enabling technology
Regular assessment of savings and participation
Solar-Plus-Storage & Storage for All
Pairing solar generation with a battery allows electricity produced during daylight hours to be used later. Depending on program rules and system configuration, solar-plus-storage may support customer savings, backup power, peak reduction, and participation in a virtual power plant.
CRGA directs the ICC to oversee solar-plus-storage rebate and virtual-power-plant initiatives. It also directs the IPA to evaluate and potentially implement Storage for All, which would support storage paired with projects developed through Illinois Solar for All.
The law authorizes the IPA to allocate up to 25 percent of the Illinois Solar for All budget to Storage for All. The IPA began stakeholder engagement on program design in fall 2026. Until the design and approval process is completed, the authorization should not be described as a generally available customer incentive.
Program-design questions include:
Which customers and project categories qualify
Whether storage must be paired with new or existing solar
Required customer savings
Ownership and maintenance responsibilities
Backup-power capabilities
Participation in grid-service programs
Treatment of tax credits and other incentives
Consumer disclosures and contract terms
Geographic and environmental-justice priorities
Geothermal & Thermal Energy Networks
CRGA also expands policy support for resources that reduce or shift heating and cooling demand.
The Act directs the IPA to design a Geothermal Homes and Businesses Incentive Program through the 2028 Long-Term Renewable Resources Procurement Plan. The program may use up to $10 million per delivery year for geothermal renewable energy credits supporting eligible heating and cooling systems.
Thermal energy networks can connect multiple buildings to shared heating and cooling infrastructure. These systems may reduce direct fossil-fuel use, create opportunities to use existing utility and skilled-trades expertise, and affect electric demand differently from individual building electrification.
Geothermal and thermal networks are not electric batteries, but they can provide a form of thermal flexibility by reducing or shifting the electricity required for heating and cooling. Their long-term value will depend on project costs, building density, customer participation, workforce capacity, utility regulation, and integration with electric-grid planning.
Local Siting, Safety & Emergency Planning
Utility-scale battery facilities present land-use and public-safety questions distinct from traditional power plants. State law now provides a more standardized framework affecting local regulation of commercial storage projects, while counties and municipalities continue to perform important permitting, inspection, emergency-planning, and public-safety functions within that framework.
Project review may involve:
Compliance with applicable building, electrical, and fire codes
Battery chemistry and system design
Thermal-runaway detection and suppression
Separation distances and site access
Emergency-response plans
Fire-department training and equipment
Water, air, and runoff considerations
Noise, lighting, fencing, and security
Decommissioning and financial assurance
Recycling or disposal of damaged and retired equipment
Coordination among developers, local governments, fire districts, and emergency-management agencies
CRGA also established a standardized property-tax valuation framework for qualifying commercial energy-storage systems. This can provide greater predictability for developers and taxing districts, but local governments should distinguish projected tax-base benefits from revenues that begin only after a project is completed and assessed.
Consumer Data, Cybersecurity & Control
Distributed-resource programs require utilities, aggregators, equipment providers, and customers to exchange information and control signals. These systems can improve grid operation, but they also raise questions concerning:
Customer consent
Collection and use of interval energy data
Cybersecurity standards
Third-party access
Remote control of customer devices
Data retention and sharing
Responsibility for equipment or communications failures
Customer ability to withdraw from a program
Clear rules are particularly important when a program can remotely change thermostat settings, charging schedules, battery operation, or other customer equipment.
Implementation Questions to Monitor
Important storage and distributed-resource issues include:
Whether the first 600 MW of contracted storage reaches commercial operation
Progress toward the 3,000 MW target
Results and regional allocation of future procurements
Development of the 2027 Energy Storage Resources Procurement Plan
Storage-project interconnection and transmission requirements
Cost and performance of Indexed Storage Credit contracts
Design of the statewide virtual-power-plant program
Availability and terms of solar-plus-storage rebates
Development of Storage for All
Customer savings under time-varying rates
Treatment of flexible data-center and industrial loads
Local siting, fire safety, taxation, and emergency preparedness
Cybersecurity and customer-data protections
Whether storage and demand flexibility reduce capacity costs or defer grid investments
Coordination with Illinois’ Integrated Resource Plan and regional PJM and MISO markets
Storage policy should ultimately be measured by completed projects and verified performance—not only procurement targets. The relevant question is whether these resources operate when needed, provide value exceeding their costs, protect participating customers, and improve the reliability and affordability of Illinois’ energy system.
Sources & Further Reading:
Illinois Power Agency—Energy Storage Procurements and Programs
Illinois Power Agency—Clean and Reliable Grid Affordability Act Implementation
Illinois General Assembly—Senate Bill 25 and Public Act 104-0458
Illinois Power Agency Procurement Administrator—Energy Storage Procurement
Illinois Department of Revenue—Commercial Energy Storage Systems Valuation
Transmission policy determines how electricity moves across the bulk power system, where new lines and substations are built, how generation and large customers connect to the grid, and who pays for the resulting investments. These decisions increasingly affect reliability, consumer costs, renewable-energy development, economic growth, and the ability to respond to changing electricity demand.
Illinois presents an especially complex planning environment because the state is divided between two regional transmission organizations—MISO and PJM—while federal regulators, the Illinois Commerce Commission, utilities, transmission owners, local governments, and neighboring states all have distinct roles.
How Transmission Differs from Distribution
Transmission facilities generally move large quantities of electricity over longer distances and at higher voltages. Distribution facilities deliver electricity from substations to homes, businesses, and other retail customers.
The Federal Energy Regulatory Commission generally regulates interstate transmission service, regional transmission tariffs, and wholesale electricity markets. Illinois retains authority over matters that include utility regulation, retail rates, and the siting of many transmission facilities within the state.
A transmission project may be proposed for several different reasons:
Correcting an identified reliability violation;
Replacing aging infrastructure;
Reducing congestion or other system costs;
Connecting new generation or energy-storage facilities;
Serving major new electricity demand;
Supporting state or federal public-policy requirements;
Improving transfers between regions; or
Preparing the grid for multiple plausible long-term demand and generation scenarios.
The project’s classification can affect how it is evaluated, which entity may construct it, and how its costs are assigned.
MISO, PJM & Illinois’ Divided Regional Grid
Most of central and southern Illinois participates in the Midcontinent Independent System Operator, while northern Illinois—including the Commonwealth Edison service territory—participates in PJM Interconnection.
MISO and PJM operate their respective regional grids, administer wholesale markets, conduct reliability and transmission planning, and manage interconnection processes under tariffs approved by FERC. Transmission owners build and operate facilities, but regional projects generally must proceed through the applicable planning and approval processes.
Because Illinois is divided between the two organizations, statewide energy policy must account for different market rules, capacity structures, planning procedures, and cost-allocation methods. Coordination across the MISO-PJM boundary is also important because congestion or insufficient transfer capability at a regional seam can limit the movement of electricity even when generation is available elsewhere.
Illinois’ Climate and Equitable Jobs Act and Clean and Reliable Grid Affordability Act established or expanded state planning responsibilities that interact with these regional processes. The Illinois Power Agency’s first statewide integrated resource plan and its study of alternative regional-transmission-organization arrangements are scheduled for submission in 2026. These proceedings can help Illinois evaluate how generation, transmission, storage, demand response, affordability, and reliability fit together across both regional markets.
Long-Term Regional Transmission Planning
Federal transmission policy now requires a more forward-looking approach to regional planning. FERC Orders 1920, 1920-A, and 1920-B require transmission providers to conduct long-term regional planning using multiple scenarios and a planning horizon of at least 20 years.
Those scenarios must account for factors such as:
Changes in electricity demand and electrification;
Planned generation retirements;
State and federal energy laws;
Utility resource plans and supply obligations;
Generator-interconnection requests and withdrawals;
Changing technology and fuel costs; and
The expected availability of generation and energy storage.
The rules also strengthen the role of state regulators in planning and cost-allocation discussions. Potential projects must be evaluated using transparent criteria and a range of possible benefits, including reliability improvements, avoided replacement costs, reduced congestion, production-cost savings, reduced energy losses, and improved performance during extreme conditions.
Transmission planners must also consider whether existing corridors can be used more efficiently through advanced conductors, dynamic line ratings, power-flow controls, transmission switching, or the “right-sizing” of facilities already scheduled for replacement. These technologies may increase grid capacity more quickly or at lower cost than constructing an entirely new corridor, although they do not eliminate the need for new transmission in every location.
Generation and Storage Interconnection
A proposed power plant or energy-storage facility generally cannot begin commercial operation merely because it has entered an interconnection queue. MISO or PJM must study how the facility would affect the regional grid, identify required network upgrades, and determine the costs and technical requirements associated with connecting it.
FERC Order 2023 changed the federal interconnection framework by requiring reforms that include cluster-based studies, stronger project-readiness requirements, commercial-readiness deposits, improved study deadlines, and consideration of certain transmission technologies. Implementation occurs through FERC-approved regional tariff changes.
Interconnection queues therefore represent proposed development—not a forecast that every listed project will be completed. Projects may withdraw because of financing problems, changing market conditions, permitting obstacles, equipment constraints, or unexpectedly high network-upgrade costs.
Interconnection policy presents several recurring questions:
How can viable projects be studied and connected more quickly?
Which network upgrades are attributable to an individual project, and which provide broader regional benefits?
When should upgrade costs be assigned to an interconnection customer rather than a wider group of transmission users?
Can shared or proactively planned upgrades reduce the cost and delay associated with project-by-project studies?
How should generation, storage, and large new electricity loads be coordinated in system planning?
The related questions raised by data centers and other large-load customers are addressed more fully in the separate section on large energy users and grid cost allocation.
Who Pays for Transmission
Transmission costs may be allocated locally, across a utility zone, among multiple zones, or more broadly across a region, depending on the project’s purpose and the applicable FERC-approved tariff.
A central principle of federal cost allocation is that costs should be assigned in a manner that is at least roughly commensurate with expected benefits. Applying that principle can be difficult because a single project may improve reliability, reduce congestion, connect new resources, support public policy, and defer other investments at the same time.
Important policy questions include:
Which customers or regions are expected to benefit?
Over what period should benefits be measured?
How should reliability and resilience benefits be valued?
Should project costs be allocated differently when a line primarily serves a new generator or large customer?
Are alternatives—such as storage, demand response, reconductoring, or distributed resources—less costly?
How will regional transmission charges ultimately affect Illinois retail customers?
Approval of a project as necessary or beneficial does not by itself resolve whether its costs are reasonable or how those costs should appear in customer rates.
Rights of First Refusal and Competitive Transmission Development
A transmission right of first refusal generally gives an incumbent transmission owner the first opportunity—or an exclusive right—to construct certain qualifying projects in its service territory.
Supporters argue that incumbent utilities possess local operating experience, established rights-of-way, existing facilities, and clear responsibility for maintaining system reliability. Opponents argue that competitive solicitation can produce lower costs, encourage innovation, and provide stronger protections against excessive project spending.
The answer is not uniform for every transmission project. Development rights may depend on federal rules, the applicable MISO or PJM tariff, the project’s classification, state law, and whether the project is local, regional, interregional, or associated with an existing facility. Some projects remain assigned to incumbent transmission owners, while others may qualify for a competitive development process.
The broad Ameren-focused Illinois proposals discussed in the former version of this page did not become current statewide law. Those proposals—including the 2023 amendatory-veto dispute and subsequent legislation—are better retained in the Historical Illinois Energy Policy Archive as background on an unresolved policy debate.
Illinois Siting and Community Impacts
Regional selection of a transmission project does not necessarily complete the state approval process. Depending on the project and the developer, the Illinois Commerce Commission may consider requests for certificates, route approval, construction authority, and related relief under the Illinois Public Utilities Act.
Transmission proceedings may address:
The need for the proposed facility;
Alternative routes and existing corridors;
Reliability and regional-planning determinations;
Project costs and effects on customers;
Agricultural, environmental, and land-use impacts;
Proximity to homes and community facilities;
Coordination with roads and other infrastructure;
Property rights, easements, and potential eminent-domain authority; and
Public notice and opportunities for affected communities to participate.
Regional planning, state siting, local coordination, land acquisition, environmental review, and cost recovery are related but distinct processes. Approval at one stage should not be assumed to resolve every issue at another.
Issues to Monitor
Illinois transmission policy will continue to develop through:
MISO and PJM implementation of federal planning and interconnection reforms;
Long-range and interregional transmission portfolios;
Illinois’ statewide integrated resource planning;
The state’s examination of its current MISO-PJM structure;
Treatment of large new loads and associated grid upgrades;
Generator and storage interconnection reforms;
Transmission cost-allocation disputes;
Use of advanced transmission technologies;
Competitive-development and right-of-first-refusal proposals; and
ICC certificate, routing, and utility cost-recovery proceedings.
Transmission expansion can strengthen reliability and provide access to lower-cost or cleaner generation, but each proposal requires careful examination of need, alternatives, benefits, community impacts, development rights, and the allocation of costs.
Sources & Further Reading:
Data centers, advanced-manufacturing facilities, hydrogen projects, electrified industrial operations, and other large energy users can require as much electricity as an entire community. These projects may generate construction activity, investment, tax revenue, and technology-sector growth, but they can also require new generation, transmission lines, substations, distribution upgrades, and long-term capacity commitments.
The central policy question is not simply whether Illinois should attract large energy users. It is how the state can accommodate responsible development without shifting unreasonable infrastructure, reliability, or electricity-supply costs to households and existing businesses.
Proposed Demand Is Not the Same as Operating Demand
Utility and regional-grid forecasts may contain projects at very different stages of development. Some large-load proposals have secured land, financing, permits, and firm utility commitments. Others remain preliminary or may pursue connections in several locations before selecting a site.
Overestimating demand could lead to unnecessary infrastructure and higher customer costs. Underestimating it could leave the grid without sufficient generation or delivery capacity.
Planning entities therefore need to evaluate:
Whether a project has demonstrated financial and operational readiness;
Its expected construction and energization schedule;
The amount and pattern of electricity it is likely to use;
Whether demand will increase in phases;
The likelihood that the customer will complete and remain at the site;
Whether duplicative requests appear in other utility territories;
The customer’s ability to reduce demand during stressed grid conditions; and
Whether required generation and transmission improvements can be completed on time.
Illinois’ new integrated-resource-planning process provides an opportunity to examine large-load forecasts alongside power-plant retirements, new generation, energy storage, transmission constraints, affordability, and reliability.
Connecting a Large Load to the Grid
A utility must determine whether its existing system can safely serve a proposed large customer. Depending on the requested service and location, the project may require distribution improvements, a new or expanded substation, high-voltage transmission upgrades, or additional study through MISO or PJM.
A large-load connection is not the same as a generator-interconnection request. The customer consumes electricity instead of supplying it, although the same development may separately propose on-site generation or storage.
Important connection questions include:
What facilities are required to serve the customer?
Which improvements are dedicated to the customer, and which provide wider system benefits?
How much must the customer pay before construction begins?
What happens if the project is delayed, downsized, relocated, or canceled?
Will the demand be firm, interruptible, or subject to emergency curtailment?
Can the project be served without reducing reliability for existing customers?
Are sufficient generation and transmission resources likely to be operating when service begins?
Local approval of a data-center or industrial site does not, by itself, guarantee that sufficient electricity will be available on the developer’s preferred schedule.
Protecting Existing Customers from Cost Shifting
Serving a large new customer may require substantial utility investment before that customer begins paying its full electric bill. If the project does not materialize—or operates at only a fraction of its projected demand—other customers could be left responsible for infrastructure constructed on its behalf.
Potential customer protections include:
Upfront contributions toward construction;
Minimum monthly demand charges;
Long-term service commitments;
Financial-security or collateral requirements;
Milestone payments tied to development progress;
Exit fees or termination charges;
Charges based on contracted capacity rather than usage alone;
Separate treatment of customer-specific and system-wide improvements; and
Refund provisions if customer-funded facilities later provide measurable benefits to others.
These protections should reflect the project’s size, risk, and system effects. Requirements that are too weak may expose other customers to stranded costs, while unnecessarily rigid requirements may discourage viable investment or prevent flexible arrangements that benefit the grid.
A sound rate structure should identify which expenses are caused by the new customer, which improvements provide broader benefits, and which development risks should remain with the customer or utility shareholders.
Energy Supply, Capacity & Reliability
Paying for a physical connection does not necessarily establish that sufficient electricity will be available during periods of peak demand. A large customer may increase the need for generation capacity, transmission imports, storage, demand response, or other reliability resources.
Potential approaches include requiring or encouraging large customers to:
Procure clean or firm energy resources;
Support development of new generation or storage;
Participate in demand-response programs;
Reduce nonessential consumption during grid emergencies;
Shift flexible computing or industrial activity away from peak periods;
Phase service as new infrastructure becomes available; or
Provide accurate operating data for utility and regional planning.
A contractual commitment to purchase renewable energy does not always mean that electricity will be generated in the same region or during the same hours in which the facility operates. Policymakers may therefore distinguish annual renewable-energy purchases from hourly matching, deliverable regional supply, and resources that contribute directly to capacity and reliability.
On-Site Generation and Co-Location
Some large customers seek to locate next to an existing power plant or develop dedicated generation behind the customer’s meter. These arrangements may reduce reliance on portions of the transmission system, but they do not automatically eliminate wider grid effects.
Policy and regulatory questions include:
Whether the generator will remain available to serve other customers;
The effect on regional capacity and wholesale markets;
Backup service when dedicated generation is unavailable;
Use of transmission, ancillary, and reliability services;
Responsibility for network upgrades;
Federal versus state regulatory jurisdiction;
Emissions and environmental-permitting requirements; and
Whether costs are being shifted to customers outside the arrangement.
FERC and regional grid organizations continue to examine the reliability, jurisdictional, market, and cost-allocation consequences of locating very large loads directly with generating facilities.
Demand Flexibility as a Grid Resource
Some data-center computing activity, industrial processes, storage systems, and cooling operations may be capable of changing when or how they consume electricity. Large customers that can reduce demand during peak periods or grid emergencies may lower their impact on the system.
Useful tools may include:
Time-varying electric rates;
Interruptible-service agreements;
Automated demand response;
On-site energy storage;
Thermal storage or flexible cooling;
Phased energization;
Emergency curtailment protocols; and
Compensation for verified reductions that benefit the grid.
Demand flexibility should be supported by measurable and enforceable commitments. A customer’s general statement that it could reduce electricity use should not be treated as equivalent to dependable demand response available when the system needs it.
Community and Environmental Considerations
Electricity is only one component of data-center and large-load policy. State and local decision-makers may also consider:
Water use and cooling technology;
Noise from cooling equipment and backup generators;
Air emissions and generator operating limits;
Land use, setbacks, and compatibility with nearby development;
Construction traffic and public-infrastructure needs;
Emergency-response planning;
Permanent employment relative to the project’s size;
Property-tax treatment and other public incentives;
Community-benefit commitments; and
Transparency concerning projected energy and water consumption.
Economic-development incentives should be evaluated together with expected employment, tax revenue, infrastructure costs, environmental effects, and the extent to which the developer will bear project-related expenses.
Illinois’ economic-development incentives and its utility-regulatory policies are related but separate. Eligibility for a tax benefit does not determine whether a project can obtain electric service, how quickly it can connect, or how utility costs should be allocated.
Toward an Illinois Large-Load Framework
A durable Illinois framework could combine economic-development opportunities with consumer, reliability, and community protections. Major elements may include:
Consistent standards for identifying viable large-load projects;
Improved disclosure of forecast demand and development milestones;
Coordination among utilities, MISO, PJM, the Illinois Commerce Commission, the Illinois Power Agency, and local governments;
Customer-specific tariffs or contracts addressing construction and cancellation risks;
Protections against unreasonable cost shifting;
Consideration of clean-energy procurement, storage, and demand flexibility;
Transparent evaluation of incentives and community benefits;
Protection of legitimate confidential information without concealing material system impacts; and
Periodic review as technology, electricity demand, and regional-market rules change.
Because northern Illinois participates in PJM while much of central and southern Illinois participates in MISO, a single policy model may not produce identical results statewide. Illinois policy must account for differences in utility systems, regional capacity structures, transmission constraints, and available generation.
ICG Policy Analysis
In the June 2026 podcast Roadmap for Data Center Policy Compromise, Illinois Capitol Group examines how policymakers could move beyond a choice between unrestricted development and a complete policy retreat. The episode discusses possible areas of compromise involving infrastructure responsibility, consumer-cost protections, clean-energy expectations, transparency, local impacts, and the continued economic-development role of data centers.
Related technology-development, incentive, and community-impact issues are addressed on ICG’s Illinois Advanced Technology & Innovation Policy page.
AI Data Centers & the Illinois AI Cabinet
Executive Order 2026-07, issued September 22, 2026, created the Illinois Artificial Intelligence Cabinet and directed it to evaluate the energy burden that AI-related data centers may place on the Illinois grid and existing ratepayers, including impacts arising through PJM Interconnection. The Cabinet will also consider whether data-center tax incentives, permits, or operational approvals should be conditioned on compliance with AI safety, accountability, and transparency standards.
The order does not itself establish a new utility rate, allocate infrastructure costs, change PJM rules, or impose new energy requirements on data centers. Its significance for energy policy is that future AI and data-center recommendations may address matters already central to Illinois grid planning: demand forecasting, generation and capacity needs, transmission and distribution investment, large-load rate design, project commitments, and protection of customers from costs attributable to unusually large new loads.
Issues to monitor include whether the Cabinet recommends:
Special rate, deposit, minimum-demand, or infrastructure-payment requirements for AI-related data centers;
Procedures for distinguishing committed projects from speculative interconnection or service requests;
Disclosure or verification of anticipated and actual electricity demand;
Clean-energy, on-site-generation, storage, or demand-response commitments;
Coordination among the Illinois Commerce Commission, utilities, PJM, the Illinois Power Agency, and economic-development agencies; or
Conditions linking state data-center incentives to grid reliability and ratepayer protections.
Until recommendations are issued and implemented through legislation, regulation, utility tariffs, incentive agreements, or other lawful action, these matters remain under evaluation rather than existing statewide requirements.
Issues to Monitor
Illinois stakeholders should continue monitoring:
Large-load forecasts used by utilities, MISO, PJM, and state agencies;
ICC proceedings involving special contracts, tariffs, and utility investments;
Methods for distinguishing committed projects from speculative requests;
Infrastructure deposits, minimum-demand charges, and exit protections;
Allocation of generation, transmission, and distribution costs;
Data-center incentive proposals and eligibility requirements;
State and local siting, water, noise, and environmental policies;
Federal treatment of co-located generation and large loads;
Clean-energy and demand-response commitments; and
Effects on electric affordability and reliability for existing customers.
Sources & Further Reading:
An Illinois electric bill reflects several different services and policy decisions. Although ComEd and Ameren Illinois deliver electricity to most customers in their respective service territories, they do not independently control every component of the final bill.
Electricity supply, regional capacity costs, transmission charges, utility distribution investments, public-policy programs, taxes, and the customer’s usage can all affect the amount due. Understanding which entity controls each component is essential when evaluating a proposed rate increase or affordability policy.
What Is Included in an Electric Bill?
A typical Illinois electric bill may include:
Electricity supply: The cost of producing or purchasing the electricity used by the customer.
Capacity: Payments intended to ensure that sufficient generation or other qualifying resources will be available when regional demand is highest.
Transmission: The cost of moving electricity across the high-voltage regional grid.
Distribution and delivery: The utility’s cost of operating local poles, wires, substations, meters, customer-service systems, and related infrastructure.
Riders and program charges: Separately identified charges or credits associated with particular statutes, regulatory programs, investments, or reconciliations.
Taxes and governmental fees: State or local charges that may vary by location and customer class.
A change in one component does not necessarily mean that every part of the bill increased. For example, wholesale supply and capacity costs may rise even when the utility’s distribution rate remains unchanged. Conversely, an ICC delivery-rate decision may affect customer bills even when wholesale electricity prices fall.
Default Supply, Alternative Suppliers & Municipal Aggregation
Illinois customers generally continue to receive physical delivery service from their local utility regardless of who supplies their electricity.
For eligible customers who remain on utility default supply, the Illinois Power Agency develops procurement plans and conducts competitive procurements, subject to Illinois Commerce Commission approval. The resulting supply charges are generally passed through to customers without becoming utility profit.
Some customers may instead purchase electricity from an alternative retail electric supplier or participate in a municipal aggregation program. Before selecting an alternative offer, customers should compare:
The supplier’s rate with the utility’s current price to compare;
Whether the rate is fixed, variable, or promotional;
The length of the contract;
Early-termination or enrollment fees;
Automatic-renewal provisions;
How renewable or “green” claims are supported; and
What happens when the initial contract period ends.
An alternative supplier can offer different pricing or contract features, but changing suppliers does not replace the local utility’s delivery system or guarantee savings.
How Utility Delivery Rates Are Set
The Illinois Commerce Commission regulates the distribution rates charged by investor-owned electric utilities. ComEd serves much of northern Illinois, while Ameren Illinois provides electric service across substantial portions of central and southern Illinois. Municipal utilities and electric cooperatives operate under different governance and rate-setting structures.
In an ICC rate proceeding, a utility must submit evidence supporting its proposed revenue requirement and planned expenditures. Commission staff, the Illinois Attorney General, consumer advocates, public bodies, business groups, environmental organizations, and other parties may review the filing, conduct discovery, submit testimony, and challenge particular costs.
The Commission evaluates issues that may include:
Whether proposed investments are necessary and reasonable;
Whether expenditures were prudently incurred;
The appropriate return on utility investment;
Allocation of costs among residential, commercial, and industrial customers;
Reliability and service-quality expectations;
Affordability and customer impacts;
Treatment of forecast costs and later reconciliations; and
Whether investments advance statutory grid-modernization and clean-energy requirements.
Illinois’ multi-year rate-plan framework allows utilities to present planned investments and revenue needs over more than one year. Annual adjustments and reconciliation proceedings can then compare forecasts with actual costs and performance. This structure is intended to provide greater planning continuity, but it also makes transparent assumptions, measurable performance, and meaningful Commission oversight especially important.
Approval of a utility program does not mean that every requested expenditure must be recovered from customers. The utility retains the burden of supporting its costs under the applicable statutory and regulatory standards.
Riders, Reconciliations & Bill Transparency
Some utility costs are recovered through riders rather than through a traditional base-rate case. Riders may address energy efficiency, renewable-energy programs, purchased electricity, transmission service, environmental compliance, or other specifically authorized expenses.
A rider may include a later reconciliation that compares amounts collected with actual eligible costs. Depending on the result, customers may receive a credit or be charged an additional amount.
Because riders can change at different times and for different reasons, a customer’s total bill may increase even if the publicly discussed base rate remains stable. Clear bill descriptions, accessible tariff information, and transparent reconciliation proceedings help customers and policymakers understand why charges changed.
Affordability and Energy Burden
Energy affordability is not determined only by the price of each kilowatt-hour. A household’s energy burden—the percentage of household income devoted to energy costs—also depends on income, housing condition, weather, appliance efficiency, fuel type, and the amount of energy required to maintain a safe home.
Illinois affordability tools include:
The Low Income Home Energy Assistance Program, or LIHEAP;
The Percentage of Income Payment Plan, or PIPP, for qualifying households;
Low-income utility discount rates;
Utility payment arrangements and hardship programs;
Weatherization and energy-efficiency assistance;
Consumer protections governing deposits, late payments, and disconnection;
Special protections associated with extreme temperatures, medical conditions, military service, or participation in qualifying assistance programs; and
ICC complaint and dispute-resolution procedures.
Program eligibility, funding, enrollment periods, and available benefits can change. Customers should consult the responsible state agency, community-action agency, utility, or ICC rather than assume that enrollment in one program automatically establishes eligibility for every form of assistance.
Low-Income Discount Rates
Illinois has implemented income-based discount structures for qualifying customers of major electric and natural-gas utilities. These discounts are distinct from one-time financial assistance: an eligible customer may receive an ongoing reduction under the applicable utility tariff.
Eligibility is generally connected to household income and participation in or qualification for designated assistance programs. The precise discount and enrollment process depend on the utility, customer circumstances, and governing ICC order.
Discount rates can reduce immediate energy burdens, but policymakers must also consider:
How eligible customers are identified and enrolled;
Whether participation requires repeated applications;
How discounts interact with LIHEAP and PIPP;
Whether eligible households know the program exists;
How program costs are allocated among other customers; and
Whether the program measurably reduces arrearages and disconnections.
Time-Varying Rates & Customer Flexibility
Traditional residential rates generally charge the same supply price regardless of the hour in which electricity is used. Time-of-use and hourly-pricing programs instead vary prices based on market conditions or predetermined peak and off-peak periods.
These structures may help customers save money by shifting electric-vehicle charging, appliance use, cooling, or other flexible consumption to lower-cost hours. They may also reduce pressure on the grid during peak demand.
However, time-varying rates are not equally beneficial for every household. Customers with medical equipment, inflexible work schedules, inefficient housing, limited access to automation, or unavoidable peak-period needs may have less ability to shift usage. Effective implementation therefore requires:
Clear and understandable rate information;
Tools allowing customers to monitor usage and prices;
Appropriate notice of critical or high-price periods;
Protections against unexpected bill increases;
Accommodation of vulnerable customers; and
Evaluation of whether promised system savings are actually achieved.
Public Act 104-0458, the Clean and Reliable Grid Affordability Act, expanded Illinois’ consideration of time-sensitive rates and other demand-flexibility tools. Implementation should be monitored through ICC, utility, and Illinois Power Agency proceedings.
Reliability, Resilience & Affordability
Utility investment can improve reliability, storm response, cybersecurity, distributed-resource integration, and the ability to serve growing demand. At the same time, customers may pay for those investments over many years.
The appropriate question is therefore not simply whether a project improves the grid, but whether it is the most cost-effective way to produce the claimed benefit.
Regulators and stakeholders may consider:
The expected reduction in outages or restoration time;
Whether lower-cost alternatives were evaluated;
Whether the investment duplicates regional transmission or other utility projects;
Which customers cause or benefit from the expenditure;
Whether advanced technology can defer traditional construction;
The risk that an asset will become underused or obsolete; and
Whether customer protections are needed when projected benefits do not materialize.
Energy efficiency, demand response, distributed generation, storage, and targeted replacement of aging equipment may sometimes reduce or defer more expensive infrastructure. In other circumstances, major construction may be necessary to maintain safe and reliable service.
Consumer Complaints & Participation
Customers may first attempt to resolve billing, service, or supplier disputes directly with the utility or alternative supplier. If the matter remains unresolved, the ICC’s Consumer Services Division can provide information and facilitate the complaint process.
Customers and organizations may also participate in regulatory proceedings by:
Reviewing filings through the ICC’s e-Docket system;
Submitting public comments;
Attending public forums or Commission meetings;
Seeking formal intervention when appropriate; or
Working with consumer, municipal, business, or community organizations participating in the case.
Public comments do not substitute for evidence formally admitted in a contested proceeding, but they can inform the Commission about affordability, service-quality, and community impacts.
Issues to Monitor
Illinois utility-rate policy should continue to monitor:
ComEd and Ameren Illinois multi-year rate plans and annual reconciliations;
Supply, capacity, and transmission costs originating in PJM and MISO;
Utility spending associated with grid modernization and electrification;
Costs associated with data centers and other large new loads;
Performance metrics and consequences for missed targets;
Time-of-use and demand-response implementation;
Participation in low-income discount programs;
LIHEAP, PIPP, arrearage, and disconnection trends;
Alternative retail supplier marketing and contract practices;
Rate impacts across residential, commercial, and industrial customers; and
Whether infrastructure spending produces measurable reliability and customer benefits.
Sources & Further Reading:
Natural gas remains an important source of heating, cooking, industrial energy, and electric generation in Illinois. At the same time, the state must decide how much additional gas infrastructure customers should finance as buildings become more efficient, some customers electrify, climate policies evolve, and long-lived pipelines require replacement.
The central policy question is not limited to whether Illinois will continue using natural gas. It is how the state can maintain safe and reliable service, manage infrastructure costs, protect customers, and evaluate alternative technologies without making unsupported assumptions about future demand.
Illinois Natural-Gas Utilities
Illinois’ investor-owned natural-gas utilities include:
Ameren Illinois, serving portions of central and southern Illinois;
Nicor Gas, serving much of northern Illinois outside Chicago;
Peoples Gas, serving the City of Chicago; and
North Shore Gas, serving portions of northeastern Illinois.
Municipal gas systems and other local arrangements operate under different governance structures.
The Illinois Commerce Commission regulates the delivery rates, service standards, infrastructure investments, and many consumer practices of investor-owned gas utilities. The ICC also administers Illinois’ pipeline-safety program in coordination with federal pipeline-safety requirements.
What Is Included in a Natural-Gas Bill?
A natural-gas bill generally contains several distinct components:
Gas supply: The cost of purchasing the natural gas delivered to customers;
Interstate transportation and storage: Costs associated with transporting gas to Illinois and storing supply for later use;
Local delivery: The cost of operating pipelines, meters, customer-service systems, and other distribution infrastructure;
Infrastructure and program charges: Charges or credits authorized through base rates, riders, or reconciliation mechanisms; and
Taxes and governmental fees: State or local charges that may vary by location.
Gas utilities generally recover prudently incurred commodity costs from customers without adding a profit to the gas itself. Utilities may purchase and store gas during lower-cost periods, use longer-term contracts, or apply other portfolio strategies intended to manage price volatility.
Delivery rates and infrastructure costs are examined separately through ICC proceedings. A decrease in the market price of natural gas can therefore occur at the same time as an increase in delivery charges—or vice versa.
Rate Cases & Infrastructure Investment
When a gas utility requests higher delivery rates, it must submit evidence supporting its operating expenses, capital investments, projected revenue requirement, and proposed allocation of costs among customer classes.
The ICC may consider:
Whether pipeline replacement is required for safety or reliability;
The condition and risk profile of existing infrastructure;
Whether the utility selected a reasonable and cost-effective solution;
Construction schedules and cost controls;
The appropriate return on utility investment;
Effects on residential, commercial, and industrial customers;
Whether proposed facilities may become underused before the end of their expected lives;
Availability of non-pipeline alternatives; and
Whether spending is consistent with the state’s longer-term energy policies.
Safety requirements remain important regardless of broader debates about the future use of natural gas. However, identifying a safety need does not necessarily determine the scope, design, cost, or useful life of the appropriate solution.
Illinois’ former qualifying-infrastructure-plant surcharge framework allowed certain pipeline investments to be recovered between traditional rate cases. Following expiration of that statutory framework, major gas-system investments generally require consideration through base-rate cases or other applicable Commission proceedings.
Pipeline Safety & Replacement
Gas-distribution systems contain pipelines installed during different periods and constructed from different materials. Utilities use inspections, leak surveys, integrity-management programs, repair histories, and risk models to prioritize replacement and maintenance.
Pipeline policy should distinguish among:
Immediate safety repairs;
Replacement of leak-prone or obsolete materials;
Routine maintenance;
System expansion;
Reliability improvements;
Capacity increases; and
broader modernization projects.
Replacing high-risk infrastructure may reduce leaks and improve safety. At the same time, large multiyear programs require effective project management, transparent cost estimates, measurable performance, and independent regulatory oversight.
The issue is particularly significant when a utility proposes installing assets expected to remain in service for several decades while future customer demand remains uncertain.
The ICC’s Future of Gas Process
The Illinois Commerce Commission opened its Future of Gas workshop process in 2024 to examine decarbonization of the state’s natural-gas distribution system and the long-term regulatory questions created by changing technology and customer demand.
Topics considered during the process have included:
Gas-demand forecasts;
Pipeline safety and reliability;
Building energy efficiency;
Electrification;
Geothermal systems and thermal energy networks;
Renewable natural gas, hydrogen, and other alternative fuels;
Non-pipeline alternatives;
Depreciation and stranded-asset risk;
Affordability and energy burden;
Workforce and community impacts;
Environmental justice;
Utility planning requirements; and
Potential legislative or regulatory changes.
The workshop is an information-gathering and policy-development process. Proposals submitted by individual participants are not automatically ICC policy or Illinois law. In particular, discussion of limiting new gas connections, accelerating electrification, or changing utility cost recovery should not be described as an enacted statewide prohibition on natural-gas service.
As of September 2026, the process remains relevant to future regulatory and legislative decisions, including the development of recommendations concerning gas-system planning and decarbonization.
Electrification & Coordinated Energy Planning
High-efficiency electric heat pumps, induction cooking, geothermal systems, building improvements, and thermal energy networks can reduce or replace natural-gas consumption in some buildings. Electrification may also reduce on-site combustion and provide customers with heating and cooling through the same equipment.
Its system effects depend on several factors:
Building condition and insulation;
Equipment efficiency at low temperatures;
Electricity and gas prices;
Upfront installation costs;
Availability of electrical-panel or distribution upgrades;
Customer access to incentives and financing;
The emissions profile of electricity used;
Winter electric-system capacity; and
Whether gas infrastructure costs remain after customers depart.
Poorly coordinated electrification could reduce gas revenue without proportionately reducing gas-system costs, leaving remaining customers responsible for a larger share of fixed expenses. Conversely, continued investment based on overstated gas-demand forecasts could commit customers to unnecessary long-term costs.
Electric and gas planning should therefore be coordinated. Reductions in gas demand may affect electric peak demand, distribution-system needs, resource adequacy, and the timing of utility investments.
Non-Pipeline Alternatives
A non-pipeline alternative uses measures other than traditional pipeline construction to address an identified system need. Depending on the location and circumstances, alternatives may include:
Targeted energy efficiency;
Building weatherization;
Electrification;
Demand management;
Geothermal or shared thermal systems;
Repair or retirement of a limited section of gas infrastructure; or
A portfolio combining several measures.
Non-pipeline alternatives are not appropriate for every safety or capacity problem. They may be most useful when a proposed pipeline project serves a limited area, costs substantially more than reducing local demand, or would create an asset whose long-term use is uncertain.
Effective evaluation requires transparent information about the underlying need, project cost, affected customers, implementation schedule, reliability consequences, and responsibility for building or equipment upgrades.
Alternative Gases & Existing Infrastructure
Some stakeholders propose using renewable natural gas, hydrogen, or synthetic fuels to reduce emissions while retaining portions of the existing gas system.
These resources raise questions concerning:
Available supply and scalability;
Production costs;
Lifecycle greenhouse-gas emissions;
Pipeline and appliance compatibility;
Leakage and safety;
Competing industrial or transportation uses;
Federal subsidies and environmental requirements; and
Which customers should pay the additional cost.
Limited supplies of lower-carbon gas may prove most valuable for industrial processes or other applications that are difficult to electrify. Claims that an alternative fuel can broadly preserve the existing distribution system should be evaluated against realistic supply, cost, safety, and emissions evidence.
Stranded Costs & the Pace of Transition
Gas pipelines and related facilities are commonly depreciated over long periods. If an asset is retired before the utility has recovered its authorized cost, the unrecovered amount may become a stranded-cost issue.
Possible policy approaches include:
Changing depreciation schedules;
Requiring more detailed long-term gas plans;
Limiting expansion where demand is expected to decline;
Using non-pipeline alternatives;
Retiring infrastructure geographically rather than customer by customer;
Allocating transition costs across different customer groups or funding sources; and
Protecting low-income and renter households from disproportionate burdens.
Accelerating cost recovery can reduce the risk of leaving expenses to a smaller future customer base, but it can increase bills for current customers. Extending cost recovery may reduce near-term rate pressure but heighten the risk that customers will continue paying for facilities no longer fully used.
There is no cost-free solution. The objective should be to identify and manage these risks before major investments are approved.
Affordability & Consumer Protection
Natural-gas affordability depends on commodity prices, delivery rates, housing efficiency, weather, income, and the condition of heating equipment.
Available protections may include:
LIHEAP assistance;
The Percentage of Income Payment Plan;
Low-income discount rates;
Weatherization assistance;
Utility payment arrangements;
Extreme-weather disconnection protections;
Medical and other special protections;
Energy-efficiency programs; and
ICC complaint and dispute-resolution procedures.
Energy-transition policies should account for renters, customers unable to afford new equipment, households living in inefficient buildings, and communities where electrical upgrades may be necessary before electrification is practical.
ICG Policy Analysis
In the September 2026 podcast Case Study on the Future of Natural Gas, Illinois Capitol Group examines the competing considerations involved in gas-system planning, including reliability, infrastructure investment, customer affordability, electrification, stranded-cost risk, and the need to distinguish stakeholder proposals from enacted policy.
The case study illustrates why natural-gas decisions should not be treated as a simple choice between preserving every existing investment and immediately abandoning the system. A durable approach requires project-specific review, realistic demand forecasts, coordination with the electric grid, and protections for customers who may otherwise bear disproportionate transition costs.
Issues to Monitor
Illinois natural-gas policy should continue to monitor:
The ICC’s Future of Gas findings and recommendations;
Utility rate cases and infrastructure proposals;
Pipeline-safety and leak-reduction performance;
Peoples Gas system-modernization planning;
Development of non-pipeline-alternative screening standards;
Long-term gas-demand forecasts;
Coordination between electric and gas planning;
Building-electrification and efficiency incentives;
Low-income discount enrollment and energy burdens;
Treatment of stranded costs and depreciation;
Alternative-fuel cost, availability, and safety; and
Legislative proposals affecting new gas connections or utility cost recovery.
Sources & Further Reading:
This archive preserves selected Illinois Capitol Group analysis, government reports, legislative proposals, and outside reporting that provide useful background on the development of Illinois energy policy.
Archived materials reflect the laws, proposals, forecasts, and policy debates in effect on their original publication dates. They should not be treated as descriptions of current law or current market conditions without consulting the updated sections and official resources elsewhere on this page.
ICG Energy Policy Podcasts & Reviews
September 28, 2025 — Review of Pending Illinois Energy Legislation: A concise review of the major energy proposals under consideration before passage of the legislation that ultimately became the Clean and Reliable Grid Affordability Act. The episode discusses resource adequacy, energy storage, clean-energy procurement, customer costs, and the political obstacles facing an omnibus agreement.
July 14, 2025 — Illinois Energy Grid Modernization and Transmission Policy: A review of the transmission-policy debate following the 2025 spring legislative session, including competing developer, utility, labor, business, environmental, and regional-grid perspectives.
July 9, 2025 — Illinois Commerce Commission First Half of 2025 Review: A survey of significant ICC decisions and regulatory activity from December 2024 through July 2025. The episode provides historical context for utility rates, grid investment, consumer protection, and agency implementation responsibilities.
July 8, 2025 — Illinois Energy Resource Adequacy Review: A review of the ICC’s 2024–2025 resource-adequacy policy sessions and the reliability, capacity-market, energy-storage, transmission, and demand-response issues discussed during those proceedings.
More recent ICG episodes—including the Midwest capacity analysis, data-center policy discussion, and natural-gas case study—are linked within the current substantive sections to which they apply.
Energy Storage & Resource-Adequacy Background
2024 — The Power Bureau: Cost and Benefit Analysis of Energy Storage Resource Deployment in Illinois:This stakeholder-commissioned study evaluated a proposed 8,500-megawatt Illinois energy-storage program and estimated potential reliability, customer-cost, economic, and emissions benefits. Its recommendations preceded Illinois’ enactment of a different statutory storage framework in Public Act 104-0458.
2024 — Energy News Network/Canary Media: Study Suggests a Big Role for Grid Battery Storage as Illinois Shutters Its Coal Power Plants: Contemporary reporting describing the Power Bureau study, its supporters’ conclusions, and the broader debate over storage as Illinois approached additional fossil-generation retirements.
2023 — Illinois Power Agency Electricity Procurement Plan: Earlier procurement and resource-adequacy planning materials that informed the page’s former discussion of MISO, PJM, ComEd, Ameren Illinois, and MidAmerican Energy. More recent IPA studies and implementation materials should be used for present-day planning conclusions.
These materials are retained because they document the analyses and forecasts that shaped later legislative action. Illinois’ current storage procurement, integrated-resource-planning, and resource-adequacy processes are addressed in the updated sections of this page.
Transmission Competition & Right-of-First-Refusal History
2023 — House Bill 3445: Legislation that included a right of first refusal for certain transmission development in the Ameren Illinois service territory. Governor Pritzker issued an amendatory veto, and the proposal did not become permanent Illinois law in that form.
August 2023 — Governor’s Amendatory Veto Message for House Bill 3445: The veto message raised concerns about competition and consumer costs while recommending changes to the transmission-development provisions.
2024 — House Bill 5234: A subsequent transmission right-of-first-refusal proposal that continued the debate but did not establish the broad statewide framework contemplated by its supporters.
2022 — U.S. Department of Justice and Federal Trade Commission Comment on Transmission Competition:Federal antitrust agencies discussed the possible effects of reinstating transmission rights of first refusal and argued that competitive development can provide cost and innovation benefits.
These sources explain the origins of Illinois’ RoFR debate. Current transmission planning, project eligibility, competitive selection, development rights, and cost allocation depend on applicable federal rules, regional tariffs, project classifications, and state law, as discussed in the updated Transmission Planning, Interconnection & Regional Grid Governance section.
Federal Grid-Modernization Funding
U.S. Department of Energy — Grid Resilience and Innovation Partnerships Program: The federal GRIP program has supported transmission, distribution, smart-grid, resilience, and interconnection projects. This link is preserved from the prior page because federal funding opportunities and selected projects can provide useful historical and implementation context, although current availability and eligibility should always be confirmed through the Department of Energy.
Using the Archive
These materials can help readers:
Trace how Illinois moved from earlier storage proposals to the framework enacted in Public Act 104-0458;
Understand the policy discussions that preceded current resource-adequacy and integrated-planning processes;
Review the development of Illinois’ transmission-competition debate;
Compare earlier reliability forecasts with later market and agency findings; and
Identify recurring stakeholder concerns involving affordability, reliability, clean-energy development, utility investment, and regulatory authority.
For present requirements, deadlines, rates, procurements, and regulatory proceedings, readers should rely on the current-policy sections and official-source directory on this page.
Energy legislation and regulatory decisions can affect utility costs, infrastructure investments, project development, economic opportunities, and long-term organizational planning. Illinois Capitol Group helps organizations evaluate proposals, engage policymakers and regulatory agencies, develop advocacy strategies, and prepare for implementation.