§ 1-15

Illinois § 1-15

• Jurisdiction: Illinois
• Topic: REGULATION
• Ch. 220: UTILITIES
• Act 220 ILCS 31/: Municipal and Cooperative Electric Utility Transparent Planning Act.

Text

(This Section may contain text from a Public Act with a delayed effective date ) Sec. 1-15. Purpose and contents of integrated resource plan. (a) Beginning on or before January 1, 2027, and every 5 years thereafter on or before January 1, all generation and transmission electric cooperatives with members in this State, all municipal power agencies, and all municipalities and distribution electric cooperatives that provide electricity for service to more than 7,000 retail electric customer meters shall initiate an integrated resource planning process to prepare and issue a preliminary integrated resource plan to be posted on its website by January 1 of the following year. Municipalities and electric cooperatives that are members of, and have a full requirements contract with, a municipal power agency or generation and transmission electric cooperative may adopt the integrated resource plan of such other utility. In the alternative, a municipality or electric cooperative that is a member of, and has other than a full requirements contract with, a municipal power agency or generation and transmission electric cooperative may include the resources or resource planning of the municipal power agency or generation and transmission electric cooperative in its integrated resource plan, and the municipal power agency or generation and transmission electric cooperative may adopt such municipality's or electric cooperative's integrated resource plan. An integrated resource plan completed by a utility on or after January 1, 2024 shall satisfy the first integrated resource plan requirement if it meets the criteria set forth in subsections (b) through (d). (b) The purposes of the integrated resource plan are to consider and evaluate the utility's current portfolio, including electrical generation, power supply contracts, storage, and demand-side programs; to forecast future load changes; to facilitate prudent planning with respect to reliability, resources, energy and capacity procurements, power supply contract expiration, and timing of generation retirement; to determine what resource portfolio will maintain reliability consistent with RTO obligations; to minimize cost and meet State and federal environmental law; and to articulate steps the utility will take to minimize customer costs and consider environmental impacts through changes to its current generation portfolio through construction, procurement, retirement, demand-side programs, or other applicable technology or processes. (c) As part of the integrated resource plan development process, a utility shall consider all resources reasonably available or reasonably likely to be available during the relevant time period to satisfy the demand for electricity services for a planning period of at least 5 years, taking into account both supply-side and demand-side electric power resources and cost and benefits projections for at least the next 20 years. (d) A utility may include the results of an all-source request for proposals for generation resources and capacity contracts for delivery beginning within the next 5 years in its integrated resource plan. If the utility chooses not to include such results, the utility must provide notice to the utility's ratepayers upon issuance of the integrated resource plan that states why the utility has chosen not to include the results. A utility also shall include the following, at a minimum, in its integrated resource plan: (1) A list of all electricity generation facilities owned by the utility, in whole or in part. For each such facility, the integrated resource plan shall report: (A) general location; (B) ownership information, if ownership is shared with another entity; (C) type of fuel; (D) the date of commercial operation; (E) expected useful life; (F) expected retirement date for any resource expected to retire within the next 8 years, and an explanation of the reason for the retirement; (G) nameplate, maximum output, and accredited capacity; (H) total MWh generated at the facility during the previous calendar year; (I) the date on which the facility is anticipated to be fully depreciated; and (J) any known and measurable compliance obligations, or compliance obligations reasonably expected to apply within the next 8 years, and an estimate of reasonably anticipated expenditures intended to meet those obligations. (2) A list of all power purchase agreements to which the utility is a party, whether as purchaser or seller, including the following, if specified: the counterparty, general location and type of generation resource providing power per the agreement, date on which the agreement was entered into, duration of the agreement, and the energy and capacity terms of the agreement. (3) A list of any sale transactions of any capacity to any purchaser. (4) A list of any demand-side programs and known distributed generation. (5) A narrative description of all existing transmission facilities owned by the utility, in whole or in part, that identifies anticipated transmission constraints or critical contingencies, and identification of the regional transmission organization, if any, that exercises operational control over the transmission facility. (6) A description of all transmission investment costs, disaggregated by expenditure, related to interconnection costs and other transmission system upgrades associated with a new generating resource or increased injection rights from an existing generating resource costing greater than $1,000,000 over the term of the agreement. (7) A copy of the most recent FERC Form 1 filed by the utility. If no such FERC Form 1 has been filed, the utility shall provide Form EIA 860, Form EIA 861, Form EIA 412, or information applicable to the utility included in the sections of FERC Form 1 or Form EIA 412 relating to electric operating revenues, sales for resale, electric operating and maintenance expenses, purchased power, common utility plant and expenses, and electric energy accounts for the prior calendar year. The utility shall not be required to disclose any information required to be protected from disclosure by the regional transmission organizations. (8) A range of load forecasts for the 5-year planning period that incorporate varying assumptions regarding electrification, economic growth, new regulation, and major new customers, sufficient for capacity planning for the utility. Such forecasts shall include: (A) all relevant underlying assumptions; (B) (i) historical analysis of hourly loads consistent with NERC and regional transmission organization reporting requirements; (ii) known or projected changes to future loads; and (iii) growth forecasts and trends by customer class or load type; (C) analysis of the annual capacity and energy impact of any demand-side programs, and energy efficiency programs both current and projected; (D) any reserve margin or other obligations placed on the utility by regional transmission organizations or other entity responsible for reliability standards under State or federal law; and (E) a comparison of past load forecasts and actual realized load and a brief narrative description of any unforeseen events to which any discrepancy may be attributed. (9) A 5-year action plan for meeting the forecasted load that reasonably minimizes customer cost taking into account load, fuel price, and regulatory uncertainty, that ensures reliability consistent with RTO obligations, and meets State and federal environmental law. As part of the action plan, the utility shall: (A) Identify any generation or storage resources reasonably anticipated to be removed from service in the 5 years following the date on which the integrated resource plan is due to be completed. (B) Determine whether given forecasted load growth or unit retirements, or both, the utility will need to procure additional accredited capacity and energy, and provide a quantitative estimate of any such gap between forecasted load and supply-side resources. (C) Provide a narrative description of the utility's process for evaluating possible resources to secure additional needed capacity and energy. (D) Provide a narrative description of the utility's processes for assessing the economic value of existing generation; and consistent with these processes, explain whether any currently operating units could be replaced by other resources at lower cost to ratepayers while maintaining reliability. (E) Identify a preferred portfolio of generation resources, which may include storage, and demand-side programs that, in the utility's judgment, meets its forecasted load and complies with State and federal environmental law, while minimizing ratepayer cost to the extent reasonably achievable in the planning period covered by the action plan. The portfolio shall incorporate any accredited capacity or other reliability requirements of any regional transmission organization of which the utility is a member. (F) Describe any anticipated capital expenditures by the utility in excess of $1,000,000 at existing generation facilities and the reason for such expenditures. (10) A description of all models and methodologies used in performing the integrated resource planning process. The utility shall provide, to any member of a joint action agency or member of a generation and transmission electric cooperative, reasonable access to computer models used in the analysis that are not proprietary to the owner of the model, such as software that cannot be used without a licensing agreement, or otherwise subject to confidentiality by the modeler. (e) As part of the initial integrated resource plan, the utility shall identify all programs, grants, loans, or tax benefits for which the utility has applied for or plans to apply for pursuant to the federal Inflation Reduction Act of 2022 and shall state whether the utility has applied for or otherwise used the program, grant, loan, or tax benefit. (f) Each utility shall consider and include, as part of its integrated resource plan, technically feasible least-cost portfolio scenarios, consistent with RTO reliability obligations, for constructing or procuring renewable energy resources to meet 40% of its energy needs by 2030, meeting the emissions reductions requirements under Public Act 102-662, and supplying 100% of its total projected load through carbon-free resources in combination with storage resources and demand-side programs by 2045.

Legislative History

(Source: P.A. 104-458, eff. 6-1-26.)