HB4120 104TH GENERAL ASSEMBLY

LRB104 15394 AAS 28548 b

104TH GENERAL ASSEMBLY
State of Illinois
2025 and 2026
HB4120

Introduced 10/15/2025, by Rep. Jay Hoffman

SYNOPSIS AS INTRODUCED:

See Index

Creates the Municipal and Cooperative Electric Utility Transparent Planning Act. Requires certain electric cooperatives, municipal power agencies, and municipalities and distribution electric cooperatives to initiate an integrated resource planning process. Sets forth provisions concerning the integrated resource plan; stakeholder meetings; and a prequalified consulting firm list. Makes conforming changes in the Open Meetings Act and the General Not For Profit Corporation Act of 1986. Creates the Utility Data Access Act. Requires the Illinois Commerce Commission to adopt certain rules. Amends the Illinois Finance Authority Act. Adds provisions concerning the Thermal Energy Network Revolving Loan Program. Amends the Illinois Power Agency Act. Makes changes in provisions concerning the powers of the Illinois Power Agency; the Illinois Power Agency Renewable Energy Resources Fund; the Illinois Solar for All Program; the Planning and Procurement Bureau; and the Agency's annual reports. Amends the Illinois Procurement Code. Makes changes in provisions concerning prequalification. Amends the Property Tax Code. Adds a Division concerning commercial energy storage systems. Amends the Counties Code and the Illinois Municipal Code to add a Division concerning the Solar Bill of Rights. Amends the Public Utilities Act. Makes changes in provisions concerning the duties of public utilities; energy efficiency and demand-response measures; certificates of public convenience and necessity; the renewable energy access plan; rate case filing; net electricity metering; distributed generation rebates; the recovery of costs associated with delivery; procurement; alternative retail electric suppliers; and customer self-generation of electricity. Adds provisions concerning time-of-use pricing; the Thermal Energy Network Pilot Program; new large load energy and water reporting requirements; the Energy Reliability Corporation of Illinois; investigation into colocation and rate design; integrated resource plan development, review, and approval; the Interconnection Working Group; and the Interconnection Monitor. Amends the Electric Transmission Systems and Construction Standards Act. Adds requirements for construction contractors. Amends the Environmental Protection Act. Makes changes in provisions concerning greenhouse gases and permit issuance. Makes other changes.

A BILL FOR

AN ACT concerning regulation.

Be it enacted by the People of the State of Illinois, represented in the General Assembly:

ARTICLE 1.

Section 1-1. Short title. This Article may be cited as the Municipal and Cooperative Electric Utility Transparent Planning Act. References in this Article to "this Act" mean this Article.

Section 1-5. Legislative findings and objectives. The General Assembly finds:

(1) Municipal and cooperative electric utilities provide electricity to more than 1,000,000 State residents.

(2) Municipal utilities are public bodies governed and managed by elected public officials or their appointees. Electric cooperatives are not-for-profit, member-owned entities governed and managed by elected boards of directors chosen by their member consumers. Due to their governance structures, municipal and cooperative electric utilities are exempt from certain regulatory requirements under State and federal law.

(3) Because democratic elections by member-ratepayers or customers are the ultimate guarantor of the integrity and cost-effectiveness of these utilities' operations, access to information and decision-making is crucial to ensuring management of these utilities is prudent and responsive.

(4) While not always applicable to municipal and electric cooperatives, integrated resource planning processes have been used in other states to attempt to avoid capacity shortfalls, minimize ratepayer costs, and increase public participation in and knowledge of electric generation portfolio choices.

(5) It is in the long-term best interests of State electricity customers and member-ratepayers that electricity is provided by a diverse portfolio of generation resources that may include generation ownership, power supply contracts, storage resources, and demand-side programs that minimizes costs and strives to ensure reliable service to customers while considering environmental impacts and that long-term utility planning can help facilitate the achievement of reasonable and stable rates, reliability, and State and federal environmental law through such portfolios.

(6) Municipal and electric cooperatives utilities should perform a comprehensive analysis of their existing portfolio and identify opportunities to minimize member-ratepayer and customer costs while maintaining reliability and meeting State and federal environmental law.

(7) To ensure utilities minimize ratepayer costs while maintaining reliability and meeting State and federal environmental law, and to increase transparency and democratic participation, it is important that municipal and cooperative electric utilities participate in an integrated resource planning process with meaningful and appropriate participation and engagement.

Section 1-10. Definitions. As used in this Act:

"Agency" means the Illinois Power Agency.

"Demand-side program" means a program implemented by or on behalf of a utility to reduce retail customer consumption (MWh) or shift the time of consumption of energy (MW) from end users, including energy efficiency programs, demand-response programs, and programs for the promotion or aggregation of distributed generation.

"Electric cooperative" has the meaning given to that term in Section 3-119 of the Public Utilities Act.

"Generation resource" means a facility for the generation of electricity.

"Integrated resource plan" or "IRP" means the planning process for a municipal power agency, municipality, or electric cooperative to evaluate energy supply and demand in order to meet long-term energy needs while minimizing costs and complying with federal and State environmental requirements, consistent with this Act.

"Municipality" has the meaning given to that term in Section 11-119.1-3 of the Illinois Municipal Code.

"Municipal power agency" has the meaning given to that term in Section 11-119.1-3 of the Illinois Municipal Code excluding single project municipal power agencies that do not plan for the full requirements of their members.

"Renewable generation resource" means a resource for generating electricity that uses wind, solar, hydro, or geothermal energy.

"Storage resource" means a commercially available technology that uses mechanical, chemical, or thermal processes to store energy and deliver the stored energy as electricity for use at a later time and is capable of being controlled by the distribution or transmission entity managing it, to enable and optimize the safe and reliable operation of the electric system.

"Utility" means a municipal power agency, municipality, or electric cooperative, including a generation and transmission electric cooperative that provides wholesale electricity to one or more distribution electric cooperatives.

Section 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.

Section 1-20. Stakeholder process for municipal power agencies and municipalities. Prior to the issuance of a final integrated resource plan, a municipal power agency or municipality required to prepare and issue an integrated resource plan shall hold one or more stakeholder meetings open to the municipal power agency's or municipality's ratepayers and members of the public before it issues a preliminary integrated resource plan and one or more such stakeholder meetings after the preliminary integrated resource plan is issued.

Notice of the meetings shall be posted to the municipal power agency's or municipality's website and notice of the initial meeting to customers through the normal billing process not less than 30 days prior to the initial meeting, and any municipality planning to adopt a municipal power agency's final integrated resource plan shall post the notice to its website or a link to the notice on the municipality's website and provide notice of the municipal power agency's initial meeting to customers through the normal billing process not less than 30 days prior to the initial meeting. During the first meeting the municipal power agency or municipality shall describe its proposed processes for developing the integrated resource plan and its core assumptions and constraints. In subsequent meetings, either before or after the preliminary integrated resource plan is issued, the municipal power agency or municipality shall present its proposed preferred portfolio, and describe any planned retirements, capital expenditures on existing generation resources likely to exceed $1,000,000, and planned construction. Each meeting shall provide opportunity for meaningful public engagement including reasonable time to ask questions, have those questions answered, and to provide public comment. Meetings shall be held at times accessible for working residents and shall be recorded, and the municipal power agency or municipality may consider language interpretation needs for non-English speaking ratepayers in areas with a significant proportion of non-English speaking residents. Following the meeting, the municipal power agency or municipality shall provide attendees with a reasonable means of providing public comment in writing and of accessing the recording.

Section 1-25. Procedures for preliminary and final integrated resource plans for municipal power agencies and municipalities.

(a) Each municipal power agency or municipality shall issue its preliminary integrated resource plan, as set forth in this Act, and post it publicly to the website maintained by the municipal power agency or municipality by January 1, 12 months following the date of the calendar year for which the planning is required to begin. Any municipality planning to adopt a municipal power agency's final integrated resource plan shall post the preliminary integrated resource plan publicly to its website or a link to it on the municipality's website.

(b) The municipal power agency or municipality shall facilitate public comment on the preliminary integrated resource plan, as follows:

(1) upon issuance of the preliminary integrated resource plan, the municipal power agency or municipality and any municipality planning to adopt a municipal power agency's final integrated resource plan shall post the preliminary integrated resource plan or a link to it publicly on its website. The plan shall remain publicly accessible for at least 60 days;

(2) the municipal power agency or municipality shall hold one or more public meetings, in person with remote access, where it shall make a representative available to address questions about the preliminary integrated resource plan. The meetings shall be held no sooner than 15 days, and no later than 45 days, after the preliminary integrated resource plan is made available to the public;

(3) the municipal power agency or municipality shall accept public comments on the preliminary integrated resource plan for 30 days following its public posting via website, email, or mail. The municipal power agency or municipality may extend this public comment period by an additional 30 days upon request by ratepayers of the municipal power agency or municipality or any entity that plans to adopt the municipal power agency's or municipality's final integrated resource plan; and

(4) The municipal power agency or municipality shall review public comments and provide responses that reasonably address all relevant issues or questions raised by such comments. The municipal power agency or municipality may modify its preliminary integrated resource plan in response to these comments. The municipal power agency or municipality shall prepare a document with responses to public comments and submit this response document to the Agency no later than 90 days after the close of the comment period. This response document shall be posted publicly on the municipality's or municipal power agency's websites, as relevant, and on the website of the Illinois Power Agency's website along with the preliminary integrated resource plan, as submitted, and any revisions made by the municipal power agency or municipality in response to public comments.

(c) The Illinois Power Agency shall maintain public access to all integrated resource plans submitted pursuant to this Act, accessible through the Illinois Power Agency's website, for no less than 10 years following each integrated resource plan's initial submission.

Section 1-27. Member input and process for electric cooperatives completing an integrated resource plan.

(a) Each electric cooperative completing an integrated resource plan shall post its preliminary integrated resource plan on its website no later than 60 days after completion of the preliminary integrated resource plan. Any distribution electric cooperative intending to adopt a generation and transmission cooperative's integrated resource plan pursuant to Section 1-15 of this Act must also post the preliminary integrated resource plan or a link to the preliminary integrated resource plan on its own website. The preliminary integrated resource plan must remain publicly accessible for at least 60 days.

(b) After posting the preliminary integrated resource plan, but before completion of a final integrated resource plan, an electric cooperative preparing such a plan shall hold at least one meeting open to its members, including members of any member distribution cooperative and any other electric cooperative adopting the integrated resource plan. An electric cooperative intending to adopt the integrated resource plan pursuant to Section 1-15 of this Act may, but is not required to, hold its own meeting. If all other provisions of Section 1-15 are met, an electric cooperative may utilize its annual meeting of members to comply with the meeting requirements set forth in this Section.

(c) Notice of any meeting held pursuant to this Section shall be posted on the website of any electric cooperative whose members are eligible to attend the meeting and, if applicable, provided to members through the electric cooperative's normal billing process or regular communication channel, at least 30 days prior to the meeting. An electric cooperative intending to adopt the integrated resource plan pursuant to Section 1-15 of this Act shall post the meeting notice on its own website and notify members using the same timeline and methods.

(d) Each meeting shall provide an opportunity for meaningful member participation, including sufficient time for members to submit comments, ask questions, and receive responses. Meetings shall be held at times convenient for working members. The electric cooperative may consider language interpretation needs for non-English speaking members in areas with a significant non-English speaking population. At a minimum, the electric cooperative shall present the following information at the meeting:

(1) the purpose and process of developing an integrated resource plan;

(2) the electric cooperative's process for developing the integrated resource plan;

(3) the assumptions and scenarios considered by the electric cooperative;

(4) an overview of supply and demand size resources used to meet energy and capacity needs; and

(5) historical energy and capacity data, along with assumptions regarding future load changes.

(e) Following the meeting, the electric cooperative shall provide a reasonable opportunity for members to submit written comments for at least 30 days. The electric cooperative shall review written comments and prepare a response document that summarizes and addresses relevant member comments. The electric cooperative shall post the response document on its website within 90 days after the close of the comment period. The electric cooperative may modify its preliminary integrated resource plan in response to comments. If the electric cooperative revises its preliminary integrated resource plan in response to comments, it shall post the modified preliminary integrated resource plan on its website.

(f) The Illinois Power Agency shall maintain a copy or a link to an electric cooperative's integrated resource plan completed pursuant to this Act on the Agency's website, for at least 10 years from the date of each plan's initial submission.

(g) An electric cooperative completing an integrated resource plan may select their own consulting firm, complete internally, or select a prequalified consulting firm from the list maintained by the Agency.

Section 1-30. IRP prequalified consulting firm list.

(a) The Illinois Power Agency shall maintain a list of qualified consulting firms for the purpose of developing integrated resource plans on behalf of the utility. In order to prequalify a consulting firm must have:

(1) direct previous experience preparing integrated resource plans for utilities; assembling power supply plans or portfolios for utilities;

(2) one or more employees with an advanced degree in economics, mathematics, engineering, risk management, or a related area of study;

(3) 10 years of experience in the electricity sector;

(4) expertise in wholesale electricity market rules, market planning, market development, and market modeling. This includes, but is not limited to, expertise in current and ongoing FERC Order implementation into RTO markets, RTO governing documents, including, but not limited to, transmission planning processes, and resource planning;

(5) expertise in wholesale electricity market rules, including those established by the federal Energy Regulatory Commission and regional transmission organizations; and

(6) adequate resources to perform and fulfill the required functions and responsibilities.

(b) No later than January 1, 2026 or the effective date of this Act, whichever is later, the Illinois Power Agency shall issue a Request for Information seeking responses from consulting firms. Responses will be due within 45 days of that issuance. The Agency will review responses and within 45 days produce a list of prequalified consulting firms that the Agency determines meet all of the prequalification requirements contained in subsection (a) of this Section. A firm determined not to meet the requirements may request to submit additional information to the Agency for reconsideration. If the Agency subsequently determines a firm meets the requirements, the Agency shall add the firm to the list.

The list will be updated as additional consulting firms request to be added to the list and the Agency determines they meet the requirements contained in subsection (a) of this Section 1-30. The Agency shall not arbitrarily or capriciously deny inclusion to any qualified vendor that satisfies the minimum qualifications set forth in this Section 1-30.

(c) The Illinois Power Agency shall publish the list of prequalified consulting firms on its website. Upon request, the Agency shall also provide each prequalified consulting firm's response to the Request for Information to the affected utility.

(d) A utility required to submit an integrated resource plan may select a consulting firm on the Agency's list of prequalified consulting firms to develop the integrated resource plan and support stakeholder processes.

(e) The utility may apply for funding to offset its costs for its integrated resource plan through the Small Utility Clean Energy Planning Grant Program offered through the Illinois Finance Authority in its role as Climate Bank for the State of Illinois, subject to funding availability or subject to appropriation, and in accordance with program requirements and limitations.

Section 1-32. Planning purposes of an integrated resource plan.

(a) Nothing in this Act shall be construed to alter any regulatory authority or jurisdiction of any State agency with respect to any municipal power agency, municipality, or cooperative.

(b) The submission, posting, or publication of an integrated resource plan pursuant to this Act shall not create any binding obligation, commitment, or duty upon the municipal power agency, municipality, or electric cooperative regarding the construction, retirement, or operation of any facility, or the procurement of any resource.

(c) Nothing in this Act shall be construed to create a private right of action to enforce its provisions.

Section 1-90. The Open Meetings Act is amended by changing Section 2 as follows:

(5 ILCS 120/2) (from Ch. 102, par. 42)

Sec. 2. Open meetings.

(a) Openness required. All meetings of public bodies shall be open to the public unless excepted in subsection (c) and closed in accordance with Section 2a.

(b) Construction of exceptions. The exceptions contained in subsection (c) are in derogation of the requirement that public bodies meet in the open, and therefore, the exceptions are to be strictly construed, extending only to subjects clearly within their scope. The exceptions authorize but do not require the holding of a closed meeting to discuss a subject included within an enumerated exception.

(c) Exceptions. A public body may hold closed meetings to consider the following subjects:

(1) The appointment, employment, compensation, discipline, performance, or dismissal of specific employees, specific individuals who serve as independent contractors in a park, recreational, or educational setting, or specific volunteers of the public body or legal counsel for the public body, including hearing testimony on a complaint lodged against an employee, a specific individual who serves as an independent contractor in a park, recreational, or educational setting, or a volunteer of the public body or against legal counsel for the public body to determine its validity. However, a meeting to consider an increase in compensation to a specific employee of a public body that is subject to the Local Government Wage Increase Transparency Act may not be closed and shall be open to the public and posted and held in accordance with this Act.

(2) Collective negotiating matters between the public body and its employees or their representatives, or deliberations concerning salary schedules for one or more classes of employees.

(3) The selection of a person to fill a public office, as defined in this Act, including a vacancy in a public office, when the public body is given power to appoint under law or ordinance, or the discipline, performance or removal of the occupant of a public office, when the public body is given power to remove the occupant under law or ordinance.

(4) Evidence or testimony presented in open hearing, or in closed hearing where specifically authorized by law, to a quasi-adjudicative body, as defined in this Act, provided that the body prepares and makes available for public inspection a written decision setting forth its determinative reasoning.

(4.5) Evidence or testimony presented to a school board regarding denial of admission to school events or property pursuant to Section 24-24 of the School Code, provided that the school board prepares and makes available for public inspection a written decision setting forth its determinative reasoning.

(5) The purchase or lease of real property for the use of the public body, including meetings held for the purpose of discussing whether a particular parcel should be acquired.

(6) The setting of a price for sale or lease of property owned by the public body.

(7) The sale or purchase of securities, investments, or investment contracts. This exception shall not apply to the investment of assets or income of funds deposited into the Illinois Prepaid Tuition Trust Fund.

(8) Security procedures, school building safety and security, and the use of personnel and equipment to respond to an actual, a threatened, or a reasonably potential danger to the safety of employees, students, staff, the public, or public property.

(9) Student disciplinary cases.

(10) The placement of individual students in special education programs and other matters relating to individual students.

(11) Litigation, when an action against, affecting or on behalf of the particular public body has been filed and is pending before a court or administrative tribunal, or when the public body finds that an action is probable or imminent, in which case the basis for the finding shall be recorded and entered into the minutes of the closed meeting.

(12) The establishment of reserves or settlement of claims as provided in the Local Governmental and Governmental Employees Tort Immunity Act, if otherwise the disposition of a claim or potential claim might be prejudiced, or the review or discussion of claims, loss or risk management information, records, data, advice or communications from or with respect to any insurer of the public body or any intergovernmental risk management association or self insurance pool of which the public body is a member.

(13) Conciliation of complaints of discrimination in the sale or rental of housing, when closed meetings are authorized by the law or ordinance prescribing fair housing practices and creating a commission or administrative agency for their enforcement.

(14) Informant sources, the hiring or assignment of undercover personnel or equipment, or ongoing, prior or future criminal investigations, when discussed by a public body with criminal investigatory responsibilities.

(15) Professional ethics or performance when considered by an advisory body appointed to advise a licensing or regulatory agency on matters germane to the advisory body's field of competence.

(16) Self evaluation, practices and procedures or professional ethics, when meeting with a representative of a statewide association of which the public body is a member.

(17) The recruitment, credentialing, discipline or formal peer review of physicians or other health care professionals, or for the discussion of matters protected under the federal Patient Safety and Quality Improvement Act of 2005, and the regulations promulgated thereunder, including 42 C.F.R. Part 3 (73 FR 70732), or the federal Health Insurance Portability and Accountability Act of 1996, and the regulations promulgated thereunder, including 45 C.F.R. Parts 160, 162, and 164, by a hospital, or other institution providing medical care, that is operated by the public body.

(18) Deliberations for decisions of the Prisoner Review Board.

(19) Review or discussion of applications received under the Experimental Organ Transplantation Procedures Act.

(20) The classification and discussion of matters classified as confidential or continued confidential by the State Government Suggestion Award Board.

(21) Discussion of minutes of meetings lawfully closed under this Act, whether for purposes of approval by the body of the minutes or semi-annual review of the minutes as mandated by Section 2.06.

(22) Deliberations for decisions of the State Emergency Medical Services Disciplinary Review Board.

(23) The operation by a municipality of a municipal utility or the operation of a municipal power agency or municipal natural gas agency when the discussion involves: (i) trade secrets or commercial or financial information obtained from a person or business where the trade secrets or commercial or financial information are furnished under a claim that they are proprietary, privileged, or confidential, and that disclosure of the trade secrets or commercial or financial information would cause competitive harm to the person or business; or commercially sensitive information contained in offers to buy or sell made in the competitive markets of a regional transmission organization; and only insofar as the discussion relates directly to such trade secrets or information; (ii) physical or cybersecurity of facilities or materials designated as Critical Energy/Electric Infrastructure Information under federal law or regulation; or (iii) ongoing contract negotiations or results of a request for proposals relating to the purchase, sale, or delivery of electricity or natural gas from nonaffiliate entities; provided however, the municipality, municipal power agency, or municipal natural gas agency shall hold at least one public meeting as to any contract discussed in whole or in part in closed session prior to final action on the contract. (i) contracts relating to the purchase, sale, or delivery of electricity or natural gas or (ii) the results or conclusions of load forecast studies.

(24) Meetings of a residential health care facility resident sexual assault and death review team or the Executive Council under the Abuse Prevention Review Team Act.

(25) Meetings of an independent team of experts under Brian's Law.

(26) Meetings of a mortality review team appointed under the Department of Juvenile Justice Mortality Review Team Act.

(27) (Blank).

(28) Correspondence and records (i) that may not be disclosed under Section 11-9 of the Illinois Public Aid Code or (ii) that pertain to appeals under Section 11-8 of the Illinois Public Aid Code.

(29) Meetings between internal or external auditors and governmental audit committees, finance committees, and their equivalents, when the discussion involves internal control weaknesses, identification of potential fraud risk areas, known or suspected frauds, and fraud interviews conducted in accordance with generally accepted auditing standards of the United States of America.

(30) (Blank).

(31) Meetings and deliberations for decisions of the Concealed Carry Licensing Review Board under the Firearm Concealed Carry Act.

(32) Meetings between the Regional Transportation Authority Board and its Service Boards when the discussion involves review by the Regional Transportation Authority Board of employment contracts under Section 28d of the Metropolitan Transit Authority Act and Sections 3A.18 and 3B.26 of the Regional Transportation Authority Act.

(33) Those meetings or portions of meetings of the advisory committee and peer review subcommittee created under Section 320 of the Illinois Controlled Substances Act during which specific controlled substance prescriber, dispenser, or patient information is discussed.

(34) Meetings of the Tax Increment Financing Reform Task Force under Section 2505-800 of the Department of Revenue Law of the Civil Administrative Code of Illinois.

(35) Meetings of the group established to discuss Medicaid capitation rates under Section 5-30.8 of the Illinois Public Aid Code.

(36) Those deliberations or portions of deliberations for decisions of the Illinois Gaming Board in which there is discussed any of the following: (i) personal, commercial, financial, or other information obtained from any source that is privileged, proprietary, confidential, or a trade secret; or (ii) information specifically exempted from the disclosure by federal or State law.

(37) Deliberations for decisions of the Illinois Law Enforcement Training Standards Board, the Certification Review Panel, and the Illinois State Police Merit Board regarding certification and decertification.

(38) Meetings of the Ad Hoc Statewide Domestic Violence Fatality Review Committee of the Illinois Criminal Justice Information Authority Board that occur in closed executive session under subsection (d) of Section 35 of the Domestic Violence Fatality Review Act.

(39) Meetings of the regional review teams under subsection (a) of Section 75 of the Domestic Violence Fatality Review Act.

(40) Meetings of the Firearm Owner's Identification Card Review Board under Section 10 of the Firearm Owners Identification Card Act.

(d) Definitions. For purposes of this Section:

"Employee" means a person employed by a public body whose relationship with the public body constitutes an employer-employee relationship under the usual common law rules, and who is not an independent contractor.

"Public office" means a position created by or under the Constitution or laws of this State, the occupant of which is charged with the exercise of some portion of the sovereign power of this State. The term "public office" shall include members of the public body, but it shall not include organizational positions filled by members thereof, whether established by law or by a public body itself, that exist to assist the body in the conduct of its business.

"Quasi-adjudicative body" means an administrative body charged by law or ordinance with the responsibility to conduct hearings, receive evidence or testimony and make determinations based thereon, but does not include local electoral boards when such bodies are considering petition challenges.

(e) Final action. No final action may be taken at a closed meeting. Final action shall be preceded by a public recital of the nature of the matter being considered and other information that will inform the public of the business being conducted.

(Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21; 102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff. 7-28-23; 103-626, eff. 1-1-25.)

Section 1-95. The Public Utilities Act is amended by changing Section 8-406 as follows:

(220 ILCS 5/8-406) (from Ch. 111 2/3, par. 8-406)

Sec. 8-406. Certificate of public convenience and necessity.

(a) No public utility not owning any city or village franchise nor engaged in performing any public service or in furnishing any product or commodity within this State as of July 1, 1921 and not possessing a certificate of public convenience and necessity from the Illinois Commerce Commission, the State Public Utilities Commission, or the Public Utilities Commission, at the time Public Act 84-617 goes into effect (January 1, 1986), shall transact any business in this State until it shall have obtained a certificate from the Commission that public convenience and necessity require the transaction of such business. A certificate of public convenience and necessity requiring the transaction of public utility business in any area of this State shall include authorization to the public utility receiving the certificate of public convenience and necessity to construct such plant, equipment, property, or facility as is provided for under the terms and conditions of its tariff and as is necessary to provide utility service and carry out the transaction of public utility business by the public utility in the designated area.

(b) No public utility shall begin the construction of any new plant, equipment, property, or facility which is not in substitution of any existing plant, equipment, property, or facility, or any extension or alteration thereof or in addition thereto, unless and until it shall have obtained from the Commission a certificate that public convenience and necessity require such construction. Whenever after a hearing the Commission determines that any new construction or the transaction of any business by a public utility will promote the public convenience and is necessary thereto, it shall have the power to issue certificates of public convenience and necessity. The Commission shall determine that proposed construction will promote the public convenience and necessity only if the utility demonstrates: (1) that the proposed construction is necessary to provide adequate, reliable, and efficient service to its customers and is the least-cost means of satisfying the service needs of its customers or that the proposed construction will promote the development of an effectively competitive electricity market that operates efficiently, is equitable to all customers, and is the least cost means of satisfying those objectives; (2) that the utility is capable of efficiently managing and supervising the construction process and has taken sufficient action to ensure adequate and efficient construction and supervision thereof; and (3) that the utility is capable of financing the proposed construction without significant adverse financial consequences for the utility or its customers.

(b-5) As used in this subsection (b-5):

"Qualifying direct current applicant" means an entity that seeks to provide direct current bulk transmission service for the purpose of transporting electric energy in interstate commerce.

"Qualifying direct current project" means a high voltage direct current electric service line that crosses at least one Illinois border, the Illinois portion of which is physically located within the region of the Midcontinent Independent System Operator, Inc., or its successor organization, and runs through the counties of Pike, Scott, Greene, Macoupin, Montgomery, Christian, Shelby, Cumberland, and Clark, is capable of transmitting electricity at voltages of 345 kilovolts or above, and may also include associated interconnected alternating current interconnection facilities in this State that are part of the proposed project and reasonably necessary to connect the project with other portions of the grid.

Notwithstanding any other provision of this Act, a qualifying direct current applicant that does not own, control, operate, or manage, within this State, any plant, equipment, or property used or to be used for the transmission of electricity at the time of its application or of the Commission's order may file an application on or before December 31, 2023 with the Commission pursuant to this Section or Section 8-406.1 for, and the Commission may grant, a certificate of public convenience and necessity to construct, operate, and maintain a qualifying direct current project. The qualifying direct current applicant may also include in the application requests for authority under Section 8-503. The Commission shall grant the application for a certificate of public convenience and necessity and requests for authority under Section 8-503 if it finds that the qualifying direct current applicant and the proposed qualifying direct current project satisfy the requirements of this subsection and otherwise satisfy the criteria of this Section or Section 8-406.1 and the criteria of Section 8-503, as applicable to the application and to the extent such criteria are not superseded by the provisions of this subsection. The Commission's order on the application for the certificate of public convenience and necessity shall also include the Commission's findings and determinations on the request or requests for authority pursuant to Section 8-503. Prior to filing its application under either this Section or Section 8-406.1, the qualifying direct current applicant shall conduct 3 public meetings in accordance with subsection (h) of this Section. If the qualifying direct current applicant demonstrates in its application that the proposed qualifying direct current project is designed to deliver electricity to a point or points on the electric transmission grid in either or both the PJM Interconnection, LLC or the Midcontinent Independent System Operator, Inc., or their respective successor organizations, the proposed qualifying direct current project shall be deemed to be, and the Commission shall find it to be, for public use. If the qualifying direct current applicant further demonstrates in its application that the proposed transmission project has a capacity of 1,000 megawatts or larger and a voltage level of 345 kilovolts or greater, the proposed transmission project shall be deemed to satisfy, and the Commission shall find that it satisfies, the criteria stated in item (1) of subsection (b) of this Section or in paragraph (1) of subsection (f) of Section 8-406.1, as applicable to the application, without the taking of additional evidence on these criteria. Prior to the transfer of functional control of any transmission assets to a regional transmission organization, a qualifying direct current applicant shall request Commission approval to join a regional transmission organization in an application filed pursuant to this subsection (b-5) or separately pursuant to Section 7-102 of this Act. The Commission may grant permission to a qualifying direct current applicant to join a regional transmission organization if it finds that the membership, and associated transfer of functional control of transmission assets, benefits Illinois customers in light of the attendant costs and is otherwise in the public interest. Nothing in this subsection (b-5) requires a qualifying direct current applicant to join a regional transmission organization. Nothing in this subsection (b-5) requires the owner or operator of a high voltage direct current transmission line that is not a qualifying direct current project to obtain a certificate of public convenience and necessity to the extent it is not otherwise required by this Section 8-406 or any other provision of this Act.

(c) As used in this subsection (c):

"Decommissioning" has the meaning given to that term in subsection (a) of Section 8-508.1.

"Nuclear power reactor" has the meaning given to that term in Section 8 of the Nuclear Safety Law of 2004.

After the effective date of this amendatory Act of the 103rd General Assembly, no construction shall commence on any new nuclear power reactor with a nameplate capacity of more than 300 megawatts of electricity to be located within this State, and no certificate of public convenience and necessity or other authorization shall be issued therefor by the Commission, until the Illinois Emergency Management Agency and Office of Homeland Security, in consultation with the Illinois Environmental Protection Agency and the Illinois Department of Natural Resources, finds that the United States Government, through its authorized agency, has identified and approved a demonstrable technology or means for the disposal of high level nuclear waste, or until such construction has been specifically approved by a statute enacted by the General Assembly. Beginning January 1, 2026, construction may commence on a new nuclear power reactor with a nameplate capacity of 300 megawatts of electricity or less within this State if the entity constructing the new nuclear power reactor has obtained all permits, licenses, permissions, or approvals governing the construction, operation, and funding of decommissioning of such nuclear power reactors required by: (1) this Act; (2) any rules adopted by the Illinois Emergency Management Agency and Office of Homeland Security under the authority of this Act; (3) any applicable federal statutes, including, but not limited to, the Atomic Energy Act of 1954, the Energy Reorganization Act of 1974, the Low-Level Radioactive Waste Policy Amendments Act of 1985, and the Energy Policy Act of 1992; (4) any regulations promulgated or enforced by the U.S. Nuclear Regulatory Commission, including, but not limited to, those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of the Code of Federal Regulations, as from time to time amended; and (5) any other federal or State statute, rule, or regulation governing the permitting, licensing, operation, or decommissioning of such nuclear power reactors. None of the rules developed by the Illinois Emergency Management Agency and Office of Homeland Security or any other State agency, board, or commission pursuant to this Act shall be construed to supersede the authority of the U.S. Nuclear Regulatory Commission. The changes made by this amendatory Act of the 103rd General Assembly shall not apply to the uprate, renewal, or subsequent renewal of any license for an existing nuclear power reactor that began operation prior to the effective date of this amendatory Act of the 103rd General Assembly.

None of the changes made in this amendatory Act of the 103rd General Assembly are intended to authorize the construction of nuclear power plants powered by nuclear power reactors that are not either: (1) small modular nuclear reactors; or (2) nuclear power reactors licensed by the U.S. Nuclear Regulatory Commission to operate in this State prior to the effective date of this amendatory Act of the 103rd General Assembly.

(d) In making its determination under subsection (b) of this Section, the Commission shall attach primary weight to the cost or cost savings to the customers of the utility. The Commission may consider any or all factors which will or may affect such cost or cost savings, including the public utility's engineering judgment regarding the materials used for construction.

(e) The Commission may issue a temporary certificate which shall remain in force not to exceed one year in cases of emergency, to assure maintenance of adequate service or to serve particular customers, without notice or hearing, pending the determination of an application for a certificate, and may by regulation exempt from the requirements of this Section temporary acts or operations for which the issuance of a certificate will not be required in the public interest.

A public utility shall not be required to obtain but may apply for and obtain a certificate of public convenience and necessity pursuant to this Section with respect to any matter as to which it has received the authorization or order of the Commission under the Electric Supplier Act, and any such authorization or order granted a public utility by the Commission under that Act shall as between public utilities be deemed to be, and shall have except as provided in that Act the same force and effect as, a certificate of public convenience and necessity issued pursuant to this Section.

No electric cooperative shall be made or shall become a party to or shall be entitled to be heard or to otherwise appear or participate in any proceeding initiated under this Section for authorization of power plant construction and as to matters as to which a remedy is available under the Electric Supplier Act.

(f) Such certificates may be altered or modified by the Commission, upon its own motion or upon application by the person or corporation affected. Unless exercised within a period of 2 years from the grant thereof, authority conferred by a certificate of convenience and necessity issued by the Commission shall be null and void.

No certificate of public convenience and necessity shall be construed as granting a monopoly or an exclusive privilege, immunity or franchise.

(g) A public utility that undertakes any of the actions described in items (1) through (3) of this subsection (g) or that has obtained approval pursuant to Section 8-406.1 of this Act shall not be required to comply with the requirements of this Section to the extent such requirements otherwise would apply. For purposes of this Section and Section 8-406.1 of this Act, "high voltage electric service line" means an electric line having a design voltage of 69,000 100,000 or more. For purposes of this subsection (g), a public utility may do any of the following:

(1) replace or upgrade any existing high voltage electric service line and related facilities, notwithstanding its length or, subject to applicable Article VII requirements, ownership;

(2) relocate any existing high voltage electric service line and related facilities, notwithstanding its length, to accommodate construction or expansion of a roadway or other transportation infrastructure; or

(3) construct a high voltage electric service line and related facilities that is constructed solely to serve a single customer's premises or to provide a generator interconnection to the public utility's transmission system and that will (i) pass under or over the premises owned by the customer or generator to be served; (ii) pass or under or over premises for which the customer or generator has secured the necessary right of way right-of-way; or (iii) be multi-circuited with the facilities of the public utility.

(h) A public utility seeking to construct a high-voltage electric service line and related facilities (Project) must show that the utility has held a minimum of 2 pre-filing public meetings to receive public comment concerning the Project in each county where the Project is to be located, no earlier than 6 months prior to filing an application for a certificate of public convenience and necessity from the Commission. Notice of the public meeting shall be published in a newspaper of general circulation within the affected county once a week for 3 consecutive weeks, beginning no earlier than one month prior to the first public meeting. If the Project traverses 2 contiguous counties and where in one county the transmission line mileage and number of landowners over whose property the proposed route traverses is one-fifth or less of the transmission line mileage and number of such landowners of the other county, then the utility may combine the 2 pre-filing meetings in the county with the greater transmission line mileage and affected landowners. All other requirements regarding pre-filing meetings shall apply in both counties. Notice of the public meeting, including a description of the Project, must be provided in writing to the clerk of each county where the Project is to be located. A representative of the Commission shall be invited to each pre-filing public meeting.

(h-5) A public utility seeking to construct a high-voltage electric service line and related facilities must also show that the Project has complied with training and competence requirements under subsection (b) of Section 15 of the Electric Transmission Systems Construction Standards Act.

(i) For applications filed after August 18, 2015 (the effective date of Public Act 99-399), the Commission shall, by certified mail, notify each owner of record of land, as identified in the records of the relevant county tax assessor, included in the right-of-way over which the utility seeks in its application to construct a high-voltage electric line of the time and place scheduled for the initial hearing on the public utility's application. The utility shall reimburse the Commission for the cost of the postage and supplies incurred for mailing the notice.

(j) In determining whether to issue a certificate of public convenience for a new electric generation facility to a municipal power agency that is required to obtain such a certificate to exercise its power of eminent domain pursuant to Section 11-119.1-10 of the Illinois Municipal Code, the Commission shall give due consideration to whether a generation unit of similar size and type is part of the municipal power agency's preferred portfolio or least-cost plan for achieving renewable energy goals in its most recent integrated resource plan, as described in subsection (d) of Section 1-15 of the Municipal and Cooperative Electric Utility Transparent Planning Act.

(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21; 102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff. 6-1-24; 103-1066, eff. 2-20-25.)

Section 1-100. The General Not For Profit Corporation Act of 1986 is amended by adding Section 108.22 as follows:

(805 ILCS 105/108.22 new)

Sec. 108.22. Distribution electric cooperatives.

(a) A distribution electric cooperative, as that term is used in the Electric Supplier Act, shall maintain a publicly accessible website and shall post the following documents and information on its website:

(1) The current bylaws.

(2) A schedule of all regular meetings, posted annually and updated as necessary.

(3) Planned agendas for all regular and special board meetings.

(4) Minutes of the regular session of each board meeting, posted within 30 days of their approval.

(5) A description of the director election process, including:

(A) eligibility requirements for director candidates;

(B) nomination procedures;

(C) voting methods and member instructions; and

(D) election timelines and deadlines.

(b) A distribution electric cooperative may include in its bylaws procedures for accepting votes cast by mail or through secure online voting platforms.

(c) Each distribution electric cooperative shall adopt bylaws or written policies establishing a process that allows members to address the board of directors on matters relevant to the governance and operation of the cooperative.

ARTICLE 5.

Section 5-1. Short title. This Article may be cited as the Utility Data Access Act. References in this Article to "this Act" mean this Article.

Section 5-5. Findings.

(a) The General Assembly finds and declares that optimizing energy use through whole-building utility data access is in the public interest because it provides consumers, building owners, utilities, and states with significant economic benefits.

(b) The General Assembly further finds the following:

(1) implementing building energy use data access legislation catalyzes the development of a strong market for building energy services which will positively impact the State's economy through significant job growth;

(2) improving the energy use efficiency of the existing building stock is a key strategy to help preserve the affordability of rental housing;

(3) energy use reductions stemming from data access can result in direct cost savings to customers and in peak load reductions that benefit all ratepayers;

(4) data access programs allow utilities to maximize the value of their energy use efficiency portfolio by engaging customers and directing them to energy efficiency programs and by enabling utilities to target low-performing buildings;

(5) implementing building data access enables building owners in the State to qualify for certain federal and other incentives to help them improve their assets;

(6) energy use data access is the foundation of a successful efficiency strategy and enables building owners to track energy use performance over time, set performance goals, and justify cost-effective energy use upgrades; and

(7) absent whole-building energy use data access legislation, building owners lack an efficient, defined process to obtain energy performance of their buildings in a manner that protects consumer confidentiality.

Section 5-10. Definitions. As used in this Act:

"Account holder" or "customer" means the person or entity authorized to access or modify utility account details.

"Aggregated usage data" means an aggregation of covered usage data, where all data associated with a qualified building or qualified property, including, but not limited to, data from tenant meters and from owner meters, are combined into one collective data point per utility data type, per time period, and where any unique identifiers or other personal information are removed or dissociated from individual meter data.

"Aggregation threshold" means 3 or more unique nonresidential qualified accounts or any combination of 5 or more residential and nonresidential unique qualified accounts of a property or building during the period for which data is requested.

"Benchmarking tool" means the ENERGY STAR Portfolio Manager web-based tool or any prudent and cost-effective alternative system or tool approved by the Commission should ENERGY STAR Portfolio Manager become inoperative or no longer useful to achieving the policy goals of the State of Illinois that (i) enables the periodic entry of a building's energy use data and other descriptive information about a building and (ii) rates a building's energy efficiency against that of comparable buildings nationwide.

"Commission" means the Illinois Commerce Commission.

"Covered usage data" means electric data collected from one or more utility meters that reflects the quantity and period of utility usage in the building, property, or portion thereof.

"Data recipient" means:

(1) an owner of the property or building;

(2) an owner of a portion of a property with regard to covered usage data only for the utility consumption the owner or the owner's tenants, if any, pay for and consume in the owned portion;

(3) a tenant with regard to covered usage data only for the utility consumption the tenant or the tenant's subtenants, if any, pay for and consume in the space leased by the tenant;

(4) the board, in the case of a condominium or cooperative ownership of the property or building; or

(5) an agent authorized to receive the covered usage data by anyone in paragraphs (1) through (4).

"Property" means:

(1) a single tax parcel;

(2) 2 or more tax parcels held in the cooperative or condominium form of ownership and governed by a single board of managers; or

(3) 2 or more colocated tax parcels owned or controlled by the same entity.

"Qualified account" means a utility account that serves some or all of a building or property for which covered usage data is requested and that, as affirmed by the data recipient, was not controlled by the data recipient or its subsidiary during the time period for which covered usage data is requested.

"Qualified building" means a building that meets the aggregation threshold.

"Qualified data recipient" means a data recipient with respect to a qualified property or qualified building.

"Qualified property" means a property that meets the aggregation threshold.

"Qualified utility" means an electric utility that serves at least 500,000 customers in the State.

"Utility" means an entity that is an electric utility with over 500,000 customers in this State and that is a public utility, as defined in Section 3-105 of the Public Utilities Act.

"Utility data type" means electric.

Section 5-15. Utility data access.

(a) Within 90 days after the effective date of this Act, the Commission shall open a proceeding to establish by rule, consistent with the Illinois Administrative Procedure Act and the requirements of subsection (c), procedures to implement the requirements of this Section. The Commission shall consider industry best practices along with Illinois law, rules, and Commission orders in developing the implementing rules. The governing authority of a public utility district, municipally owned utility, or cooperative utility may adopt a rule adopted by the Commission.

(b) No later than 2 years after the effective date of this Act, the Commission shall adopt procedures through the rulemaking proceeding identified in subsection (a) whereby:

(1) a utility shall retain all consumption data for a period of not less than 2 years;

(2) a qualified utility shall retain usage data in the possession of the utility on the effective date of this Act or that is subsequently generated by the utility, for a period 5 years or however long the utility retains usage data in its active billing system, whichever is longer;

(3) a utility shall honor an account holder's authorized request to transmit the account holder's covered usage data held by the utility to any entity designated by the account holder;

(4) a qualified data recipient with respect to a qualified building or qualified property may request that a qualified utility provide aggregated usage data for the qualified building or qualified property. Aggregated usage data shall include identifiers of all meters associated with the aggregate data and any other information needed for data quality assurance;

(5) a utility shall establish a tool or process to enable qualified data recipients to request data under this subsection. The tool or process shall meet specifications established by the Commission;

(6) the account holder request process and utility delivery of requested data shall be convenient, secure, and at the Commission's direction requests to the utility may be submitted exclusively through an online portal; and

(7) a utility shall provide updates or corrections to any previously provided usage information on the schedule established in paragraph (5) of subsection (d). Data recipients may request and receive timely revisions correcting any previously provided usage information. A utility shall also provide usage information on the schedule established in paragraph (5) of subsection (d).

(c) Any covered usage data that a utility provides to a data recipient under this Section must meet the following requirements:

(1) The covered usage data must be available to be requested online except that a nonqualified utility may provide only paper request forms upon showing of good cause. A utility's validation of the requester's identity shall be consistent with, and no more onerous than, the utility's then-current practices.

(2) The covered usage data must be provided to the data recipient in a timeframe, frequency, and format and be delivered by a method as may be determined by the Commission.

(d) Any covered usage data that a qualified utility provides to a data recipient under this Section must:

(1) be provided to the data recipient within 30 days after receiving the data recipient's valid request if the request is received after the effective date of the rulemaking identified in subsection (a) of this Section;

(2) for any initial upload of data to a data recipient and subject to subsection (j) of this Section, a data recipient must include all the data for the time period required in paragraph (2) of subsection (b), regardless of whether the data recipient had a business relationship with the building or property during that period;

(3) include all necessary data and available usage data points for data recipients to comply with reporting requirements to which they are subject, including any such usage data that the utility possesses;

(4) be directly uploaded to the benchmarking tool account, or delivered in another format approved by the Commission, depending on utility size under subsection (e);

(5) be provided to the data recipient according to a schedule set by the Commission, but no less than monthly;

(6) be provided until the data recipient revokes the request for usage data or is no longer a data recipient or is no longer a qualified data recipient with respect to aggregated usage data;

(7) be accompanied by a list of all meters associated with the covered usage data, including, but not limited to, aggregated usage data, and shall be accompanied by any other information the Commission deems necessary including for data quality assurance; and

(8) be provided at no cost to the data recipient.

(e) The Commission shall direct that covered usage data shall be delivered to the data recipient in a standard format consistent with the benchmarking tool at the data recipient's request. The Commission shall direct electric utilities that serve at least 500,000 customers in the State to provide requested data by direct upload to the benchmarking tool and associate the data with the data recipient's benchmarking tool account.

(f) To ensure the validity and usefulness of covered usage data, the utility shall provide the best available consumption and other information, consistent with the utility's records as presented to account holders on the utility's customer portal and captured at the meter level.

(g) Once covered usage data has been made available to a duly authorized data recipient, such data may not be deleted or altered by a utility system, except as is necessary to correct errors or reflect rebills or is affected as part of the utility's billing data retention policy. If previously provided covered usage data is changed to correct errors, notification must be provided to the data recipient.

(h) Within 180 days after the effective date of this Act, the Commission shall adopt a standard form for a utility account holder to authorize the sharing of the utility account holder's covered usage data.

(i) For properties that do not meet the aggregation threshold and therefore require account holder authorization, the utility shall provide covered usage data to data recipients upon account holder authorization, which:

(1) may be provided in Commission-approved form;

(2) may be provided in a lease agreement provision; and

(3) remains valid until the account holder revokes it, regardless of how the authorization is provided.

(j) Access to covered usage data under this Section shall be subject to any rules the Commission has adopted or may choose to adopt, if the rules do not conflict with this Section.

(k) Except in cases where the utility has not followed processes established by this Act or the utility is grossly negligent, the utility shall be held harmless for third-party misuse of data shared under this Act and no cause of action may be initiated against the utility for such subsequent misuse.

(l) A qualified utility may file for cost recovery of the reasonable and prudently incurred costs of providing covered usage data, including establishing, operating, and maintaining data aggregation and data access services, for the Commission to evaluate. A qualified utility shall make good faith efforts to secure federal, State, or other relevant funding for such investments in the future. Any such funding the qualified utility receives shall be deducted from future revenue requirements.

(m) The Commission may hire consultants and experts to execute their responsibilities under this Act, with the retention of those consultants and experts exempt from the requirements of Section 20-10 of the Illinois Procurement Code.

ARTICLE 90.

Section 90-5. The Department of Commerce and Economic Opportunity Law of the Civil Administrative Code of Illinois is amended by changing Section 605-1075 as follows:

(20 ILCS 605/605-1075)

Sec. 605-1075. Energy Transition Assistance Fund.

(a) The General Assembly hereby declares that management of several economic development programs requires a consolidated funding source to improve resource efficiency. The General Assembly specifically recognizes that properly serving communities and workers impacted by the energy transition requires that the Department of Commerce and Economic Opportunity have access to the resources required for the execution of the programs for workforce and contractor development, just transition investments and community support, and the implementation and administration of energy and justice efforts by the State.

(b) The Department shall be responsible for the administration of the Energy Transition Assistance Fund and shall allocate funding on the basis of priorities established in this Section. Each year, the Department shall determine the available amount of resources in the Fund that can be allocated to the programs identified in this Section, and allocate the funding accordingly. The Department shall, to the extent practical, consider both the short-term and long-term costs of the programs and allocate funding so that the Department is able to cover both the short-term and long-term costs of these programs using projected revenue.

The available funding for each year shall be allocated from the Fund in the following order of priority:

(1) for costs related to the Clean Jobs Workforce Network Program, up to $21,000,000 annually prior to June 1, 2023; and $24,333,333 annually from June 1, 2023 to May 30, 2026; and $26,020,736 annually thereafter;

(2) for costs related to the Clean Energy Contractor Incubator Program, up to $21,000,000 annually prior to June 1, 2026 and up to $22,687,403 thereafter;

(3) for costs related to the Clean Energy Primes Contractor Accelerator Program, up to $9,000,000 annually;

(4) for costs related to the Barrier Reduction Program, up to $21,000,000 annually prior to June 1, 2026 and up to $22,143,079 annually thereafter;

(5) for costs related to the Jobs and Environmental Justice Grant Program, up to $34,000,000 annually;

(6) for costs related to the Returning Residents Clean Jobs Training Program, up to $6,000,000 annually;

(7) for costs related to Energy Transition Navigators, up to $6,000,000 annually;

(8) for costs related to the Illinois Climate Works Preapprenticeship Program, up to $10,000,000 annually;

(9) for costs related to Energy Transition Community Support Grants, up to $40,000,000 annually;

(10) for costs related to the Displaced Energy Worker Dependent Scholarship, upon request by the Illinois Student Assistance Commission, up to $1,100,000 annually;

(11) up to $10,000,000 annually shall be transferred to the Public Utilities Fund for use by the Illinois Commerce Commission for costs of administering the changes made to the Public Utilities Act by this amendatory Act of the 102nd General Assembly;

(12) up to $4,000,000 annually shall be transferred to the Illinois Power Agency Operations Fund for use by the Illinois Power Agency; and

(13) for costs related to the Clean Energy Jobs and Justice Fund, up to $1,000,000 annually.

The Department is authorized to utilize up to 10% of the Energy Transition Assistance Fund for administrative and operational expenses to implement the requirements of this Act.

(b-5) Beginning January 1, 2028, the Department shall transfer up to $84,800,000 annually to the Electric Vehicle and Charging Fund for costs related to beneficial electrification programs, as defined in Section 45 of the Electric Vehicle Act. The Environmental Protection Agency may utilize up to 3% of the annual allocation under this subsection (b-5) for administrative and operational expenses.

(c) Within 30 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric utility serving more than 500,000 customers in the State shall report to the Department its total kilowatt-hours of energy delivered during the 12 months ending on the immediately preceding May 31. By October 31, 2021 and each October 31 thereafter, each electric utility serving more than 500,000 customers in the State shall report to the Department its total kilowatt-hours of energy delivered during the 12 months ending on the immediately preceding May 31.

(d) The Department shall, within 60 days after the effective date of this amendatory Act of the 102nd General Assembly:

(1) determine the amount necessary, but not more than $180,000,000, to meet the funding needs of the programs reliant upon the Energy Transition Assistance Fund as a revenue source for the period between the effective date of this amendatory Act of the 102nd General Assembly and December 31, 2021;

(2) determine, based on the kilowatt-hour deliveries for the 12 months ending May 31, 2021 reported by the electric utilities under subsection (c), the total energy transition assistance charge to be allocated to each electric utility for the period between the effective date of this amendatory Act of the 102nd General Assembly and December 31, 2021; and

(3) report the total energy transition assistance charge applicable until December 31, 2021 to each electric utility serving more than 500,000 customers in the State and the Illinois Commerce Commission for purposes of filing the tariff pursuant to Section 16-108.30 of the Public Utilities Act.

(e) The Department shall by November 30, 2021, and each November 30 thereafter:

(1) determine the amount necessary, but not more than $180,000,000 plus the amount needed to fund the programs described in subsection (b-5), to meet the funding needs of the programs reliant upon the Energy Transition Assistance Fund as a revenue source for the immediately following calendar year;

(2) determine, based on the kilowatt-hour deliveries for the 12 months ending on the immediately preceding May 31 reported to it by the electric utilities under subsection (c), the total energy transition assistance charge to be allocated to each electric utility for the immediately following calendar year; and

(3) report the energy transition assistance charge applicable for the immediately following calendar year to each electric utility serving more than 500,000 customers in the State and the Illinois Commerce Commission for purposes of filing the tariff pursuant to Section 16-108.30 of the Public Utilities Act.

(f) The energy transition assistance charge may not exceed $180,000,000 plus the amount needed to fund the programs described in subsection (b-5) annually. If, at the end of the calendar year, any surplus remains in the Energy Transition Assistance Fund, the Department may allocate the surplus from the fund in the following order of priority:

(1) for costs related to the development of the Stretch Energy Codes and other standards at the Capital Development Board, up to $500,000 annually, at the request of the Board;

(2) up to $7,000,000 annually shall be transferred to the Energy Efficiency Trust Fund and Clean Air Act Permit Fund for use by the Environmental Protection Agency for costs related to energy efficiency and weatherization, and costs of implementation, administration, and enforcement of the Clean Air Act; and

(3) for costs related to State fleet electrification at the Department of Central Management Services, up to $10,000,000 annually, at the request of the Department.

(Source: P.A. 102-662, eff. 9-15-21.)

Section 90-6. The Electric Vehicle Act is amended by changing Section 45 as follows:

(20 ILCS 627/45)

Sec. 45. Beneficial electrification.

(a) It is the intent of the General Assembly to decrease reliance on fossil fuels, reduce pollution from the transportation sector, increase access to electrification for all consumers, and ensure that electric vehicle adoption and increased electricity usage and demand do not place significant additional burdens on the electric system and create benefits for Illinois residents.

(1) Illinois should increase the adoption of electric vehicles in the State to 1,000,000 by 2030.

(2) Illinois should strive to be the best state in the nation in which to drive and manufacture electric vehicles.

(3) Widespread adoption of electric vehicles is necessary to electrify the transportation sector, diversify the transportation fuel mix, drive economic development, and protect air quality.

(4) Accelerating the adoption of electric vehicles will drive the decarbonization of Illinois' transportation sector.

(5) Expanded infrastructure investment will help Illinois more rapidly decarbonize the transportation sector.

(6) Statewide adoption of electric vehicles requires increasing access to electrification for all consumers.

(7) Widespread adoption of electric vehicles requires increasing public access to charging equipment throughout Illinois, especially in low-income and environmental justice communities, where levels of air pollution burden tend to be higher.

(8) Widespread adoption of electric vehicles and charging equipment has the potential to provide customers with fuel cost savings and electric utility customers with cost-saving benefits.

(9) Widespread adoption of electric vehicles can improve an electric utility's electric system efficiency and operational flexibility, including the ability of the electric utility to integrate renewable energy resources and make use of off-peak generation resources that support the operation of charging equipment.

(10) Widespread adoption of electric vehicles should stimulate innovation, competition, and increased choices in charging equipment and networks and should also attract private capital investments and create high-quality jobs in Illinois.

(b) As used in this Section:

"Agency" means the Environmental Protection Agency.

"Beneficial electrification programs" means programs that lower carbon dioxide emissions, replace fossil fuel use, create cost savings, improve electric grid operations, reduce increases to peak demand, improve electric usage load shape, and align electric usage with times of renewable generation. All beneficial electrification programs shall provide for incentives such that customers are induced to use electricity at times of low overall system usage or at times when generation from renewable energy sources is high. "Beneficial electrification programs" include a portfolio of the following:

(1) time-of-use electric rates;

(2) hourly pricing electric rates;

(3) optimized charging programs or programs that encourage charging at times beneficial to the electric grid;

(4) optional demand-response programs specifically related to electrification efforts;

(5) incentives for electrification and associated infrastructure tied to using electricity at off-peak times;

(6) incentives for electrification and associated infrastructure targeted to medium-duty and heavy-duty vehicles used by transit agencies;

(7) incentives for electrification and associated infrastructure targeted to school buses;

(8) incentives for electrification and associated infrastructure for medium-duty and heavy-duty government and private fleet vehicles;

(9) low-income programs that provide access to electric vehicles for communities where car ownership or new car ownership is not common;

(10) incentives for electrification in eligible communities;

(11) incentives or programs to enable quicker adoption of electric vehicles by developing public charging stations in dense areas, workplaces, and low-income communities;

(12) incentives or programs to develop electric vehicle infrastructure that minimizes range anxiety, filling the gaps in deployment, particularly in rural areas and along highway corridors;

(13) incentives to encourage the development of electrification and renewable energy generation in close proximity in order to reduce grid congestion;

(14) offer support to low-income communities who are experiencing financial and accessibility barriers such that electric vehicle ownership is not an option; and

(15) other such programs as defined by the Commission.

"Black, indigenous, and people of color" or "BIPOC" means people who are members of the groups described in subparagraphs (a) through (e) of paragraph (A) of subsection (1) of Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act.

"Commission" means the Illinois Commerce Commission.

"Coordinator" means the Electric Vehicle Coordinator.

"Electric vehicle" means a vehicle that is exclusively powered by and refueled by electricity, must be plugged in to charge, and is licensed to drive on public roadways. "Electric vehicle" does not include electric mopeds, electric off-highway vehicles, or hybrid electric vehicles and extended-range electric vehicles that are also equipped with conventional fueled propulsion or auxiliary engines.

"Electric vehicle charging station" means a station that delivers electricity from a source outside an electric vehicle into one or more electric vehicles.

"Environmental justice communities" means the definition of that term based on existing methodologies and findings, used and as may be updated by the Illinois Power Agency and its program administrator in the Illinois Solar for All Program.

"Equity investment eligible community" or "eligible community" means the geographic areas throughout Illinois which would most benefit from equitable investments by the State designed to combat discrimination and foster sustainable economic growth. Specifically, "eligible community" means the following areas:

(1) areas where residents have been historically excluded from economic opportunities, including opportunities in the energy sector, as defined pursuant to Section 10-40 of the Cannabis Regulation and Tax Act; and

(2) areas where residents have been historically subject to disproportionate burdens of pollution, including pollution from the energy sector, as established by environmental justice communities as defined by the Illinois Power Agency pursuant to Illinois Power Agency Act, excluding any racial or ethnic indicators.

"Equity investment eligible person" or "eligible person" means the persons who would most benefit from equitable investments by the State designed to combat discrimination and foster sustainable economic growth. Specifically, "eligible person" means the following people:

(1) persons whose primary residence is in an equity investment eligible community;

(2) persons who are graduates of or currently enrolled in the foster care system; or

(3) persons who were formerly incarcerated.

"Low-income" means persons and families whose income does not exceed 80% of the state median income for the current State fiscal year as established by the U.S. Department of Health and Human Services.

"Make-ready infrastructure" means the electrical and construction work necessary between the distribution circuit to the connection point of charging equipment.

"Optimized charging programs" mean programs whereby owners of electric vehicles can set their vehicles to be charged based on the electric system's current demand, retail or wholesale market rates, incentives, the carbon or other pollution intensity of the electric generation mix, the provision of grid services, efficient use of the electric grid, or the availability of clean energy generation. Optimized charging programs may be operated by utilities as well as third parties.

(c) The Commission shall initiate a workshop process no later than November 30, 2021 for the purpose of soliciting input on the design of beneficial electrification programs that the utility shall offer. The workshop shall be coordinated by the Staff of the Commission, or a facilitator retained by Staff, and shall be organized and facilitated in a manner that encourages representation from diverse stakeholders, including stakeholders representing environmental justice and low-income communities, and ensures equitable opportunities for participation, without requiring formal intervention or representation by an attorney.

The stakeholder workshop process shall take into consideration the benefits of electric vehicle adoption and barriers to adoption, including:

(1) the benefit of lower bills for customers who do not charge electric vehicles;

(2) benefits to the distribution system from electric vehicle usage;

(3) the avoidance and reduction in capacity costs from optimized charging and off-peak charging;

(4) energy price and cost reductions;

(5) environmental benefits, including greenhouse gas emission and other pollution reductions;

(6) current barriers to mass-market adoption, including cost of ownership and availability of charging stations;

(7) current barriers to increasing access among populations that have limited access to electric vehicle ownership, communities significantly impacted by transportation-related pollution, and market segments that create disproportionate pollution impacts;

(8) benefits of and incentives for medium-duty and heavy-duty fleet vehicle electrification;

(9) opportunities for eligible communities to benefit from electrification;

(10) geographic areas and market segments that should be prioritized for electrification infrastructure investment.

The workshops shall consider barriers, incentives, enabling rate structures, and other opportunities for the bill reduction and environmental benefits described in this subsection.

The workshop process shall conclude no later than February 28, 2022. Following the workshop, the Staff of the Commission, or the facilitator retained by the Staff, shall prepare and submit a report, no later than March 31, 2022, to the Commission that includes, but is not limited to, recommendations for transportation electrification investment or incentives in the following areas:

(i) publicly accessible Level 2 and fast-charging stations, with a focus on bringing access to transportation electrification in densely populated areas and workplaces within eligible communities;

(ii) medium-duty and heavy-duty charging infrastructure used by government and private fleet vehicles that serve or travel through environmental justice or eligible communities;

(iii) medium-duty and heavy-duty charging infrastructure used in school bus operations, whether private or public, that primarily serve governmental or educational institutions, and also serve or travel through environmental justice or eligible communities;

(iv) public transit medium-duty and heavy-duty charging infrastructure, developed in consultation with public transportation agencies; and

(v) publicly accessible Level 2 and fast-charging stations targeted to fill gaps in deployment, particularly in rural areas and along State highway corridors.

The report must also identify the participants in the process, program designs proposed during the process, estimates of the costs and benefits of proposed programs, any material issues that remained unresolved at the conclusions of such process, and any recommendations for workshop process improvements. The report shall be used by the Commission to inform and evaluate the cost-effectiveness cost effectiveness and achievement of goals within the submitted Beneficial Electrification Plans.

(d) No later than July 1, 2022, electric utilities serving greater than 500,000 customers in the State shall file a Beneficial Electrification Plan with the Illinois Commerce Commission for programs that start no later than January 1, 2023. The plan shall take into consideration recommendations from the workshop report described in this Section. Within 45 days after the filing of the Beneficial Electrification Plan, the Commission shall, with reasonable notice, open an investigation to consider whether the plan meets the objectives and contains the information required by this Section. The Commission shall determine if the proposed plan is cost-beneficial and in the public interest. When considering if the plan is in the public interest and determining appropriate levels of cost recovery for investments and expenditures related to programs proposed by an electric utility, the Commission shall consider whether the investments and other expenditures are designed and reasonably expected to:

(1) maximize total energy cost savings and rate reductions so that nonparticipants can benefit;

(2) address environmental justice interests by ensuring there are significant opportunities for residents and businesses in eligible communities to directly participate in and benefit from beneficial electrification programs;

(3) support at least a 40% investment of make-ready infrastructure incentives to facilitate the rapid deployment of charging equipment in or serving environmental justice, low-income, and eligible communities; however, nothing in this subsection is intended to require a specific amount of spending in a particular geographic area;

(4) support at least a 5% investment target in electrifying medium-duty and heavy-duty school bus and diesel public transportation vehicles located in or serving environmental justice, low-income, and eligible communities in order to provide those communities and businesses with greater economic investment, transportation opportunities, and a cleaner environment so they can directly benefit from transportation electrification efforts; however, nothing in this subsection is intended to require a specific amount of spending in a particular geographic area;

(5) stimulate innovation, competition, private investment, and increased consumer choices in electric vehicle charging equipment and networks;

(6) contribute to the reduction of carbon emissions and meeting air quality standards, including improving air quality in eligible communities who disproportionately suffer from emissions from the medium-duty and heavy-duty transportation sector;

(7) support the efficient and cost-effective use of the electric grid in a manner that supports electric vehicle charging operations; and

(8) provide resources to support private investment in charging equipment for uses in public and private charging applications, including residential, multi-family, fleet, transit, community, and corridor applications.

The plan shall be determined to be cost-beneficial if the total cost of beneficial electrification expenditures is less than the net present value of increased electricity costs (defined as marginal avoided energy, avoided capacity, and avoided transmission and distribution system costs) avoided by programs under the plan, the net present value of reductions in other customer energy costs, net revenue from all electric charging in the service territory, and the societal value of reduced carbon emissions and surface-level pollutants, particularly in environmental justice communities. The calculation of costs and benefits should be based on net impacts, including the impact on customer rates.

The Commission shall approve, approve with modifications, or reject the plan within 270 days from the date of filing. The Commission may approve the plan if it finds that the plan will achieve the goals described in this Section and contains the information described in this Section. Proceedings under this Section shall proceed according to the rules provided by Article IX of the Public Utilities Act. Information contained in the approved plan shall be considered part of the record in any Commission proceeding under Section 16-107.6 of the Public Utilities Act, provided that a final order has not been entered prior to the initial filing date. The Beneficial Electrification Plan shall specifically address, at a minimum, the following:

(i) make-ready investments to facilitate the rapid deployment of charging equipment throughout the State, facilitate the electrification of public transit and other vehicle fleets in the light-duty, medium-duty, and heavy-duty sectors, and align with Agency-issued rebates for charging equipment;

(ii) the development and implementation of beneficial electrification programs, including time-of-use rates and their benefit for electric vehicle users and for all customers, optimized charging programs to achieve savings identified, and new contracts and compensation for services in those programs, through signals that allow electric vehicle charging to respond to local system conditions, manage critical peak periods, serve as a demand response or peak resource, and maximize renewable energy use and integration into the grid;

(iii) optional commercial tariffs utilizing alternatives to traditional demand-based rate structures to facilitate charging for light-duty, heavy-duty, and fleet electric vehicles;

(iv) financial and other challenges to electric vehicle usage in low-income communities, and strategies for overcoming those challenges, particularly in communities where and for people for whom car ownership is not an option;

(v) methods of minimizing ratepayer impacts and exempting or minimizing, to the extent possible, low-income ratepayers from the costs associated with facilitating the expansion of electric vehicle charging;

(vi) plans to increase access to Level 3 Public Electric Vehicle Charging Infrastructure to serve vehicles that need quicker charging times and vehicles of persons who have no other access to charging infrastructure, regardless of whether those projects participate in optimized charging programs;

(vii) whether to establish charging standards for type of plugs eligible for investment or incentive programs, and if so, what standards;

(viii) opportunities for coordination and cohesion with electric vehicle and electric vehicle charging equipment incentives established by any agency, department, board, or commission of the State, any other unit of government in the State, any national programs, or any unit of the federal government;

(ix) ideas for the development of online tools, applications, and data sharing that provide essential information to those charging electric vehicles, and enable an automated charging response to price signals, emission signals, real-time renewable generation production, and other Commission-approved or customer-desired indicators of beneficial charging times; and

(x) customer education, outreach, and incentive programs that increase awareness of the programs and the benefits of transportation electrification, including direct outreach to eligible communities.

(e) Proceedings under this Section shall proceed according to the rules provided by Article IX of the Public Utilities Act. Information contained in the approved plan shall be considered part of the record in any Commission proceeding under Section 16-107.6 of the Public Utilities Act, provided that a final order has not been entered prior to the initial filing date.

(f) The utility shall file an update to the plan on July 1, 2024 and every 3 years thereafter. This update shall describe transportation investments made during the prior plan period, investments planned for the following 24 months, and updates to the information required by this Section. Beginning with the first update, the The utility shall develop the plan in conjunction with the distribution system planning process described in Section 16-105.17, including incorporation of stakeholder feedback from that process.

(g) Within 35 days after the utility files its report, the Commission shall, upon its own initiative, open an investigation regarding the utility's plan update to investigate whether the objectives described in this Section are being achieved. The Commission shall determine whether investment targets should be increased based on achievement of spending goals outlined in the Beneficial Electrification Plan and consistency with outcomes directed in the plan stakeholder workshop report. If the Commission finds, after notice and hearing, that the utility's plan is materially deficient, the Commission shall issue an order requiring the utility to devise a corrective action plan, subject to Commission approval, to bring the plan into compliance with the goals of this Section. The Commission's order shall be entered within 270 days after the utility files its annual report. The contents of a plan filed under this Section shall be available for evidence in Commission proceedings. However, omission from an approved plan shall not render any future utility expenditure to be considered unreasonable or imprudent. The Commission may, upon sufficient evidence, allow expenditures that were not part of any particular distribution plan. The Commission shall consider revenues from electric vehicles in the utility's service territory in evaluating the retail rate impact. The retail rate impact from the development of electric vehicle infrastructure shall not exceed 1% per year of the total annual revenue requirements of the utility.

(h) In meeting the requirements of this Section, the utility, and beginning January 1, 2029 the Agency, shall demonstrate efforts to increase the use of contractors and electric vehicle charging station installers that meet multiple workforce equity actions, including, but not limited to:

(1) the business is headquartered in or the person resides in an eligible community;

(2) the business is majority owned by eligible person or the contractor is an eligible person;

(3) the business or person is certified by another municipal, State, federal, or other certification for disadvantaged businesses;

(4) the business or person meets the eligibility criteria for a certification program such as:

(A) certified under Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act;

(B) certified by another municipal, State, federal, or other certification for disadvantaged businesses;

(C) submits an affidavit showing that the vendor meets the eligibility criteria for a certification program such as those in items (A) and (B);

(D) if the vendor is a nonprofit, meets any of the criteria in those in item (A), (B), or (C) with the exception that the nonprofit is not required to meet any criteria related to being a for-profit entity, or is controlled by a board of directors that consists of 51% or greater individuals who are equity investment eligible persons; or

(E) ensuring that program implementation contractors and electric vehicle charging station installers pay employees working on electric vehicle charging installations at or above the prevailing wage rate as published by the Department of Labor.

Utilities, and beginning January 1, 2029 the Agency, shall establish reporting procedures for vendors that ensure compliance with this subsection, but are structured to avoid, wherever possible, placing an undue administrative burden on vendors.

(i) Program data collection.

(1) In order to ensure that the benefits provided to Illinois residents and business by the clean energy economy are equitably distributed across the State, it is necessary to accurately measure the applicants and recipients of this Program. The purpose of this paragraph is to require the implementing utilities, and beginning January 1, 2029 the Agency, to collect all data from Program applicants and beneficiaries to track and improve equitable distribution of benefits across Illinois communities. The further purpose is to measure any potential impact of racial discrimination on the distribution of benefits and provide the utilities the information necessary to correct any discrimination through methods consistent with State and federal law.

(2) The implementing utilities, and beginning January 1, 2029 the Agency, shall collect demographic and geographic data for each applicant and each person or business awarded benefits or contracts under this Program.

(3) The implementing utilities, and beginning January 1, 2029 the Agency, shall collect the following information from applicants and Program or procurement beneficiaries where applicable:

(A) demographic information, including racial or ethnic identity for real persons employed, contracted, or subcontracted through the program;

(B) demographic information, including racial or ethnic identity of business owners;

(C) geographic location of the residency of real persons or geographic location of the headquarters for businesses; and

(D) any other information necessary for the purpose of achieving the purpose of this paragraph.

(4) The utility, and beginning January 1, 2029 the Agency, shall publish, at least annually, aggregated information on the demographics of program and procurement applicants and beneficiaries. The utilities shall protect personal and confidential business information as necessary.

(5) The utilities, and beginning January 1, 2029 the Agency, shall conduct a regular review process to confirm the accuracy of reported data.

(6) On a quarterly basis, utilities, and beginning January 1, 2029 the Agency, shall collect data necessary to ensure compliance with this Section and shall communicate progress toward compliance to program implementation contractors and electric vehicle charging station installation vendors.

(7) Utilities filing Beneficial Electrification Plans under this Section, and beginning January 1, 2029 the Agency, shall report annually to the Illinois Commerce Commission and the General Assembly on how hiring, contracting, job training, and other practices related to its Beneficial electrification programs enhance the diversity of vendors working on such programs. These reports must include data on vendor and employee diversity.

(j) The provisions of this Section are severable under Section 1.31 of the Statute on Statutes.

(k) The utilities' Beneficial Electrification Plans under this Section shall end no later than December 31, 2028. Beginning January 1, 2029, the beneficial electrification programs described in this Section shall be administered by the Environmental Protection Agency. The Agency shall have broad authority to provide grants and other forms of financial assistance to develop and implement beneficial electrification programs that achieve the goals described in paragraphs (1) through (8) of subsection (d) of this Section, and that may include, but are not limited to, initiatives as described in items (i) through (x) of subsection (d) of this Section.

(l) No later than March 1, 2028, the Agency shall publish a draft 3-year Beneficial Electrification Plan for the implementation of its beneficial electrification programs and solicit comments and input from interested stakeholders, including through public workshops, on the design of the programs. As part of the Plan development process, the Agency shall strive to meaningfully engage members and representatives of equity investment eligible communities at the outset of Plan development, prior to the publication of the draft Plan, and during the comment and input process. The Plan shall take into consideration lessons learned from the implementation of utility Beneficial Electrification Plans described in this Section. Within 180 days after the publication of its draft Beneficial Electrification Plan, the Agency shall publish a final Plan that is designed and reasonably expected to achieve the goals described in paragraphs (1) through (8) of subsection (d) of this Section.

(m) Funds shall be made available from the Electric Vehicle and Charging Fund to the Agency to provide grants and other forms of financial assistance and administer beneficial electrification programs. Subject to appropriation, the annual budget for Agency-administered beneficial electrification programs shall be equivalent to the average annual budget of programs administered by the utilities under this Section for the years 2026 through 2028.

(Source: P.A. 102-662, eff. 9-15-21; 102-820, eff. 5-13-22; 103-154, eff. 6-30-23.)

Section 90-7. The Energy Transition Act is amended by changing Section 5-40 as follows:

(20 ILCS 730/5-40)

(Section scheduled to be repealed on September 15, 2045)

Sec. 5-40. Illinois Climate Works Preapprenticeship Program.

(a) Subject to appropriation, the Department shall develop, and through Regional Administrators administer, the Illinois Climate Works Preapprenticeship Program. The goal of the Illinois Climate Works Preapprenticeship Program is to create a network of hubs throughout the State that will recruit, prescreen, and provide preapprenticeship skills training, for which participants may attend free of charge and receive a stipend, to create a qualified, diverse pipeline of workers who are prepared for careers in the construction and building trades and clean energy jobs opportunities therein. Upon completion of the Illinois Climate Works Preapprenticeship Program, the candidates will be connected to and prepared to successfully complete an apprenticeship program.

(b) Each Climate Works Hub that receives funding from the Energy Transition Assistance Fund shall provide an annual report to the Illinois Works Review Panel by April 1 of each calendar year. The annual report shall include the following information:

(1) a description of the Climate Works Hub's recruitment, screening, and training efforts, including a description of training related to construction and building trades opportunities in clean energy jobs;

(2) the number of individuals who apply to, participate in, and complete the Climate Works Hub's program, broken down by race, gender, age, and veteran status;

(3) the number of the individuals referenced in paragraph (2) of this subsection who are initially accepted and placed into apprenticeship programs in the construction and building trades; and

(4) the number of individuals referenced in paragraph (2) of this subsection who remain in apprenticeship programs in the construction and building trades or have become journeymen one calendar year after their placement, as referenced in paragraph (3) of this subsection.

(c) Subject to appropriation, the Department shall provide funding to 3 Climate Works Hubs throughout the State, including one to the Illinois Department of Transportation Region 1, one to the Illinois Department of Transportation Regions 2 and 3, and one to the Illinois Department of Transportation Regions 4 and 5. An eligible organization may serve as the designated Climate Works Hub for all 5 regions. Climate Works Hubs shall be awarded grants in multi-year increments not to exceed 36 months. Each grant shall come with a one year initial term, with the Department renewing each year for 2 additional years unless the grantee either declines to continue or fails to meet reasonable performance measures that consider apprenticeship programs timeframes. The Department may take into account experience and performance as a previous grantee of the Climate Works Hub as part of the selection criteria for subsequent years.

(d) Each Climate Works Hub that receives funding from the Energy Transition Assistance Fund shall recruit, prescreen, and provide preapprenticeship training to program participants. Each Climate Works Hub that receives funding from the Energy Transition Assistance Fund shall:

(1) in each Hub Site where the applicant pool allows, comply with the following:

(A) dedicate at least one-third of Program placements to applicants who reside in a geographic area that is impacted by economic and environmental challenges, defined as an area that is both (i) an R3 Area, as defined pursuant to Section 10-40 of the Cannabis Regulation and Tax Act, and (ii) an environmental justice community, as defined by the Illinois Power Agency under the Illinois Power Agency Act, excluding any racial or ethnic indicators used by the Agency unless and until the constitutional basis for the inclusion of the factors in determining Program admissions is established; among applicants that satisfy these criteria, preference shall be given to applicants who face barriers to employment, including low educational attainment, prior involvement with the criminal justice system, and language barriers, and applicants that are graduates of or currently enrolled in the foster care system; and

(B) dedicate at least two-thirds of Program placements to applicants who reside in a geographic area that is impacted by economic or environmental challenges, defined as an area that is either (i) an R3 Area, as defined pursuant to Section 10-40 of the Cannabis Regulation and Tax Act, or (ii) an environmental justice community, as defined by the Illinois Power Agency in the Illinois Power Agency Act, excluding any racial or ethnic indicators used by the Agency unless and until the constitutional basis for the inclusion of the factors in determining Program admissions is established; among applicants that satisfy these criteria, preference shall be given to applicants who face barriers to employment, including low educational attainment, prior involvement with the criminal legal system, and language barriers, and applicants that are graduates of or currently enrolled in the foster care system; and

(C) prioritize the remaining Program placements for the following:

(i) applicants who are displaced energy workers, as defined in the Energy Community Reinvestment Act;

(ii) persons who face barriers to employment, including low educational attainment, prior involvement with the criminal justice system, and language barriers; and

(iii) applicants who are graduates of or currently enrolled in the foster care system, regardless of the applicant's area of residence; Each Climate Works Hub that receives funding from the Energy Transition Assistance Fund shall:

(1) recruit, prescreen, and provide preapprenticeship training to equity investment eligible persons;

(2) provide training information related to opportunities and certifications relevant to clean energy jobs in the construction and building trades; and

(3) provide preapprentices with stipends they receive that may vary depending on the occupation the individual is training for.

(d-5) Priority shall be given to Climate Works Hubs that have an agreement with North American Building Trades Unions (NABTU) to utilize the Multi-Craft Core Curriculum or successor curriculums.

(e) Funding for the Program is subject to appropriation from the Energy Transition Assistance Fund.

(f) The Department shall adopt any rules deemed necessary to implement this Section.

(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22; 102-1123, eff. 1-27-23.)

Section 90-10. The Illinois Finance Authority Act is amended by adding Section 850-20 as follows:

(20 ILCS 3501/850-20 new)

Sec. 850-20. Thermal Energy Network Revolving Loan and Financial Assistance Program.

(a) As used in this Section:

"Program" means the Thermal Energy Network Revolving Loan and Financial Assistance Program established under this Section.

"Thermal energy network" means all real estate, fixtures, and personal property operated, owned, used, or to be used for in connection with or to facilitate a community-scale distribution infrastructure project that transfers heat into and out of buildings using non-combusting thermal energy, sourced from zero-emission technologies, including geothermal energy, for the purpose of reducing emissions. "Thermal energy network" includes, but is not limited to, real estate, fixtures, and personal property that is operated, owned, or used by multiple parties and community geothermal systems.

(b) In its role as the Climate Bank for the State, the Authority may, subject to available funding, establish and administer a Thermal Energy Network Revolving Loan and Financial Assistance Program. The Program shall provide access to capital for thermal energy network projects that take into consideration the risks involved in the development of shared heating and cooling systems and the required coordination among multiple customers, as well as the benefits of enabling low-cost decarbonization of residential, commercial, and industrial buildings and processes. The Program may provide loans, grants, or other financial assistance for thermal energy network projects.

(c) The Authority may establish internal accounts necessary to administer the Program, identify sources of public and private funding and financial capital, and develop any requirements or agreements necessary to successfully execute the Program.

(d) The Authority shall coordinate and enter into any necessary agreements with the Illinois Commerce Commission to (i) develop and offer funding and financing to thermal energy network pilot projects approved by the Commission under subsection (a) of Section 8-513 of the Public Utilities Act, (ii) receive funds as necessary and as approved by the Commission under subsection (b) of Section 8-513 of the Public Utilities Act, and (iii) establish any requirements necessary to ensure compliance with the objectives of any federal funding sources secured to support the Program.

(e) All repayments of loans or other financial assistance made under the Program shall be used or leveraged to provide additional capital to thermal energy network pilot projects that support the clean energy goals of the State, in coordination with any rules established by the Illinois Commerce Commission.

(f) The Authority may adopt any resolutions, plans, or rules and fix, determine, charge, or collect any fees, charges, costs, and expenses necessary to administer the Program under this Section.

Section 90-11. The Illinois Power Agency Act is amended by changing Sections 1-10, 1-20, 1-56, 1-75, and 1-125 as follows:

(20 ILCS 3855/1-10)

Sec. 1-10. Definitions.

"Agency" means the Illinois Power Agency.

"Agency loan agreement" means any agreement pursuant to which the Illinois Finance Authority agrees to loan the proceeds of revenue bonds issued with respect to a project to the Agency upon terms providing for loan repayment installments at least sufficient to pay when due all principal of, interest and premium, if any, on those revenue bonds, and providing for maintenance, insurance, and other matters in respect of the project.

"Authority" means the Illinois Finance Authority.

"Brownfield site photovoltaic project" means photovoltaics that are either:

(1) interconnected to an electric utility as defined in this Section, a municipal utility as defined in this Section, a public utility as defined in Section 3-105 of the Public Utilities Act, or an electric cooperative as defined in Section 3-119 of the Public Utilities Act and located at a site that is regulated by any of the following entities under the following programs:

(A) the United States Environmental Protection Agency under the federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended;

(B) the United States Environmental Protection Agency under the Corrective Action Program of the federal Resource Conservation and Recovery Act, as amended;

(C) the Illinois Environmental Protection Agency under the Illinois Site Remediation Program; or

(D) the Illinois Environmental Protection Agency under the Illinois Solid Waste Program; or

(2) located at the site of a coal mine that has permanently ceased coal production, permanently halted any re-mining operations, and is no longer accepting any coal combustion residues; has both completed all clean-up and remediation obligations under the federal Surface Mining and Reclamation Act of 1977 and all applicable Illinois rules and any other clean-up, remediation, or ongoing monitoring to safeguard the health and well-being of the people of the State of Illinois, as well as demonstrated compliance with all applicable federal and State environmental rules and regulations, including, but not limited, to 35 Ill. Adm. Code Part 845 and any rules for historic fill of coal combustion residuals, including any rules finalized in Subdocket A of Illinois Pollution Control Board docket R2020-019.

"Clean coal facility" means an electric generating facility that uses primarily coal as a feedstock and that captures and sequesters carbon dioxide emissions at the following levels: at least 50% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation before 2016, at least 70% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation during 2016 or 2017, and at least 90% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation after 2017. The power block of the clean coal facility shall not exceed allowable emission rates for sulfur dioxide, nitrogen oxides, carbon monoxide, particulates and mercury for a natural gas-fired combined-cycle facility the same size as and in the same location as the clean coal facility at the time the clean coal facility obtains an approved air permit. All coal used by a clean coal facility shall have high volatile bituminous rank and greater than 1.7 pounds of sulfur per million Btu content, unless the clean coal facility does not use gasification technology and was operating as a conventional coal-fired electric generating facility on June 1, 2009 (the effective date of Public Act 95-1027).

"Clean coal SNG brownfield facility" means a facility that (1) has commenced construction by July 1, 2015 on an urban brownfield site in a municipality with at least 1,000,000 residents; (2) uses a gasification process to produce substitute natural gas; (3) uses coal as at least 50% of the total feedstock over the term of any sourcing agreement with a utility and the remainder of the feedstock may be either petroleum coke or coal, with all such coal having a high bituminous rank and greater than 1.7 pounds of sulfur per million Btu content unless the facility reasonably determines that it is necessary to use additional petroleum coke to deliver additional consumer savings, in which case the facility shall use coal for at least 35% of the total feedstock over the term of any sourcing agreement; and (4) captures and sequesters at least 85% of the total carbon dioxide emissions that the facility would otherwise emit.

"Clean coal SNG facility" means a facility that uses a gasification process to produce substitute natural gas, that sequesters at least 90% of the total carbon dioxide emissions that the facility would otherwise emit, that uses at least 90% coal as a feedstock, with all such coal having a high bituminous rank and greater than 1.7 pounds of sulfur per million Btu content, and that has a valid and effective permit to construct emission sources and air pollution control equipment and approval with respect to the federal regulations for Prevention of Significant Deterioration of Air Quality (PSD) for the plant pursuant to the federal Clean Air Act; provided, however, a clean coal SNG brownfield facility shall not be a clean coal SNG facility.

"Clean energy" means energy generation that is 90% or greater free of carbon dioxide emissions.

"Commission" means the Illinois Commerce Commission.

"Community renewable generation project" means an electric generating facility that:

(1) is powered by wind, solar thermal energy, photovoltaic cells or panels, biodiesel, crops and untreated and unadulterated organic waste biomass, and hydropower that does not involve new construction of dams;

(2) is interconnected at the distribution system level of an electric utility as defined in this Section, a municipal utility as defined in this Section that owns or operates electric distribution facilities, a public utility as defined in Section 3-105 of the Public Utilities Act, or an electric cooperative, as defined in Section 3-119 of the Public Utilities Act;

(3) credits the value of electricity generated by the facility to the subscribers of the facility; and

(4) is limited in nameplate capacity to less than or equal to 5,000 kilowatts.

"Costs incurred in connection with the development and construction of a facility" means:

(1) the cost of acquisition of all real property, fixtures, and improvements in connection therewith and equipment, personal property, and other property, rights, and easements acquired that are deemed necessary for the operation and maintenance of the facility;

(2) financing costs with respect to bonds, notes, and other evidences of indebtedness of the Agency;

(3) all origination, commitment, utilization, facility, placement, underwriting, syndication, credit enhancement, and rating agency fees;

(4) engineering, design, procurement, consulting, legal, accounting, title insurance, survey, appraisal, escrow, trustee, collateral agency, interest rate hedging, interest rate swap, capitalized interest, contingency, as required by lenders, and other financing costs, and other expenses for professional services; and

(5) the costs of plans, specifications, site study and investigation, installation, surveys, other Agency costs and estimates of costs, and other expenses necessary or incidental to determining the feasibility of any project, together with such other expenses as may be necessary or incidental to the financing, insuring, acquisition, and construction of a specific project and starting up, commissioning, and placing that project in operation.

"Delivery services" has the same definition as found in Section 16-102 of the Public Utilities Act.

"Delivery year" means the consecutive 12-month period beginning June 1 of a given year and ending May 31 of the following year.

"Department" means the Department of Commerce and Economic Opportunity.

"Director" means the Director of the Illinois Power Agency.

"Demand response Demand-response" means measures that decrease peak electricity demand or shift demand from peak to off-peak periods.

"Distributed renewable energy generation device" means a device that is:

(1) powered by wind, solar thermal energy, photovoltaic cells or panels, biodiesel, crops and untreated and unadulterated organic waste biomass, tree waste, and hydropower that does not involve new construction of dams, waste heat to power systems, or qualified combined heat and power systems;

(2) interconnected at the distribution system level of either an electric utility as defined in this Section, a municipal utility as defined in this Section that owns or operates electric distribution facilities, or a rural electric cooperative as defined in Section 3-119 of the Public Utilities Act;

(3) located on the customer side of the customer's electric meter and is primarily used to offset that customer's electricity load; and

(4) (blank).

"Energy efficiency" means measures that reduce the amount of electricity or natural gas consumed in order to achieve a given end use. "Energy efficiency" includes voltage optimization measures that optimize the voltage at points on the electric distribution voltage system and thereby reduce electricity consumption by electric customers' end use devices. "Energy efficiency" also includes measures that reduce the total Btus of electricity, natural gas, and other fuels needed to meet the end use or uses.

"Energy storage system" has the meaning given to that term in Section 16-135 of the Public Utilities Act. "Energy storage system" does not include technologies that require combustion.

"Energy storage resources" means the operational output or capabilities of energy storage systems. "Energy storage resources" includes, but is not limited to, energy, capacity, and energy storage credits.

"Electric utility" has the same definition as found in Section 16-102 of the Public Utilities Act.

"Equity investment eligible community" or "eligible community" are synonymous and mean the geographic areas throughout Illinois which would most benefit from equitable investments by the State designed to combat discrimination. Specifically, the eligible communities shall be defined as the following areas:

(1) R3 Areas as established pursuant to Section 10-40 of the Cannabis Regulation and Tax Act, where residents have historically been excluded from economic opportunities, including opportunities in the energy sector; and

(2) environmental justice communities, as defined by the Illinois Power Agency pursuant to the Illinois Power Agency Act, where residents have historically been subject to disproportionate burdens of pollution, including pollution from the energy sector.

"Equity eligible persons" or "eligible persons" means persons who would most benefit from equitable investments by the State designed to combat discrimination, specifically:

(1) persons who graduate from or are current or former participants in the Clean Jobs Workforce Network Program, the Clean Energy Contractor Incubator Program, the Illinois Climate Works Preapprenticeship Program, Returning Residents Clean Jobs Training Program, or the Clean Energy Primes Contractor Accelerator Program, and the solar training pipeline and multi-cultural jobs program created in paragraphs (1) and (3) of subsection (a) (a)(1) and (a)(3) of Section 16-108.12 16-208.12 of the Public Utilities Act;

(2) persons who are graduates of or currently enrolled in the foster care system;

(3) persons who were formerly incarcerated;

(4) persons whose primary residence is in an equity investment eligible community.

"Equity eligible contractor" means a business that is majority-owned by eligible persons, or a nonprofit or cooperative that is majority-governed by eligible persons, or is a natural person that is an eligible person offering personal services as an independent contractor.

"Facility" means an electric generating unit or a co-generating unit that produces electricity along with related equipment necessary to connect the facility to an electric transmission or distribution system.

"General contractor" means the entity or organization with main responsibility for the building of a construction project and who is the party signing the prime construction contract for the project.

"Governmental aggregator" means one or more units of local government that individually or collectively procure electricity to serve residential retail electrical loads located within its or their jurisdiction.

"High voltage direct current converter station" means the collection of equipment that converts direct current energy from a high voltage direct current transmission line into alternating current using Voltage Source Conversion technology and that is interconnected with transmission or distribution assets located in Illinois.

"High voltage direct current renewable energy credit" means a renewable energy credit associated with a renewable energy resource where the renewable energy resource has entered into a contract to transmit the energy associated with such renewable energy credit over high voltage direct current transmission facilities.

"High voltage direct current transmission facilities" means the collection of installed equipment that converts alternating current energy in one location to direct current and transmits that direct current energy to a high voltage direct current converter station using Voltage Source Conversion technology. "High voltage direct current transmission facilities" includes the high voltage direct current converter station itself and associated high voltage direct current transmission lines. Notwithstanding the preceding, after September 15, 2021 (the effective date of Public Act 102-662), an otherwise qualifying collection of equipment does not qualify as high voltage direct current transmission facilities unless (1) its developer entered into a project labor agreement, is capable of transmitting electricity at 525kv with an Illinois converter station located and interconnected in the region of the PJM Interconnection, LLC, and the system does not operate as a public utility, as that term is defined in Section 3-105 of the Public Utilities Act, serving more than 100,000 customers as of January 1, 2021; or (2) its developer has entered into a project labor agreement prior to construction, the project is capable of transmitting electricity at 525 kilovolts or above, and the project has a converter station that is located in this State or in a state adjacent to this State and is interconnected to PJM Interconnection, LLC, the Midcontinent Independent System Operator, Inc., or their successor.

"Hydropower" means any method of electricity generation or storage that results from the flow of water, including impoundment facilities, diversion facilities, and pumped storage facilities.

"Index price" means the real-time energy settlement price at the applicable Illinois trading hub, such as PJM-NIHUB or MISO-IL, for a given settlement period.

"Indexed renewable energy credit" means a tradable credit that represents the environmental attributes of one megawatt hour of energy produced from a renewable energy resource, the price of which shall be calculated by subtracting the strike price offered by a new utility-scale wind project or a new utility-scale photovoltaic project from the index price in a given settlement period.

"Indexed renewable energy credit counterparty" has the same meaning as "public utility" as defined in Section 3-105 of the Public Utilities Act.

"Local government" means a unit of local government as defined in Section 1 of Article VII of the Illinois Constitution.

"Modernized" or "retooled" means the construction, repair, maintenance, or significant expansion of turbines and existing hydropower dams.

"Municipality" means a city, village, or incorporated town.

"Municipal utility" means a public utility owned and operated by any subdivision or municipal corporation of this State.

"Nameplate capacity" means the aggregate inverter nameplate capacity in kilowatts AC.

"Person" means any natural person, firm, partnership, corporation, either domestic or foreign, company, association, limited liability company, joint stock company, or association and includes any trustee, receiver, assignee, or personal representative thereof.

"Project" means the planning, bidding, and construction of a facility.

"Project labor agreement" means a pre-hire collective bargaining agreement that covers all terms and conditions of employment on a specific construction project and must include the following:

(1) provisions establishing the minimum hourly wage for each class of labor organization employee;

(2) provisions establishing the benefits and other compensation for each class of labor organization employee;

(3) provisions establishing that no strike or disputes will be engaged in by the labor organization employees;

(4) provisions establishing that no lockout or disputes will be engaged in by the general contractor building the project; and

(5) provisions for minorities and women, as defined under the Business Enterprise for Minorities, Women, and Persons with Disabilities Act, setting forth goals for apprenticeship hours to be performed by minorities and women and setting forth goals for total hours to be performed by underrepresented minorities and women.

A labor organization and the general contractor building the project shall have the authority to include other terms and conditions as they deem necessary.

"Public utility" has the same definition as found in Section 3-105 of the Public Utilities Act.

"Qualified combined heat and power systems" means systems that, either simultaneously or sequentially, produce electricity and useful thermal energy from a single fuel source. Such systems are eligible for "renewable energy credits" in an amount equal to its total energy output where a renewable fuel is consumed or in an amount equal to the net reduction in nonrenewable fuel consumed on a total energy output basis.

"Real property" means any interest in land together with all structures, fixtures, and improvements thereon, including lands under water and riparian rights, any easements, covenants, licenses, leases, rights-of-way, uses, and other interests, together with any liens, judgments, mortgages, or other claims or security interests related to real property.

"Renewable energy credit" means a tradable credit that represents the environmental attributes of one megawatt hour of energy produced from a renewable energy resource.

"Renewable energy resources" includes energy and its associated renewable energy credit or renewable energy credits from wind, solar thermal energy, photovoltaic cells and panels, biodiesel, anaerobic digestion, crops and untreated and unadulterated organic waste biomass, and hydropower that does not involve new construction of dams, waste heat to power systems, or qualified combined heat and power systems. For purposes of this Act, landfill gas produced in the State is considered a renewable energy resource. "Renewable energy resources" does not include the incineration or burning of tires, garbage, general household, institutional, and commercial waste, industrial lunchroom or office waste, landscape waste, railroad crossties, utility poles, or construction or demolition debris, other than untreated and unadulterated waste wood. "Renewable energy resources" also includes high voltage direct current renewable energy credits and the associated energy converted to alternating current by a high voltage direct current converter station to the extent that: (1) the generator of such renewable energy resource contracted with a third party to transmit the energy over the high voltage direct current transmission facilities, and (2) the third-party contracting for delivery of renewable energy resources over the high voltage direct current transmission facilities have ownership rights over the unretired associated high voltage direct current renewable energy credit.

"Retail customer" has the same definition as found in Section 16-102 of the Public Utilities Act.

"Revenue bond" means any bond, note, or other evidence of indebtedness issued by the Authority, the principal and interest of which is payable solely from revenues or income derived from any project or activity of the Agency.

"Sequester" means permanent storage of carbon dioxide by injecting it into a saline aquifer, a depleted gas reservoir, or an oil reservoir, directly or through an enhanced oil recovery process that may involve intermediate storage, regardless of whether these activities are conducted by a clean coal facility, a clean coal SNG facility, a clean coal SNG brownfield facility, or a party with which a clean coal facility, clean coal SNG facility, or clean coal SNG brownfield facility has contracted for such purposes.

"Service area" has the same definition as found in Section 16-102 of the Public Utilities Act.

"Settlement period" means the period of time utilized by MISO and PJM and their successor organizations as the basis for settlement calculations in the real-time energy market.

"Sourcing agreement" means (i) in the case of an electric utility, an agreement between the owner of a clean coal facility and such electric utility, which agreement shall have terms and conditions meeting the requirements of paragraph (3) of subsection (d) of Section 1-75, (ii) in the case of an alternative retail electric supplier, an agreement between the owner of a clean coal facility and such alternative retail electric supplier, which agreement shall have terms and conditions meeting the requirements of Section 16-115(d)(5) of the Public Utilities Act, and (iii) in case of a gas utility, an agreement between the owner of a clean coal SNG brownfield facility and the gas utility, which agreement shall have the terms and conditions meeting the requirements of subsection (h-1) of Section 9-220 of the Public Utilities Act.

"Strike price" means a contract price for energy and renewable energy credits from a new utility-scale wind project or a new utility-scale photovoltaic project.

"Subscriber" means a person who (i) takes delivery service from an electric utility, and (ii) has a subscription of no less than 200 watts to a community renewable generation project that is located in the electric utility's service area. No subscriber's subscriptions may total more than 40% of the nameplate capacity of an individual community renewable generation project. Entities that are affiliated by virtue of a common parent shall not represent multiple subscriptions that total more than 40% of the nameplate capacity of an individual community renewable generation project.

"Subscription" means an interest in a community renewable generation project expressed in kilowatts, which is sized primarily to offset part or all of the subscriber's electricity usage.

"Substitute natural gas" or "SNG" means a gas manufactured by gasification of hydrocarbon feedstock, which is substantially interchangeable in use and distribution with conventional natural gas.

"Total resource cost test" or "TRC test" means a standard that is met if, for an investment in energy efficiency or demand-response measures, the benefit-cost ratio is greater than one. The benefit-cost ratio is the ratio of the net present value of the total benefits of the program to the net present value of the total costs as calculated over the lifetime of the measures. A total resource cost test compares the sum of avoided electric utility costs, representing the benefits that accrue to the system and the participant in the delivery of those efficiency measures and including avoided costs associated with reduced use of natural gas or other fuels, avoided costs associated with reduced water consumption, and avoided costs associated with reduced operation and maintenance costs, and avoided societal costs associated with reductions in greenhouse gas emissions, as well as other quantifiable societal benefits, to the sum of all incremental costs of end-use measures that are implemented due to the program (including both utility and participant contributions), plus costs to administer, deliver, and evaluate each demand-side program, to quantify the net savings obtained by substituting the demand-side program for supply resources. The societal costs associated with greenhouse gas emissions shall be $200 per short ton, expressed in 2025 dollars or the most recently approved estimate developed by the federal government using a real discount rate consistent with long-term Treasury bond yields, whichever is greater. Changes in greenhouse gas emissions due to changes in electricity consumption shall be estimated using long-run marginal emissions rates developed by the National Renewable Energy Laboratory's Cambium model or other Illinois-specific modeling of comparable analytical rigor. In calculating avoided costs of power and energy that an electric utility would otherwise have had to acquire, reasonable estimates shall be included of financial costs likely to be imposed by future regulations and legislation on emissions of greenhouse gases. In discounting future societal costs and benefits for the purpose of calculating net present values, a societal discount rate based on actual, long-term Treasury bond yields should be used. Notwithstanding anything to the contrary, the TRC test shall not include or take into account a calculation of market price suppression effects or demand reduction induced price effects.

"Utility-scale solar project" means an electric generating facility that:

(1) generates electricity using photovoltaic cells; and

(2) has a nameplate capacity that is greater than 5,000 kilowatts alternating current (AC).

"Utility-scale wind project" means an electric generating facility that:

(1) generates electricity using wind; and

(2) has a nameplate capacity that is greater than 5,000 kilowatts.

"Waste Heat to Power Systems" means systems that capture and generate electricity from energy that would otherwise be lost to the atmosphere without the use of additional fuel.

"Zero emission credit" means a tradable credit that represents the environmental attributes of one megawatt hour of energy produced from a zero emission facility.

"Zero emission facility" means a facility that: (1) is fueled by nuclear power; and (2) is interconnected with PJM Interconnection, LLC or the Midcontinent Independent System Operator, Inc., or their successors.

(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23; 103-380, eff. 1-1-24.)

(20 ILCS 3855/1-20)

Sec. 1-20. General powers and duties of the Agency.

(a) The Agency is authorized to do each of the following:

(1) Develop electricity procurement plans to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois and for small multi-jurisdictional electric utilities that (A) on December 31, 2005 served less than 100,000 customers in Illinois and (B) request a procurement plan for their Illinois jurisdictional load. Except as provided in paragraph (1.5) of this subsection (a), the electricity procurement plans shall be updated on an annual basis and shall include electricity generated from renewable resources sufficient to achieve the standards specified in this Act. Beginning with the delivery year commencing June 1, 2017, develop procurement plans to include zero emission credits generated from zero emission facilities sufficient to achieve the standards specified in this Act. Beginning with the delivery year commencing on June 1, 2022, the Agency is authorized to develop carbon mitigation credit procurement plans to include carbon mitigation credits generated from carbon-free energy resources sufficient to achieve the standards specified in this Act.

(1.5) Develop a long-term renewable resources procurement plan in accordance with subsection (c) of Section 1-75 of this Act for renewable energy credits in amounts sufficient to achieve the standards specified in this Act for delivery years commencing June 1, 2017 and for the programs and renewable energy credits specified in Section 1-56 of this Act. Electricity procurement plans for delivery years commencing after May 31, 2017, shall not include procurement of renewable energy resources.

(2) Conduct competitive procurement processes to procure the supply resources identified in the electricity procurement plan, pursuant to Section 16-111.5 of the Public Utilities Act, and, for the delivery year commencing June 1, 2017, conduct procurement processes to procure zero emission credits from zero emission facilities, under subsection (d-5) of Section 1-75 of this Act. For the delivery year commencing June 1, 2022, the Agency is authorized to conduct procurement processes to procure carbon mitigation credits from carbon-free energy resources, under subsection (d-10) of Section 1-75 of this Act.

(2.5) Beginning with the procurement for the 2017 delivery year, conduct competitive procurement processes and implement programs to procure renewable energy credits identified in the long-term renewable resources procurement plan developed and approved under subsection (c) of Section 1-75 of this Act and Section 16-111.5 of the Public Utilities Act.

(2.10) Oversee the procurement by electric utilities that served more than 300,000 customers in this State as of January 1, 2019 of renewable energy credits from new renewable energy facilities to be installed, along with energy storage facilities, at or adjacent to the sites of electric generating facilities that burned coal as their primary fuel source as of January 1, 2016 in accordance with subsection (c-5) of Section 1-75 of this Act.

(2.15) Oversee the procurement by electric utilities of renewable energy credits from newly modernized or retooled hydropower dams or dams that have been converted to support hydropower generation.

(3) Develop electric generation and co-generation facilities that use indigenous coal or renewable resources, or both, financed with bonds issued by the Illinois Finance Authority.

(4) Supply electricity from the Agency's facilities at cost to one or more of the following: municipal electric systems, governmental aggregators, or rural electric cooperatives in Illinois.

(5) Develop a long-term energy storage resources procurement plan and conduct competitive procurement processes in accordance with subsection (d-20) of Section 1-75.

(b) Except as otherwise limited by this Act, the Agency has all of the powers necessary or convenient to carry out the purposes and provisions of this Act, including without limitation, each of the following:

(1) To have a corporate seal, and to alter that seal at pleasure, and to use it by causing it or a facsimile to be affixed or impressed or reproduced in any other manner.

(2) To use the services of the Illinois Finance Authority necessary to carry out the Agency's purposes.

(3) To negotiate and enter into loan agreements and other agreements with the Illinois Finance Authority.

(4) To obtain and employ personnel and hire consultants that are necessary to fulfill the Agency's purposes, and to make expenditures for that purpose within the appropriations for that purpose.

(5) To purchase, receive, take by grant, gift, devise, bequest, or otherwise, lease, or otherwise acquire, own, hold, improve, employ, use, and otherwise deal in and with, real or personal property whether tangible or intangible, or any interest therein, within the State.

(6) To acquire real or personal property, whether tangible or intangible, including without limitation property rights, interests in property, franchises, obligations, contracts, and debt and equity securities, and to do so by the exercise of the power of eminent domain in accordance with Section 1-21; except that any real property acquired by the exercise of the power of eminent domain must be located within the State.

(7) To sell, convey, lease, exchange, transfer, abandon, or otherwise dispose of, or mortgage, pledge, or create a security interest in, any of its assets, properties, or any interest therein, wherever situated.

(8) To purchase, take, receive, subscribe for, or otherwise acquire, hold, make a tender offer for, vote, employ, sell, lend, lease, exchange, transfer, or otherwise dispose of, mortgage, pledge, or grant a security interest in, use, and otherwise deal in and with, bonds and other obligations, shares, or other securities (or interests therein) issued by others, whether engaged in a similar or different business or activity.

(9) To make and execute agreements, contracts, and other instruments necessary or convenient in the exercise of the powers and functions of the Agency under this Act, including contracts with any person, including personal service contracts, or with any local government, State agency, or other entity; and all State agencies and all local governments are authorized to enter into and do all things necessary to perform any such agreement, contract, or other instrument with the Agency. No such agreement, contract, or other instrument shall exceed 40 years.

(10) To lend money, invest and reinvest its funds in accordance with the Public Funds Investment Act, and take and hold real and personal property as security for the payment of funds loaned or invested.

(11) To borrow money at such rate or rates of interest as the Agency may determine, issue its notes, bonds, or other obligations to evidence that indebtedness, and secure any of its obligations by mortgage or pledge of its real or personal property, machinery, equipment, structures, fixtures, inventories, revenues, grants, and other funds as provided or any interest therein, wherever situated.

(12) To enter into agreements with the Illinois Finance Authority to issue bonds whether or not the income therefrom is exempt from federal taxation.

(13) To procure insurance against any loss in connection with its properties or operations in such amount or amounts and from such insurers, including the federal government, as it may deem necessary or desirable, and to pay any premiums therefor.

(14) To negotiate and enter into agreements with trustees or receivers appointed by United States bankruptcy courts or federal district courts or in other proceedings involving adjustment of debts and authorize proceedings involving adjustment of debts and authorize legal counsel for the Agency to appear in any such proceedings.

(15) To file a petition under Chapter 9 of Title 11 of the United States Bankruptcy Code or take other similar action for the adjustment of its debts.

(16) To enter into management agreements for the operation of any of the property or facilities owned by the Agency.

(17) To enter into an agreement to transfer and to transfer any land, facilities, fixtures, or equipment of the Agency to one or more municipal electric systems, governmental aggregators, or rural electric agencies or cooperatives, for such consideration and upon such terms as the Agency may determine to be in the best interest of the residents of Illinois.

(18) To enter upon any lands and within any building whenever in its judgment it may be necessary for the purpose of making surveys and examinations to accomplish any purpose authorized by this Act.

(19) To maintain an office or offices at such place or places in the State as it may determine.

(20) To request information, and to make any inquiry, investigation, survey, or study that the Agency may deem necessary to enable it effectively to carry out the provisions of this Act.

(21) To accept and expend appropriations.

(22) To engage in any activity or operation that is incidental to and in furtherance of efficient operation to accomplish the Agency's purposes, including hiring employees that the Director deems essential for the operations of the Agency.

(23) To adopt, revise, amend, and repeal rules with respect to its operations, properties, and facilities as may be necessary or convenient to carry out the purposes of this Act, subject to the provisions of the Illinois Administrative Procedure Act and Sections 1-22 and 1-35 of this Act.

(24) To establish and collect charges and fees as described in this Act.

(25) To conduct competitive gasification feedstock procurement processes to procure the feedstocks for the clean coal SNG brownfield facility in accordance with the requirements of Section 1-78 of this Act.

(26) To review, revise, and approve sourcing agreements and mediate and resolve disputes between gas utilities and the clean coal SNG brownfield facility pursuant to subsection (h-1) of Section 9-220 of the Public Utilities Act.

(27) To request, review and accept proposals, execute contracts, purchase renewable energy credits and otherwise dedicate funds from the Illinois Power Agency Renewable Energy Resources Fund to create and carry out the objectives of the Illinois Solar for All Program in accordance with Section 1-56 of this Act.

(28) To ensure Illinois residents and business benefit from programs administered by the Agency and are properly protected from any deceptive or misleading marketing practices by participants in the Agency's programs and procurements.

(c) In conducting the procurement of electricity or other products, beginning January 1, 2022, the Agency shall not procure any products or services from persons or organizations that are in violation of the Displaced Energy Workers Bill of Rights, as provided under the Energy Community Reinvestment Act at the time of the procurement event or fail to comply the labor standards established in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75.

(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)

(20 ILCS 3855/1-56)

Sec. 1-56. Illinois Power Agency Renewable Energy Resources Fund; Illinois Solar for All Program.

(a) The Illinois Power Agency Renewable Energy Resources Fund is created as a special fund in the State treasury.

(b) The Illinois Power Agency Renewable Energy Resources Fund shall be administered by the Agency as described in this subsection (b), provided that the changes to this subsection (b) made by Public Act 99-906 shall not interfere with existing contracts under this Section.

(1) The Illinois Power Agency Renewable Energy Resources Fund shall be used to purchase renewable energy credits according to any approved procurement plan developed by the Agency prior to June 1, 2017.

(2) The Illinois Power Agency Renewable Energy Resources Fund shall also be used to create the Illinois Solar for All Program, which provides incentives for low-income distributed generation and community solar projects, and other associated approved expenditures. The objectives of the Illinois Solar for All Program are to bring photovoltaics to low-income communities in this State in a manner that maximizes the development of new photovoltaic generating facilities, to create a long-term, low-income solar marketplace throughout this State, to integrate, through interaction with stakeholders, with existing energy efficiency initiatives, and to minimize administrative costs. The Illinois Solar for All Program shall be implemented in a manner that seeks to minimize administrative costs, and maximize efficiencies and synergies available through coordination with similar initiatives, including the Adjustable Block program described in subparagraphs (K) through (M) of paragraph (1) of subsection (c) of Section 1-75, energy efficiency programs, job training programs, and community action agencies , and agencies that administer the Low-Income Home Energy Assistance Program. The Agency shall strive to ensure that renewable energy credits procured through the Illinois Solar for All Program and each of its subprograms are purchased from projects across the breadth of low-income and environmental justice communities in Illinois, including both urban and rural communities, are not concentrated in a few communities, and do not exclude particular low-income or environmental justice communities. The Agency shall include a description of its proposed approach to the design, administration, implementation and evaluation of the Illinois Solar for All Program, as part of the long-term renewable resources procurement plan authorized by subsection (c) of Section 1-75 of this Act, and the program shall be designed to grow the low-income solar market. The Agency or utility, as applicable, shall purchase renewable energy credits from the (i) photovoltaic distributed renewable energy generation projects and (ii) community solar projects that are procured under procurement processes authorized by the long-term renewable resources procurement plans approved by the Commission.

The Illinois Solar for All Program shall include the program offerings described in subparagraphs (A) through (E) of this paragraph (2), which the Agency shall implement through contracts with third-party providers and, subject to appropriation, pay the approximate amounts identified using monies available in the Illinois Power Agency Renewable Energy Resources Fund. Each contract that provides for the installation of solar facilities shall provide that the solar facilities will produce energy and economic benefits, at a level determined by the Agency to be reasonable, for the participating low-income customers. The monies available in the Illinois Power Agency Renewable Energy Resources Fund and not otherwise committed to contracts executed under subsection (i) of this Section, as well as, in the case of the programs described under subparagraphs (A) through (E) of this paragraph (2), funding authorized pursuant to subparagraph (O) of paragraph (1) of subsection (c) of Section 1-75 of this Act, shall initially be allocated among the programs described in this paragraph (2), as follows: 35% of these funds shall be allocated to programs described in subparagraphs (A) and (E) of this paragraph (2), 40% of these funds shall be allocated to programs described in subparagraph (B) of this paragraph (2), and 25% of these funds shall be allocated to programs described in subparagraph (C) of this paragraph (2). The allocation of funds among subparagraphs (A), (B), (C), and (E) of this paragraph (2) may be changed if the Agency, after receiving input through a stakeholder process, determines incentives in subparagraph subparagraphs (A), (B), (C), or (E) of this paragraph (2) have not been adequately subscribed to fully utilize available Illinois Solar for All Program funds.

Contracts that will be paid with funds in the Illinois Power Agency Renewable Energy Resources Fund shall be executed by the Agency. Contracts that will be paid with funds collected by an electric utility shall be executed by the electric utility.

Contracts under the Illinois Solar for All Program shall include an approach, as set forth in the long-term renewable resources procurement plans, to ensure the wholesale market value of the energy is credited to participating low-income customers or organizations and to ensure tangible economic benefits flow directly to program participants, except in the case of low-income multi-family housing where the low-income customer does not directly pay for energy. Priority shall be given to projects that demonstrate meaningful involvement of low-income community members in designing the initial proposals. Acceptable proposals to implement projects must demonstrate the applicant's ability to conduct initial community outreach, education, and recruitment of low-income participants in the community. Projects submitted by approved vendors must either comply with the minimum equity standard set forth in subsection (c-10) of Section 1-75 of this Act or must include job training opportunities if available, with the specific level of trainee usage to be determined through the Agency's long-term renewable resources procurement plan, and the Illinois Solar for All Program Administrator shall coordinate with the job training programs described in paragraph (1) of subsection (a) of Section 16-108.12 of the Public Utilities Act and in the Energy Transition Act.

The Agency shall make every effort to ensure that small and emerging businesses, particularly those located in low-income and environmental justice communities, are able to participate in the Illinois Solar for All Program. These efforts may include, but shall not be limited to, proactive support from the program administrator, different or preferred access to subprograms and administrator-identified customers or grassroots education provider-identified customers, and different incentive levels. The Agency shall report on progress and barriers to participation of small and emerging businesses in the Illinois Solar for All Program at least once a year. The report shall be made available on the Agency's website and, in years when the Agency is updating its long-term renewable resources procurement plan, included in that Plan.

(A) Low-income single-family and small multifamily solar incentive. This program will provide incentives to low-income customers, either directly or through solar providers, to increase the participation of low-income households in photovoltaic on-site distributed generation at residential buildings containing one to 4 units. Companies participating in this program that install solar panels shall commit to meeting a minimum equity standard or hiring job trainees for a portion of their low-income installations, and an administrator shall facilitate partnering the companies that install solar panels with entities that provide solar panel installation job training. It is a goal of this program that a minimum of 25% of the incentives for this program be allocated to projects located within environmental justice communities. Contracts entered into under this paragraph may be entered into with an entity that will develop and administer the program and shall also include contracts for renewable energy credits from the photovoltaic distributed generation that is the subject of the program, as set forth in the long-term renewable resources procurement plan. Additionally:

(i) The Agency shall reserve a portion of this program for projects that promote energy sovereignty through ownership of projects by low-income households, not-for-profit organizations providing services to low-income households, affordable housing owners, community cooperatives, or community-based limited liability companies providing services to low-income households. Projects that feature energy ownership should ensure that local people have control of the project and reap benefits from the project over and above energy bill savings. The Agency may consider the inclusion of projects that promote ownership over time or that involve partial project ownership by communities, as promoting energy sovereignty. Incentives for projects that promote energy sovereignty may be higher than incentives for equivalent projects that do not promote energy sovereignty under this same program.

(ii) Through its long-term renewable resources procurement plan, the Agency shall consider additional program and contract requirements to ensure faithful compliance by applicants benefiting from preferences for projects designated to promote energy sovereignty. The Agency shall make every effort to enable solar providers already participating in the Adjustable Block program Program under subparagraph (K) of paragraph (1) of subsection (c) of Section 1-75 of this Act, and particularly solar providers developing projects under item (i) of subparagraph (K) of paragraph (1) of subsection (c) of Section 1-75 of this Act to easily participate in the Low-Income Distributed Generation Incentive program described under this subparagraph (A), and vice versa. This effort may include, but shall not be limited to, utilizing similar or the same application systems and processes, utilizing similar or the same forms and formats of communication, and providing active outreach to companies participating in one program but not the other. The Agency shall report on efforts made to encourage this cross-participation in its long-term renewable resources procurement plan.

(iii) To maximize equitable participation in this program and overcome challenges facing the development of residential solar projects, the Agency may propose a payment structure for contracts executed pursuant to this subparagraph (A) under which applicant firms are advanced capital that is disbursed after contract execution but before the contracted project's energization, upon a demonstration of qualification or need under criteria established by the Agency that are focused on supporting the small and emerging businesses and the businesses that most acutely face barriers to capital access, which severely limits the businesses' participation in the program described in this subparagraph (A). The amount or percentage of capital advanced before project energization shall be designed to overcome the barriers in access to capital that are faced by an applicant. The amount or percentage of advanced capital may vary under this subparagraph (A) by an applicant's demonstration of need, with such levels to be established through the Long-Term Renewable Resources Procurement Plan and any application requirements or evaluation criteria developed under that Plan.

(B) Low-Income Community Solar Project Initiative. Incentives shall be offered to low-income customers, either directly or through developers, to increase the participation of low-income subscribers of community solar projects. The developer of each project shall identify its partnership with community stakeholders regarding the location, development, and participation in the project, provided that nothing shall preclude a project from including an anchor tenant that does not qualify as low-income. Companies participating in this program that develop or install solar projects shall commit to meeting a minimum equity standard or to hiring job trainees for a portion of their low-income installations, and an administrator shall facilitate partnering the companies that install solar projects with entities that provide solar installation and related job training. It is a goal of this program that a minimum of 25% of the incentives for this program be allocated to community photovoltaic projects in environmental justice communities. The Agency shall reserve a portion of this program for projects that promote energy sovereignty through ownership of projects by low-income households, not-for-profit organizations providing services to low-income households, affordable housing owners, or community-based limited liability companies providing services to low-income households. Projects that feature energy ownership should ensure that local people have control of the project and reap benefits from the project over and above energy bill savings. The Agency may consider the inclusion of projects that promote ownership over time or that involve partial project ownership by communities, as promoting energy sovereignty. Incentives for projects that promote energy sovereignty may be higher than incentives for equivalent projects that do not promote energy sovereignty under this same program. Contracts entered into under this paragraph may be entered into with developers and shall also include contracts for renewable energy credits related to the program.

(C) Incentives for non-profits and public facilities. Under this program funds shall be used to support on-site photovoltaic distributed renewable energy generation devices to serve the load associated with not-for-profit customers and to support photovoltaic distributed renewable energy generation that uses photovoltaic technology to serve the load associated with public sector customers taking service at public buildings. Master-metered multifamily buildings that primarily house income-eligible residents may qualify under this subparagraph (C). Nonprofits and public facilities that can demonstrate that the nonprofit or public facility serves income-qualified or environmental justice communities may potentially qualify for the program, regardless of physical location. Qualification may be determined using the same procedures applied to critical service provider requests for the purpose of establishing project eligibility in areas that are not designated as income-eligible or environmental justice communities. Companies participating in this program that develop or install solar projects shall commit to meeting a minimum equity standard or to hiring job trainees for a portion of their low-income installations, and an administrator shall facilitate partnering the companies that install solar projects with entities that provide solar installation and related job training. Through its long-term renewable resources procurement plan, the Agency shall consider additional program and contract requirements to ensure faithful compliance by applicants benefiting from preferences for projects designated to promote energy sovereignty. It is a goal of this program that at least 25% of the incentives for this program be allocated to projects located in environmental justice communities. Contracts entered into under this paragraph may be entered into with an entity that will develop and administer the program or with developers and shall also include contracts for renewable energy credits related to the program.

(D) (Blank).

(E) Low-income large multifamily solar incentive. This program shall provide incentives to low-income customers, either directly or through solar providers, to increase the participation of low-income households in photovoltaic on-site distributed generation at residential buildings with 5 or more units. Companies participating in this program that develop or install solar projects shall commit to meeting a minimum equity standard or to hiring job trainees for a portion of their low-income installations, and an administrator shall facilitate partnering the companies that install solar projects with entities that provide solar installation and related job training. It is a goal of this program that a minimum of 25% of the incentives for this program be allocated to projects located within environmental justice communities. The Agency shall reserve a portion of this program for projects that promote energy sovereignty through ownership of projects by low-income households, not-for-profit organizations providing services to low-income households, affordable housing owners, or community-based limited liability companies providing services to low-income households. Projects that feature energy ownership should ensure that local people have control of the project and reap benefits from the project over and above energy bill savings. The Agency may consider the inclusion of projects that promote ownership over time or that involve partial project ownership by communities, as promoting energy sovereignty. Incentives for projects that promote energy sovereignty may be higher than incentives for equivalent projects that do not promote energy sovereignty under this same program.

The requirement that a qualified person, as defined in paragraph (1) of subsection (i) of this Section, install photovoltaic devices does not apply to the Illinois Solar for All Program described in this subsection (b).

In addition to the programs outlined in paragraphs (A) through (E), the Agency and other parties may propose additional programs through the long-term renewable resources procurement plan Long-Term Renewable Resources Procurement Plan developed and approved under paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. Additional programs may target market segments not specified above and may also include incentives targeted to increase the uptake of nonphotovoltaic technologies by low-income customers, including energy storage paired with photovoltaics, if the Commission determines that the Illinois Solar for All Program would provide greater benefits to the public health and well-being of low-income residents through also supporting that additional program versus supporting programs already authorized.

(3) Costs associated with the Illinois Solar for All Program and its components described in paragraph (2) of this subsection (b), including, but not limited to, costs associated with procuring experts, consultants, and the program administrator referenced in this subsection (b) and related incremental costs, costs related to income verification and facilitating customer participation in the program through referrals and other methods, costs related to obtaining feedback on the program from parties that do not have a financial interest, and costs related to the evaluation of the Illinois Solar for All Program, may be paid for using monies in the Illinois Power Agency Renewable Energy Resources Fund, and funds allocated pursuant to subparagraph (O) of paragraph (1) of subsection (c) of Section 1-75, but the Agency or program administrator shall strive to minimize costs in the implementation of the program. The Agency or contracting electric utility shall purchase renewable energy credits from generation that is the subject of a contract under subparagraphs (A) through (E) of paragraph (2) of this subsection (b), and may pay for such renewable energy credits through an upfront payment per installed kilowatt of nameplate capacity paid once the device is interconnected at the distribution system level of the interconnecting utility and verified as energized. Unless otherwise provided in the Agency's long-term renewable resources procurement plan, payments Payments for renewable energy credits shall be in exchange for all renewable energy credits generated by the system during the first 15 years of operation and shall be structured to overcome barriers to participation in the solar market by the low-income community. The incentives provided for in this Section may be implemented through the pricing of renewable energy credits where the prices paid for the credits are higher than the prices from programs offered under subsection (c) of Section 1-75 of this Act to account for the additional capital necessary to successfully access targeted market segments. The Agency or contracting electric utility shall retire any renewable energy credits purchased under this program and the credits shall count toward the obligation under subsection (c) of Section 1-75 of this Act for the electric utility to which the project is interconnected, if applicable.

The Agency shall direct that up to 5% of the funds available under the Illinois Solar for All Program to community-based groups and other qualifying organizations to assist in community-driven education efforts related to the Illinois Solar for All Program, including general energy education, job training program outreach efforts, and other activities deemed to be qualified by the Agency. Grassroots education funding shall not be used to support the marketing by solar project development firms and organizations, unless such education provides equal opportunities for all applicable firms and organizations.

The Agency may direct up to 25% of the funds currently allocated to subparagraphs (A), (C), and (E) of paragraph (2) toward the Illinois Storage for All Program, which provides incentives through grants, rebates, or other incentives to encourage development of energy storage colocated with photovoltaic distributed renewable energy generation devices developed through the Illinois Solar for All Program. Any unused Storage for All funds during a program year may be reallocated to other Solar for All Program projects that are waitlisted or otherwise not selected due to funding limitation per the Agency's defined process. The Illinois Storage for All Program shall be available to current and future participants of the low-income single-family and multifamily subprogram described in subparagraphs (A) and (E) of paragraph (2), and the subprogram for nonprofit and public facilities described in subparagraph (C) of paragraph (2). If developed, the Illinois Storage for All Program may be designed to support community energy resilience, disaster preparedness, and energy bill reductions, particularly for residents of low-income and environmental justice communities. The Agency may propose the funding amount, structure, and details of the Illinois Storage for All Program in the Agency's long-term renewable resources procurement plan described in subsection (c) of Section 1-75 of this Act and Section 16-111.5 of the Public Utilities Act, or through its energy storage resources procurement plan described in subsection (d-20) of Section 1-75 of this Act. As part of the development of its initial energy storage resources procurement plan, the Agency shall engage stakeholders in the development of the Illinois Storage for All Program, including, but not limited to, members of the Illinois Commission on Environmental Justice described in Section 10 of the Environmental Justice Act, representatives of approved vendors participating in the Illinois Solar for All Program, representatives of community-based organizations, and members of the Illinois Solar for All Stakeholder Advisory Group. The stakeholder process shall include, but not be limited to, an exploration of how to ensure that the distributed storage will be accessible to income-qualified households with zero upfront costs and in coordination with job training programs, as well as how the program may be supported by other programs or initiatives to maximize storage benefits and limit double-counting of incentives.

(4) The Agency shall, consistent with the requirements of this subsection (b), propose the Illinois Solar for All Program terms, conditions, and requirements, including the prices to be paid for renewable energy credits, and which prices may be determined through a formula, through the development, review, and approval of the Agency's long-term renewable resources procurement plan described in subsection (c) of Section 1-75 of this Act and Section 16-111.5 of the Public Utilities Act. In the course of the Commission proceeding initiated to review and approve the plan, including the Illinois Solar for All Program proposed by the Agency, a party may propose an additional low-income solar or solar incentive program, or modifications to the programs proposed by the Agency, and the Commission may approve an additional program, or modifications to the Agency's proposed program, if the additional or modified program more effectively maximizes the benefits to low-income customers after taking into account all relevant factors, including, but not limited to, the extent to which a competitive market for low-income solar has developed. Following the Commission's approval of the Illinois Solar for All Program, the Agency or a party may propose adjustments to the program terms, conditions, and requirements, including the price offered to new systems, to ensure the long-term viability and success of the program. The Commission shall review and approve any modifications to the program through the plan revision process described in Section 16-111.5 of the Public Utilities Act.

(5) The Agency shall issue a request for qualifications for a third-party program administrator or administrators to administer all or a portion of the Illinois Solar for All Program. The third-party program administrator shall be chosen through a competitive bid process based on selection criteria and requirements developed by the Agency, including, but not limited to, experience in administering low-income energy programs and overseeing statewide clean energy or energy efficiency services. If the Agency retains a program administrator or administrators to implement all or a portion of the Illinois Solar for All Program, each administrator shall periodically submit reports to the Agency and Commission for each program that it administers, at appropriate intervals to be identified by the Agency in its long-term renewable resources procurement plan, subject to Commission approval, provided that the reporting interval is at least an annual period quarterly. The third-party program administrator may be, but need not be, the same administrator as for the Adjustable Block program described in subparagraphs (K) through (M) of paragraph (1) of subsection (c) of Section 1-75. The Agency, through its long-term renewable resources procurement plan approval process, shall also determine if individual subprograms of the Illinois Solar for All Program are better served by a different or separate Program Administrator.

The third-party administrator's responsibilities shall also include facilitating placement for graduates of Illinois-based renewable energy-specific job training programs, including the Clean Jobs Workforce Network Program and the Illinois Climate Works Preapprenticeship Program administered by the Department of Commerce and Economic Opportunity and programs administered under Section 16-108.12 of the Public Utilities Act. To increase the uptake of trainees by participating firms, the administrator shall also develop a web-based clearinghouse for information available to both job training program graduates and firms participating, directly or indirectly, in Illinois solar incentive programs. The program administrator shall also coordinate its activities with entities implementing electric and natural gas income-qualified energy efficiency programs, including customer referrals to and from such programs, and connect prospective low-income solar customers with any existing deferred maintenance programs where applicable.

(6) The long-term renewable resources procurement plan shall also provide for an independent evaluation of the Illinois Solar for All Program. At least every 5 2 years, the Agency shall select an independent evaluator to review and report on the Illinois Solar for All Program and the performance of the third-party program administrator of the Illinois Solar for All Program. The evaluation shall be based on objective criteria developed through a public stakeholder process. The process shall include feedback and participation from Illinois Solar for All Program stakeholders, including participants and organizations in environmental justice and historically underserved communities. The report shall include a summary of the evaluation of the Illinois Solar for All Program based on the stakeholder developed objective criteria. The report shall include the number of projects installed; the total installed capacity in kilowatts; the average cost per kilowatt of installed capacity to the extent reasonably obtainable by the Agency; the number of jobs or job opportunities created; economic, social, and environmental benefits created; and the total administrative costs expended by the Agency and program administrator to implement and evaluate the program. The report shall be prepared at least every 2 years and shall be delivered to the Commission and posted on the Agency's website, and shall be used, as needed, to revise the Illinois Solar for All Program. The Commission shall also consider the results of the evaluation as part of its review of the long-term renewable resources procurement plan under subsection (c) of Section 1-75 of this Act.

(7) If additional funding for the programs described in this subsection (b) is available under subsection (k) of Section 16-108 of the Public Utilities Act, then the Agency shall submit a procurement plan to the Commission no later than September 1, 2018, that proposes how the Agency will procure programs on behalf of the applicable utility. After notice and hearing, the Commission shall approve, or approve with modification, the plan no later than November 1, 2018.

(8) As part of the development and update of the long-term renewable resources procurement plan authorized by subsection (c) of Section 1-75 of this Act, the Agency shall plan for: (A) actions to refer customers from the Illinois Solar for All Program to electric and natural gas income-qualified energy efficiency programs, and vice versa, with the goal of increasing participation in both of these programs; (B) effective procedures for data sharing, as needed, to effectuate referrals between the Illinois Solar for All Program and both electric and natural gas income-qualified energy efficiency programs, including sharing customer information directly with the utilities, as needed and appropriate; and (C) efforts to identify any existing deferred maintenance programs for which prospective Solar for All Program customers may be eligible and connect prospective customers for whom deferred maintenance is or may be a barrier to solar installation to those programs.

Income verification for participation in the Illinois Solar for All subprograms described in subparagraphs (A) and (C) of paragraph (2) may include pathways for verification that rely on self-attestation by the applicant if the applicant's residence is located within a low-income or environmental justice community as defined in this subsection (b). The Agency shall proactively explore approaches that make the income verification process less burdensome for residents of low-income or environmental justice communities, as defined in this subsection (b).

As used in this subsection (b), "low-income households" means persons and families whose income does not exceed 80% of area median income, adjusted for family size and revised every year.

For the purposes of this subsection (b), the Agency shall define "environmental justice community" based on the methodologies and findings established by the Agency and the Administrator for the Illinois Solar for All Program in its initial long-term renewable resources procurement plan and as updated by the Agency and the Administrator for the Illinois Solar for All Program as part of the long-term renewable resources procurement plan update.

(b-5) After the receipt of all payments required by Section 16-115D of the Public Utilities Act, no additional funds shall be deposited into the Illinois Power Agency Renewable Energy Resources Fund unless directed by order of the Commission.

(b-10) After the receipt of all payments required by Section 16-115D of the Public Utilities Act and payment in full of all contracts executed by the Agency under subsections (b) and (i) of this Section, if the balance of the Illinois Power Agency Renewable Energy Resources Fund is under $5,000, then the Fund shall be inoperative and any remaining funds and any funds submitted to the Fund after that date, shall be transferred to the Supplemental Low-Income Energy Assistance Fund for use in the Low-Income Home Energy Assistance Program, as authorized by the Energy Assistance Act.

(b-15) The prevailing wage requirements set forth in the Prevailing Wage Act apply to each project that is undertaken pursuant to one or more of the programs of incentives and initiatives described in subsection (b) of this Section and for which a project application is submitted to the program after June 30, 2023 (the effective date of Public Act 103-188) this amendatory Act of the 103rd General Assembly, except (i) projects that serve single-family or multi-family residential buildings and (ii) projects with an aggregate capacity of less than 100 kilowatts that serve houses of worship. The Agency shall require verification that all construction performed on a project by the renewable energy credit delivery contract holder, its contractors, or its subcontractors relating to the construction of the facility is performed by workers receiving an amount for that work that is greater than or equal to the general prevailing rate of wages as that term is defined in the Prevailing Wage Act, and the Agency may adjust renewable energy credit prices to account for increased labor costs.

In this subsection (b-15), "house of worship" has the meaning given in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75.

(c) (Blank).

(d) (Blank).

(e) All renewable energy credits procured using monies from the Illinois Power Agency Renewable Energy Resources Fund shall be permanently retired.

(f) The selection of one or more third-party program managers or administrators, the selection of the independent evaluator, and the procurement processes described in this Section are exempt from the requirements of the Illinois Procurement Code, under Section 20-10 of that Code.

(g) All disbursements from the Illinois Power Agency Renewable Energy Resources Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Director or by the person or persons designated by the Director for that purpose. The Comptroller is authorized to draw the warrant upon vouchers so signed. The Treasurer shall accept all warrants so signed and shall be released from liability for all payments made on those warrants.

(h) The Illinois Power Agency Renewable Energy Resources Fund shall not be subject to sweeps, administrative charges, or chargebacks, including, but not limited to, those authorized under Section 8h of the State Finance Act, that would in any way result in the transfer of any funds from this Fund to any other fund of this State or in having any such funds utilized for any purpose other than the express purposes set forth in this Section.

(h-5) The Agency may assess fees to each bidder to recover the costs incurred in connection with a procurement process held under this Section. Fees collected from bidders shall be deposited into the Illinois Power Agency Renewable Energy Resources Fund.

(i) Supplemental procurement process.

(1) Within 90 days after June 30, 2014 (the effective date of Public Act 98-672), the Agency shall develop a one-time supplemental procurement plan limited to the procurement of renewable energy credits, if available, from new or existing photovoltaics, including, but not limited to, distributed photovoltaic generation. Nothing in this subsection (i) requires procurement of wind generation through the supplemental procurement.

Renewable energy credits procured from new photovoltaics, including, but not limited to, distributed photovoltaic generation, under this subsection (i) must be procured from devices installed by a qualified person. In its supplemental procurement plan, the Agency shall establish contractually enforceable mechanisms for ensuring that the installation of new photovoltaics is performed by a qualified person.

For the purposes of this paragraph (1), "qualified person" means a person who performs installations of photovoltaics, including, but not limited to, distributed photovoltaic generation, and who: (A) has completed an apprenticeship as a journeyman electrician from a United States Department of Labor registered electrical apprenticeship and training program and received a certification of satisfactory completion; or (B) does not currently meet the criteria under clause (A) of this paragraph (1), but is enrolled in a United States Department of Labor registered electrical apprenticeship program, provided that the person is directly supervised by a person who meets the criteria under clause (A) of this paragraph (1); or (C) has obtained one of the following credentials in addition to attesting to satisfactory completion of at least 5 years or 8,000 hours of documented hands-on electrical experience: (i) a North American Board of Certified Energy Practitioners (NABCEP) Installer Certificate for Solar PV; (ii) an Underwriters Laboratories (UL) PV Systems Installer Certificate; (iii) an Electronics Technicians Association, International (ETAI) Level 3 PV Installer Certificate; or (iv) an Associate in Applied Science degree from an Illinois Community College Board approved community college program in renewable energy or a distributed generation technology.

For the purposes of this paragraph (1), "directly supervised" means that there is a qualified person who meets the qualifications under clause (A) of this paragraph (1) and who is available for supervision and consultation regarding the work performed by persons under clause (B) of this paragraph (1), including a final inspection of the installation work that has been directly supervised to ensure safety and conformity with applicable codes.

For the purposes of this paragraph (1), "install" means the major activities and actions required to connect, in accordance with applicable building and electrical codes, the conductors, connectors, and all associated fittings, devices, power outlets, or apparatuses mounted at the premises that are directly involved in delivering energy to the premises' electrical wiring from the photovoltaics, including, but not limited to, to distributed photovoltaic generation.

The renewable energy credits procured pursuant to the supplemental procurement plan shall be procured using up to $30,000,000 from the Illinois Power Agency Renewable Energy Resources Fund. The Agency shall not plan to use funds from the Illinois Power Agency Renewable Energy Resources Fund in excess of the monies on deposit in such fund or projected to be deposited into such fund. The supplemental procurement plan shall ensure adequate, reliable, affordable, efficient, and environmentally sustainable renewable energy resources (including credits) at the lowest total cost over time, taking into account any benefits of price stability.

To the extent available, 50% of the renewable energy credits procured from distributed renewable energy generation shall come from devices of less than 25 kilowatts in nameplate capacity. Procurement of renewable energy credits from distributed renewable energy generation devices shall be done through multi-year contracts of no less than 5 years. The Agency shall create credit requirements for counterparties. In order to minimize the administrative burden on contracting entities, the Agency shall solicit the use of third parties to aggregate distributed renewable energy. These third parties shall enter into and administer contracts with individual distributed renewable energy generation device owners. An individual distributed renewable energy generation device owner shall have the ability to measure the output of his or her distributed renewable energy generation device.

In developing the supplemental procurement plan, the Agency shall hold at least one workshop open to the public within 90 days after June 30, 2014 (the effective date of Public Act 98-672) and shall consider any comments made by stakeholders or the public. Upon development of the supplemental procurement plan within this 90-day period, copies of the supplemental procurement plan shall be posted and made publicly available on the Agency's and Commission's websites. All interested parties shall have 14 days following the date of posting to provide comment to the Agency on the supplemental procurement plan. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the supplemental procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. Within 14 days following the end of the 14-day review period, the Agency shall revise the supplemental procurement plan as necessary based on the comments received and file its revised supplemental procurement plan with the Commission for approval.

(2) Within 5 days after the filing of the supplemental procurement plan at the Commission, any person objecting to the supplemental procurement plan shall file an objection with the Commission. Within 10 days after the filing, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the supplemental procurement plan within 90 days after the filing of the supplemental procurement plan by the Agency.

(3) The Commission shall approve the supplemental procurement plan of renewable energy credits to be procured from new or existing photovoltaics, including, but not limited to, distributed photovoltaic generation, if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service in the form of renewable energy credits at the lowest total cost over time, taking into account any benefits of price stability.

(4) The supplemental procurement process under this subsection (i) shall include each of the following components:

(A) Procurement administrator. The Agency may retain a procurement administrator in the manner set forth in item (2) of subsection (a) of Section 1-75 of this Act to conduct the supplemental procurement or may elect to use the same procurement administrator administering the Agency's annual procurement under Section 1-75.

(B) Procurement monitor. The procurement monitor retained by the Commission pursuant to Section 16-111.5 of the Public Utilities Act shall:

(i) monitor interactions among the procurement administrator and bidders and suppliers;

(ii) monitor and report to the Commission on the progress of the supplemental procurement process;

(iii) provide an independent confidential report to the Commission regarding the results of the procurement events;

(iv) assess compliance with the procurement plan approved by the Commission for the supplemental procurement process;

(v) preserve the confidentiality of supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;

(vi) provide expert advice to the Commission and consult with the procurement administrator regarding issues related to procurement process design, rules, protocols, and policy-related matters;

(vii) consult with the procurement administrator regarding the development and use of benchmark criteria, standard form contracts, credit policies, and bid documents; and

(viii) perform, with respect to the supplemental procurement process, any other procurement monitor duties specifically delineated within subsection (i) of this Section.

(C) Solicitation, prequalification, and registration of bidders. The procurement administrator shall disseminate information to potential bidders to promote a procurement event, notify potential bidders that the procurement administrator may enter into a post-bid price negotiation with bidders that meet the applicable benchmarks, provide supply requirements, and otherwise explain the competitive procurement process. In addition to such other publication as the procurement administrator determines is appropriate, this information shall be posted on the Agency's and the Commission's websites. The procurement administrator shall also administer the prequalification process, including evaluation of credit worthiness, compliance with procurement rules, and agreement to the standard form contract developed pursuant to item (D) of this paragraph (4). The procurement administrator shall then identify and register bidders to participate in the procurement event.

(D) Standard contract forms and credit terms and instruments. The procurement administrator, in consultation with the Agency, the Commission, and other interested parties and subject to Commission oversight, shall develop and provide standard contract forms for the supplier contracts that meet generally accepted industry practices as well as include any applicable State of Illinois terms and conditions that are required for contracts entered into by an agency of the State of Illinois. Standard credit terms and instruments that meet generally accepted industry practices shall be similarly developed. Contracts for new photovoltaics shall include a provision attesting that the supplier will use a qualified person for the installation of the device pursuant to paragraph (1) of subsection (i) of this Section. The procurement administrator shall make available to the Commission all written comments it receives on the contract forms, credit terms, or instruments. If the procurement administrator cannot reach agreement with the parties as to the contract terms and conditions, the procurement administrator must notify the Commission of any disputed terms and the Commission shall resolve the dispute. The terms of the contracts shall not be subject to negotiation by winning bidders, and the bidders must agree to the terms of the contract in advance so that winning bids are selected solely on the basis of price.

(E) Requests for proposals; competitive procurement process. The procurement administrator shall design and issue requests for proposals to supply renewable energy credits in accordance with the supplemental procurement plan, as approved by the Commission. The requests for proposals shall set forth a procedure for sealed, binding commitment bidding with pay-as-bid settlement, and provision for selection of bids on the basis of price, provided, however, that no bid shall be accepted if it exceeds the benchmark developed pursuant to item (F) of this paragraph (4).

(F) Benchmarks. Benchmarks for each product to be procured shall be developed by the procurement administrator in consultation with Commission staff, the Agency, and the procurement monitor for use in this supplemental procurement.

(G) A plan for implementing contingencies in the event of supplier default, Commission rejection of results, or any other cause.

(5) Within 2 business days after opening the sealed bids, the procurement administrator shall submit a confidential report to the Commission. The report shall contain the results of the bidding for each of the products along with the procurement administrator's recommendation for the acceptance and rejection of bids based on the price benchmark criteria and other factors observed in the process. The procurement monitor also shall submit a confidential report to the Commission within 2 business days after opening the sealed bids. The report shall contain the procurement monitor's assessment of bidder behavior in the process as well as an assessment of the procurement administrator's compliance with the procurement process and rules. The Commission shall review the confidential reports submitted by the procurement administrator and procurement monitor and shall accept or reject the recommendations of the procurement administrator within 2 business days after receipt of the reports.

(6) Within 3 business days after the Commission decision approving the results of a procurement event, the Agency shall enter into binding contractual arrangements with the winning suppliers using the standard form contracts.

(7) The names of the successful bidders and the average of the winning bid prices for each contract type and for each contract term shall be made available to the public within 2 days after the supplemental procurement event. The Commission, the procurement monitor, the procurement administrator, the Agency, and all participants in the procurement process shall maintain the confidentiality of all other supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs. Confidential information, including the confidential reports submitted by the procurement administrator and procurement monitor pursuant to this Section, shall not be made publicly available and shall not be discoverable by any party in any proceeding, absent a compelling demonstration of need, nor shall those reports be admissible in any proceeding other than one for law enforcement purposes.

(8) The supplemental procurement provided in this subsection (i) shall not be subject to the requirements and limitations of subsections (c) and (d) of this Section.

(9) Expenses incurred in connection with the procurement process held pursuant to this Section, including, but not limited to, the cost of developing the supplemental procurement plan, the procurement administrator, procurement monitor, and the cost of the retirement of renewable energy credits purchased pursuant to the supplemental procurement shall be paid for from the Illinois Power Agency Renewable Energy Resources Fund. The Agency shall enter into an interagency agreement with the Commission to reimburse the Commission for its costs associated with the procurement monitor for the supplemental procurement process.

(Source: P.A. 102-662, eff. 9-15-21; 103-188, eff. 6-30-23; 103-605, eff. 7-1-24; 103-1066, eff. 2-20-25; revised 6-23-25.)

(20 ILCS 3855/1-75)

Sec. 1-75. Planning and Procurement Bureau. The Planning and Procurement Bureau has the following duties and responsibilities:

(a) The Planning and Procurement Bureau shall each year, beginning in 2008, develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois. Beginning with the delivery year commencing on June 1, 2017, the Planning and Procurement Bureau shall develop plans and processes for the procurement of zero emission credits from zero emission facilities in accordance with the requirements of subsection (d-5) of this Section. Beginning on the effective date of this amendatory Act of the 102nd General Assembly, the Planning and Procurement Bureau shall develop plans and processes for the procurement of carbon mitigation credits from carbon-free energy resources in accordance with the requirements of subsection (d-10) of this Section. The Planning and Procurement Bureau shall also develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Agency to prepare a procurement plan for their Illinois jurisdictional load. For the purposes of this Section, the term "eligible retail customers" has the same definition as found in Section 16-111.5(a) of the Public Utilities Act.

Beginning with the plan or plans to be implemented in the 2017 delivery year, the Agency shall no longer include the procurement of renewable energy resources in the annual procurement plans required by this subsection (a), except as provided in subsection (q) of Section 16-111.5 of the Public Utilities Act, and shall instead develop a long-term renewable resources procurement plan in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act.

In accordance with subsection (c-5) of this Section, the Planning and Procurement Bureau shall oversee the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new utility-scale solar projects to be installed, along with energy storage facilities, at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source.

(1) The Agency shall each year, beginning in 2008, as needed, issue a request for qualifications for experts or expert consulting firms to develop the procurement plans in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience assembling large-scale power supply plans or portfolios for end-use customers;

(B) an advanced degree in economics, mathematics, engineering, risk management, or a related area of study;

(C) 10 years of experience in the electricity sector, including managing supply risk;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit protocols and familiarity with contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(2) The Agency shall each year, as needed, issue a request for qualifications for a procurement administrator to conduct the competitive procurement processes in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience administering a large-scale competitive procurement process;

(B) an advanced degree in economics, mathematics, engineering, or a related area of study;

(C) 10 years of experience in the electricity sector, including risk management experience;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit and contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(3) The Agency shall provide affected utilities and other interested parties with the lists of qualified experts or expert consulting firms identified through the request for qualifications processes that are under consideration to develop the procurement plans and to serve as the procurement administrator. The Agency shall also provide each qualified expert's or expert consulting firm's response to the request for qualifications. All information provided under this subparagraph shall also be provided to the Commission. The Agency may provide by rule for fees associated with supplying the information to utilities and other interested parties. These parties shall, within 5 business days, notify the Agency in writing if they object to any experts or expert consulting firms on the lists. Objections shall be based on:

(A) failure to satisfy qualification criteria;

(B) identification of a conflict of interest; or

(C) evidence of inappropriate bias for or against potential bidders or the affected utilities.

The Agency shall remove experts or expert consulting firms from the lists within 10 days if there is a reasonable basis for an objection and provide the updated lists to the affected utilities and other interested parties. If the Agency fails to remove an expert or expert consulting firm from a list, an objecting party may seek review by the Commission within 5 days thereafter by filing a petition, and the Commission shall render a ruling on the petition within 10 days. There is no right of appeal of the Commission's ruling.

(4) The Agency shall issue requests for proposals to the qualified experts or expert consulting firms to develop a procurement plan for the affected utilities and to serve as procurement administrator.

(5) The Agency shall select an expert or expert consulting firm to develop procurement plans based on the proposals submitted and shall award contracts of up to 5 years to those selected.

(6) The Agency shall select an expert or expert consulting firm, with approval of the Commission, to serve as procurement administrator based on the proposals submitted. If the Commission rejects, within 5 days, the Agency's selection, the Agency shall submit another recommendation within 3 days based on the proposals submitted. The Agency shall award a 5-year contract to the expert or expert consulting firm so selected with Commission approval.

(b) The experts or expert consulting firms retained by the Agency shall, as appropriate, prepare procurement plans, and conduct a competitive procurement process as prescribed in Section 16-111.5 of the Public Utilities Act, to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in the State of Illinois, and for eligible Illinois retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load.

(c) Renewable portfolio standard.

(1)(A) The Agency shall develop a long-term renewable resources procurement plan that shall include procurement programs and competitive procurement events necessary to meet the goals set forth in this subsection (c). The initial long-term renewable resources procurement plan shall be released for comment no later than 160 days after June 1, 2017 (the effective date of Public Act 99-906). The Agency shall review, and may revise on an expedited basis, the long-term renewable resources procurement plan at least every 2 years, which shall be conducted in conjunction with the procurement plan under Section 16-111.5 of the Public Utilities Act to the extent practicable to minimize administrative expense. No later than 120 days after the effective date of this amendatory Act of the 103rd General Assembly, the Agency shall release for comment a revision to the long-term renewable resources procurement plan, updating elements of the most recently approved plan as needed to comply with this amendatory Act of the 103rd General Assembly, and any long-term renewable resources procurement plan update published by the Agency but not yet approved by the Illinois Commerce Commission shall be withdrawn. The long-term renewable resources procurement plans shall be subject to review and approval by the Commission under Section 16-111.5 of the Public Utilities Act.

(B) Subject to subparagraph (F) of this paragraph (1), the long-term renewable resources procurement plan shall attempt to meet the goals for procurement of renewable energy credits at levels of at least the following overall percentages: 13% by the 2017 delivery year; increasing by at least 1.5% each delivery year thereafter to at least 25% by the 2025 delivery year; increasing by at least 3% each delivery year thereafter to at least 40% by the 2030 delivery year, and continuing at no less than 40% for each delivery year thereafter. The Agency shall attempt to procure 50% by delivery year 2040. The Agency shall determine the annual increase between delivery year 2030 and delivery year 2040, if any, taking into account energy demand, other energy resources, and other public policy goals. In the event of a conflict between these goals and the new wind, new photovoltaic, and hydropower procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1), the long-term plan shall prioritize compliance with the new wind, new photovoltaic, and hydropower procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1) over the annual percentage targets described in this subparagraph (B). The Agency shall not comply with the annual percentage targets described in this subparagraph (B) by procuring renewable energy credits that are unlikely to lead to the development of new renewable resources or new, modernized, or retooled hydropower facilities.

For the delivery year beginning June 1, 2017, the procurement plan shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to at least 13% of each utility's load for eligible retail customers and 13% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 50% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2018, the procurement plan shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to at least 14.5% of each utility's load for eligible retail customers and 14.5% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 75% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2019, and for each year thereafter, the procurement plans shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to a minimum percentage of each utility's load for all retail customers as follows: 16% by June 1, 2019; increasing by 1.5% each year thereafter to 25% by June 1, 2025; and 25% by June 1, 2026; increasing by at least 3% each delivery year thereafter to at least 40% by the 2030 delivery year, and continuing at no less than 40% for each delivery year thereafter. The Agency shall attempt to procure 50% by delivery year 2040. The Agency shall determine the annual increase between delivery year 2030 and delivery year 2040, if any, taking into account energy demand, other energy resources, and other public policy goals.

For each delivery year, the Agency shall first recognize each utility's obligations for that delivery year under existing contracts. Any renewable energy credits under existing contracts, including renewable energy credits as part of renewable energy resources, shall be used to meet the goals set forth in this subsection (c) for the delivery year.

(C) The long-term renewable resources procurement plan described in subparagraph (A) of this paragraph (1) shall include the procurement of renewable energy credits from new projects pursuant to the following terms:

(i) At least 10,000,000 renewable energy credits delivered annually by the end of the 2021 delivery year, and increasing ratably to reach 45,000,000 renewable energy credits delivered annually from new wind and solar projects, from repowered wind projects, or from retooled hydropower facilities by the end of delivery year 2030 such that the goals in subparagraph (B) of this paragraph (1) are met entirely by procurements of renewable energy credits from new wind and photovoltaic projects. Of that amount, to the extent possible, the Agency shall endeavor to procure 45% from new and repowered wind and hydropower projects and shall procure at least 55% from photovoltaic projects. Of the amount to be procured from photovoltaic projects, the Agency shall procure: at least 50% from solar photovoltaic projects using the program outlined in subparagraph (K) of this paragraph (1) from distributed renewable energy generation devices or community renewable generation projects; at least 47% from utility-scale solar projects; at least 3% from brownfield site photovoltaic projects that are not community renewable generation projects. The Agency may propose adjustments to these percentages, including establishing percentage-based goals for the procurement of renewable energy credits from modernized or retooled hydropower facilities and repowered wind projects, through its long-term renewable resources plan described in subparagraph (A) of this paragraph (1) as necessary based on developer interest, market conditions, budget considerations, resource adequacy needs, or other factors.

In developing the long-term renewable resources procurement plan, the Agency shall consider other approaches, in addition to competitive procurements, that can be used to procure renewable energy credits from brownfield site photovoltaic projects and thereby help return blighted or contaminated land to productive use while enhancing public health and the well-being of Illinois residents, including those in environmental justice communities, as defined using existing methodologies and findings used by the Agency and its Administrator in its Illinois Solar for All Program. The Agency shall also consider other approaches, in addition to competitive procurements, to procure renewable energy credits from new and existing hydropower facilities to support the development and maintenance of these facilities. The Agency shall explore options to convert existing dams but shall not consider approaches to develop new dams where they do not already exist. To encourage the continued operation of utility-scale wind projects, the Agency shall consider and may propose other approaches in addition to competitive procurements to procure renewable energy credits from repowered wind projects.

(ii) In any given delivery year, if forecasted expenses are less than the maximum budget available under subparagraph (E) of this paragraph (1), the Agency shall continue to procure new renewable energy credits until that budget is exhausted in the manner outlined in item (i) of this subparagraph (C).

(iii) For purposes of this Section:

"New wind projects" means wind renewable energy facilities that are energized after June 1, 2017 for the delivery year commencing June 1, 2017.

"New photovoltaic projects" means photovoltaic renewable energy facilities that are energized after June 1, 2017. Photovoltaic projects developed under Section 1-56 of this Act shall not apply towards the new photovoltaic project requirements in this subparagraph (C).

"Repowered wind projects" means utility-scale wind projects featuring the removal, replacement, or expansion of turbines at an existing project site, as defined in the long-term renewable resources procurement plan, after the effective date of this amendatory Act of the 103rd General Assembly. Renewable energy credit contract awards used to support repowered wind projects shall only cover the incremental increase in facility electricity production resultant from repowering.

For purposes of calculating whether the Agency has procured enough new wind and solar renewable energy credits required by this subparagraph (C), renewable energy facilities that have a multi-year renewable energy credit delivery contract with the utility through at least delivery year 2030 shall be considered new, however no renewable energy credits from contracts entered into before June 1, 2021 shall be used to calculate whether the Agency has procured the correct proportion of new wind and new solar contracts described in this subparagraph (C) for delivery year 2021 and thereafter.

(iv) The Agency may implement additional measures, including eligibility requirements, to ensure that new wind projects and new photovoltaic projects supported through renewable energy credit contract awards are a result of a contract award and are otherwise developed pursuant to the financial certainty provided through a contract award.

(D) Renewable energy credits shall be cost effective. For purposes of this subsection (c), "cost effective" means that the costs of procuring renewable energy resources do not cause the limit stated in subparagraph (E) of this paragraph (1) to be exceeded and, for renewable energy credits procured through a competitive procurement event, do not exceed benchmarks based on market prices for like products in the region. For purposes of this subsection (c), "like products" means contracts for renewable energy credits from the same or substantially similar technology, same or substantially similar vintage (new or existing), the same or substantially similar quantity, and the same or substantially similar contract length and structure. Benchmarks shall reflect development, financing, or related costs resulting from requirements imposed through other provisions of State law, including, but not limited to, requirements in subparagraphs (P) and (Q) of this paragraph (1) and the Renewable Energy Facilities Agricultural Impact Mitigation Act. Confidential benchmarks shall be developed by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval. If price benchmarks for like products in the region are not available, the procurement administrator shall establish price benchmarks based on publicly available data on regional technology costs and expected current and future regional energy prices. The benchmarks in this Section shall not be used to curtail or otherwise reduce contractual obligations entered into by or through the Agency prior to June 1, 2017 (the effective date of Public Act 99-906).

(E) For purposes of this subsection (c), the required procurement of cost-effective renewable energy resources for a particular year commencing prior to June 1, 2017 shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the delivery year ending immediately prior to the procurement, and, for delivery years commencing on and after June 1, 2017, the required procurement of cost-effective renewable energy resources for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) delivered by the electric utility in the delivery year ending immediately prior to the procurement, to all retail customers in its service territory. For purposes of this subsection (c), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (c), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, capacity, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (c), and except as provided in subparagraph (E-5) of paragraph (1) of this subsection (c) or except as otherwise authorized by the Commission in its approval of the integrated resource plan under Section 16-202 of the Public Utilities Act, the total of renewable energy resources procured under the procurement plan for any single year shall be subject to the limitations of this subparagraph (E). Such procurement shall be reduced for all retail customers based on the amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than 4.25% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009, adjusted annually for inflation starting with the first adjustment in the delivery year commencing June 1, 2026. For the purposes of this Section, the inflation adjustment shall not be accrued or applied retroactively prior to the effective date of this amendatory Act of the 104th General Assembly and shall apply prospectively starting in 2025. The limitation shall be increased by an additional 1.65 percentage points of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009 starting with the delivery year commencing June 1, 2027. To arrive at a maximum dollar amount of renewable energy resources to be procured for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered, or applicable portion of such amount as specified in paragraph (1) of this subsection (c), as applicable, by the electric utility in the delivery year immediately prior to the procurement to all retail customers in its service territory. The calculations required by this subparagraph (E) shall be made only once for each delivery year at the time that the renewable energy resources are procured. Once the determination as to the amount of renewable energy resources to procure is made based on the calculations set forth in this subparagraph (E) and the contracts procuring those amounts are executed between the seller and applicable electric utility, no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. As provided in subparagraph (E-5) of paragraph (1) of this subsection (c), the seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this subparagraph (E), and all costs incurred under such contracts shall be fully recoverable by the electric utility as provided in this Section.

(E-5) If, for a particular delivery year, the limitation on the amount of renewable energy resources to be procured, as calculated pursuant to subparagraph (E) of paragraph (1) of this subsection (c), would result in an insufficient collection of funds to fully pay amounts due to a seller under existing contracts executed under this Section or executed under Section 1-56 of this Act, then the following provisions shall apply to ensure full and uninterrupted payment is made to such seller or sellers:

(i) If the electric utility has retained unspent funds in an interest-bearing account as prescribed in subsection (k) of Section 16-108 of the Public Utilities Act, then the utility shall use those funds to remit full payment to the sellers to ensure prompt and uninterrupted payment of existing contractual obligation.

(ii) If the funds described in item (i) of this subparagraph (E-5) are insufficient to satisfy all existing contractual obligations, then the electric utility shall, nonetheless, remit full payment to the sellers to ensure prompt and uninterrupted payment of existing contractual obligations, provided that the full costs shall be recoverable by the utility in accordance with part (ee) of item (iv) of this subsection (E-5).

(iii) The Agency shall promptly notify the Commission that existing contractual obligations are reasonably expected to exceed the maximum collection authorized under subparagraph (E) of paragraph (1) of this subsection (c) for the applicable delivery year. The Agency shall also explain and confirm how the operation of items (i) and (ii) of this subparagraph (E-5) ensures that the electric utility will continue to make prompt and uninterrupted payment under existing contractual obligations. The Agency shall provide this information to the Commission through a notice filed in the Commission docket approving the Agency's operative Long-Term Renewable Resources Procurement Plan that includes the applicable delivery year.

(iv) The Agency shall suspend or reduce new contract awards for the procurement of renewable energy credits until an Agency determination is made under subparagraph (E) that additional procurements would not cause the rate impact limitation of subparagraph (E) to be exceeded. At least once annually after the notice provided for in item (iii) of this subparagraph (E-5) is made, the Agency shall analyze existing contract obligations, projected prices for indexed renewable energy credit contracts executed under item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act, and expected collections authorized under subparagraph (E) to determine whether and to what extent the limitations of subparagraph (E) would be exceeded by additional renewable energy credit procurement contract awards.

(aa) If the Agency determines that additional renewable energy credit procurement contract awards could be made without exceeding the limitations of subparagraph (E), then the procurements shall be authorized at a scale determined not to exceed the limitations of subparagraph (E) in a manner consistent with the priorities of this Section.

(bb) If the Agency determines that additional renewable energy credit procurement contract awards cannot be made without exceeding the limitations of subparagraph (E), then the Agency shall suspend any new contract awards for the procurement of renewable energy credits until a new rate impact determination is made under subparagraph (E).

(cc) Agency determinations made under this item (iv) shall be detailed and comprehensive and, if not made through the Agency's Long-Term Renewable Resources Procurement Plan, shall be filed as a compliance filing in the most recent docketed proceeding approving the Agency's Long-Term Renewable Resources Procurement Plan.

(dd) With respect to the procurement of renewable energy credits authorized through programs administered under subsection (b) of Section 1-56 and subparagraphs (K) through (M) of paragraph (1) of subsection (k) of Section 1-75 of this Act, the award of contracts for the procurement of renewable energy credits shall be suspended or reduced only at the conclusion of the program year in which the notice provided for under item (iii) of this subparagraph (E-5) is made.

(ee) The contract shall provide that, so long as at least one of: (i) the cost recovery mechanisms referenced in subsection (k) of Section 16-108 and subsection (l) of Section 16-111.5 of the Public Utilities Act remains in full force without limitation or (ii) the utility is otherwise authorized and or entitled to full, prompt, and uninterrupted recovery of its costs through any other mechanism, then such seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this subparagraph (E).

(F) If the limitation on the amount of renewable energy resources procured in subparagraph (E) of this paragraph (1) prevents the Agency from meeting all of the goals in this subsection (c), the Agency's long-term plan shall prioritize compliance with the requirements of this subsection (c) regarding renewable energy credits in the following order:

(i) renewable energy credits under existing contractual obligations as of June 1, 2021;

(i-5) funding for the Illinois Solar for All Program, as described in subparagraph (O) of this paragraph (1);

(ii) renewable energy credits necessary to comply with the new wind and new photovoltaic procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1); and

(iii) renewable energy credits necessary to meet the remaining requirements of this subsection (c).

(G) The following provisions shall apply to the Agency's procurement of renewable energy credits under this subsection (c):

(i) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale wind projects within 160 days after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale wind projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(ii) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects within one year after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale solar projects and brownfield site photovoltaic projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. The Agency may structure this initial procurement in one or more discrete procurement events. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(iii) Notwithstanding whether the Commission has approved the periodic long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall conduct at least one subsequent forward procurement for renewable energy credits from new utility-scale wind projects, new utility-scale solar projects, and new brownfield site photovoltaic projects within 240 days after the effective date of this amendatory Act of the 102nd General Assembly in quantities necessary to meet the requirements of subparagraph (C) of this paragraph (1) through the delivery year beginning June 1, 2021.

(iv) Notwithstanding whether the Commission has approved the periodic long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall open capacity for each category in the Adjustable Block program within 90 days after the effective date of this amendatory Act of the 102nd General Assembly manner:

(1) The Agency shall open the first block of annual capacity for the category described in item (i) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (i) shall be for at least 75 megawatts of total nameplate capacity. The price of the renewable energy credit for this block of capacity shall be 4% less than the price of the last open block in this category. Projects on a waitlist shall be awarded contracts first in the order in which they appear on the waitlist. Notwithstanding anything to the contrary, for those renewable energy credits that qualify and are procured under this subitem (1) of this item (iv), the renewable energy credit delivery contract value shall be paid in full, based on the estimated generation during the first 15 years of operation, by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and in compliance by the Program Administrator. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(2) The Agency shall open the first block of annual capacity for the category described in item (ii) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (ii) shall be for at least 75 megawatts of total nameplate capacity.

(A) The price of the renewable energy credit for any project on a waitlist for this category before the opening of this block shall be 4% less than the price of the last open block in this category. Projects on the waitlist shall be awarded contracts first in the order in which they appear on the waitlist. Any projects that are less than or equal to 25 kilowatts in size on the waitlist for this capacity shall be moved to the waitlist for paragraph (1) of this item (iv). Notwithstanding anything to the contrary, projects that were on the waitlist prior to opening of this block shall not be required to be in compliance with the requirements of subparagraph (Q) of this paragraph (1) of this subsection (c). Notwithstanding anything to the contrary, for those renewable energy credits procured from projects that were on the waitlist for this category before the opening of this block 20% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized by the Program Administrator. The remaining portion shall be paid ratably over the subsequent 4-year period. The electric utility shall receive and retire all renewable energy credits generated by the project during the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(B) The price of renewable energy credits for any project not on the waitlist for this category before the opening of the block shall be determined and published by the Agency. Projects not on a waitlist as of the opening of this block shall be subject to the requirements of subparagraph (Q) of this paragraph (1), as applicable. Projects not on a waitlist as of the opening of this block shall be subject to the contract provisions outlined in item (iii) of subparagraph (L) of this paragraph (1). The Agency shall strive to publish updated prices and an updated renewable energy credit delivery contract as quickly as possible.

(3) For opening the first 2 blocks of annual capacity for projects participating in item (iii) of subparagraph (K) of paragraph (1) of subsection (c), projects shall be selected exclusively from those projects on the ordinal waitlists of community renewable generation projects established by the Agency based on the status of those ordinal waitlists as of December 31, 2020, and only those projects previously determined to be eligible for the Agency's April 2019 community solar project selection process.

The first 2 blocks of annual capacity for item (iii) shall be for 250 megawatts of total nameplate capacity, with both blocks opening simultaneously under the schedule outlined in the paragraphs below. Projects shall be selected as follows:

(A) The geographic balance of selected projects shall follow the Group classification found in the Agency's Revised Long-Term Renewable Resources Procurement Plan, with 70% of capacity allocated to projects on the Group B waitlist and 30% of capacity allocated to projects on the Group A waitlist.

(B) Contract awards for waitlisted projects shall be allocated proportionate to the total nameplate capacity amount across both ordinal waitlists associated with that applicant firm or its affiliates, subject to the following conditions.

(i) Each applicant firm having a waitlisted project eligible for selection shall receive no less than 500 kilowatts in awarded capacity across all groups, and no approved vendor may receive more than 20% of each Group's waitlist allocation.

(ii) Each applicant firm, upon receiving an award of program capacity proportionate to its waitlisted capacity, may then determine which waitlisted projects it chooses to be selected for a contract award up to that capacity amount.

(iii) Assuming all other program requirements are met, applicant firms may adjust the nameplate capacity of applicant projects without losing waitlist eligibility, so long as no project is greater than 2,000 kilowatts in size.

(iv) Assuming all other program requirements are met, applicant firms may adjust the expected production associated with applicant projects, subject to verification by the Program Administrator.

(C) After a review of affiliate information and the current ordinal waitlists, the Agency shall announce the nameplate capacity award amounts associated with applicant firms no later than 90 days after the effective date of this amendatory Act of the 102nd General Assembly.

(D) Applicant firms shall submit their portfolio of projects used to satisfy those contract awards no less than 90 days after the Agency's announcement. The total nameplate capacity of all projects used to satisfy that portfolio shall be no greater than the Agency's nameplate capacity award amount associated with that applicant firm. An applicant firm may decline, in whole or in part, its nameplate capacity award without penalty, with such unmet capacity rolled over to the next block opening for project selection under item (iii) of subparagraph (K) of this subsection (c). Any projects not included in an applicant firm's portfolio may reapply without prejudice upon the next block reopening for project selection under item (iii) of subparagraph (K) of this subsection (c).

(E) The renewable energy credit delivery contract shall be subject to the contract and payment terms outlined in item (iv) of subparagraph (L) of this subsection (c). Contract instruments used for this subparagraph shall contain the following terms:

(i) Renewable energy credit prices shall be fixed, without further adjustment under any other provision of this Act or for any other reason, at 10% lower than prices applicable to the last open block for this category, inclusive of any adders available for achieving a minimum of 50% of subscribers to the project's nameplate capacity being residential or small commercial customers with subscriptions of below 25 kilowatts in size;

(ii) A requirement that a minimum of 50% of subscribers to the project's nameplate capacity be residential or small commercial customers with subscriptions of below 25 kilowatts in size;

(iii) Permission for the ability of a contract holder to substitute projects with other waitlisted projects without penalty should a project receive a non-binding estimate of costs to construct the interconnection facilities and any required distribution upgrades associated with that project of greater than 30 cents per watt AC of that project's nameplate capacity. In developing the applicable contract instrument, the Agency may consider whether other circumstances outside of the control of the applicant firm should also warrant project substitution rights.

The Agency shall publish a finalized updated renewable energy credit delivery contract developed consistent with these terms and conditions no less than 30 days before applicant firms must submit their portfolio of projects pursuant to item (D).

(F) To be eligible for an award, the applicant firm shall certify that not less than prevailing wage, as determined pursuant to the Illinois Prevailing Wage Act, was or will be paid to employees who are engaged in construction activities associated with a selected project.

(4) The Agency shall open the first block of annual capacity for the category described in item (iv) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (iv) shall be for at least 50 megawatts of total nameplate capacity. Renewable energy credit prices shall be fixed, without further adjustment under any other provision of this Act or for any other reason, at the price in the last open block in the category described in item (ii) of subparagraph (K) of this paragraph (1). Pricing for future blocks of annual capacity for this category may be adjusted in the Agency's second revision to its Long-Term Renewable Resources Procurement Plan. Projects in this category shall be subject to the contract terms outlined in item (iv) of subparagraph (L) of this paragraph (1).

(5) The Agency shall open the equivalent of 2 years of annual capacity for the category described in item (v) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (v) shall be for at least 10 megawatts of total nameplate capacity. Notwithstanding the provisions of item (v) of subparagraph (K) of this paragraph (1), for the purpose of this initial block, the agency shall accept new project applications intended to increase the diversity of areas hosting community solar projects, the business models of projects, and the size of projects, as described by the Agency in its long-term renewable resources procurement plan that is approved as of the effective date of this amendatory Act of the 102nd General Assembly. Projects in this category shall be subject to the contract terms outlined in item (iii) of subsection (L) of this paragraph (1).

(6) The Agency shall open the first blocks of annual capacity for the category described in item (vi) of subparagraph (K) of this paragraph (1), with allocations of capacity within the block generally matching the historical share of block capacity allocated between the category described in items (i) and (ii) of subparagraph (K) of this paragraph (1). The first two blocks of annual capacity for item (vi) shall be for at least 75 megawatts of total nameplate capacity. The price of renewable energy credits for the blocks of capacity shall be 4% less than the price of the last open blocks in the categories described in items (i) and (ii) of subparagraph (K) of this paragraph (1). Pricing for future blocks of annual capacity for this category may be adjusted in the Agency's second revision to its Long-Term Renewable Resources Procurement Plan. Projects in this category shall be subject to the applicable contract terms outlined in items (ii) and (iii) of subparagraph (L) of this paragraph (1).

(v) Upon the effective date of this amendatory Act of the 102nd General Assembly, for all competitive procurements and any procurements of renewable energy credit from new utility-scale wind and new utility-scale photovoltaic projects, the Agency shall procure indexed renewable energy credits and direct respondents to offer a strike price.

(1) The purchase price of the indexed renewable energy credit payment shall be calculated for each settlement period. That payment, for any settlement period, shall be equal to the difference resulting from subtracting the strike price from the index price for that settlement period. If this difference results in a negative number, the indexed REC counterparty shall owe the seller the absolute value multiplied by the quantity of energy produced in the relevant settlement period. If this difference results in a positive number, the seller shall owe the indexed REC counterparty this amount multiplied by the quantity of energy produced in the relevant settlement period.

(2) Parties shall cash settle every month, summing up all settlements (both positive and negative, if applicable) for the prior month.

(3) To ensure funding in the annual budget established under subparagraph (E) for indexed renewable energy credit procurements for each year of the term of such contracts, which must have a minimum tenure of 20 calendar years, the procurement administrator, Agency, Commission staff, and procurement monitor shall quantify the annual cost of the contract by utilizing one or more an industry-standard, third-party forward price curves curve for energy at the appropriate hub or load zone, including the estimated magnitude and timing of the price effects related to federal carbon controls. Each forward price curve shall contain a specific value of the forecasted market price of electricity for each annual delivery year of the contract. For procurement planning purposes, the impact on the annual budget for the cost of indexed renewable energy credits for each delivery year shall be determined as the expected annual contract expenditure for that year, equaling the difference between (i) the sum across all relevant contracts of the applicable strike price multiplied by contract quantity and (ii) the sum across all relevant contracts of the forward price curve for the applicable load zone for that year multiplied by contract quantity. The contracting utility shall not assume an obligation in excess of the estimated annual cost of the contracts for indexed renewable energy credits. Forward curves shall be revised on an annual basis as updated forward price curves are released and filed with the Commission in the proceeding approving the Agency's most recent long-term renewable resources procurement plan. If the expected contract spend is higher or lower than the total quantity of contracts multiplied by the forward price curve value for that year, the forward price curve shall be updated by the procurement administrator, in consultation with the Agency, Commission staff, and procurement monitors, using then-currently available price forecast data and additional budget dollars shall be obligated or reobligated as appropriate.

(4) To ensure that indexed renewable energy credit prices remain predictable and affordable, the Agency may consider the institution of a price collar on REC prices paid under indexed renewable energy credit procurements establishing floor and ceiling REC prices applicable to indexed REC contract prices. Any price collars applicable to indexed REC procurements shall be proposed by the Agency through its long-term renewable resources procurement plan.

(vi) All procurements under this subparagraph (G), including the procurement of renewable energy credits from hydropower facilities, shall comply with the geographic requirements in subparagraph (I) of this paragraph (1) and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act to the extent practicable, and these processes and procedures may be expedited to accommodate the schedule established by this subparagraph (G). To ensure the successful development of new renewable energy projects supported through competitive procurements, for any procurements conducted under items (i), (ii), (iii), and (v) of this subparagraph (G) and any other procurement of new utility-scale wind or utility-scale solar projects that were entered into prior to January 1, 2025, the Agency shall allow, upon a demonstration of need to ensure the commercial viability of a project, for a one-time, post-award renegotiation of select contract terms prior to the project's commercial operation date through bilateral negotiation between the Agency, the buyer, and a winning bidder. Contract terms subject to renegotiation may include the project map, as defined under the applicable competitive solicitation, the real estate footprint or any limitations thereof, the location of the generators, or a potential reduction in the quantity of renewable energy credits to be delivered. Provisions related to a renewable energy credit delivery shortfall and the event of default may be replaced with similar provisions approved by the Agency in subsequent years or subsequent to a successful bid. Post-award renegotiation of competitively bid renewable energy credit contracts entered into prior to January 1, 2025 shall not be permitted to the extent such renegotiation would result in (1) the point of interconnection being within the service area of a different state, a different regional transmission organization zone, or a different regional transmission organization, (2) the generator no longer meeting the definition of the resource category for which the winning bidder was originally awarded a contract, (3) the generator no longer meeting the Agency's public interest criteria as established in the long-term renewable resources plan in effect at the time of the contract award, or (4) a change to material terms of the renewable energy credit contract unrelated to project land or footprint or the number of renewable energy credits to be delivered, including the applicable bid price or strike price. If the Agency, the buyer, and the winning bidder reach an agreement on amended terms, then, upon petition by the winning bidder or current seller, the Commission shall issue an order directing the utility counterparty to execute an amendment drafted by the Agency with the revised terms to the renewable energy credit contract, the product order, or both. The Agency shall provide the amendment to the utility within 15 business days after the Commission's order, and the utility shall execute the amendment no more than 7 calendar days after delivery by the Agency.

(vii) On and after the effective date of this amendatory Act of the 103rd General Assembly, for all procurements of renewable energy credits from hydropower facilities, the Agency shall establish contract terms designed to optimize existing hydropower facilities through modernization or retooling and establish new hydropower facilities at existing dams. Procurements made under this item (vii) shall prioritize projects located in designated environmental justice communities, as defined in subsection (b) of Section 1-56 of this Act, or in projects located in units of local government with median incomes that do not exceed 82% of the median income of the State.

(H) The procurement of renewable energy resources for a given delivery year shall be reduced as described in this subparagraph (H) if an alternative retail electric supplier meets the requirements described in this subparagraph (H).

(i) Within 45 days after June 1, 2017 (the effective date of Public Act 99-906), an alternative retail electric supplier or its successor shall submit an informational filing to the Illinois Commerce Commission certifying that, as of December 31, 2015, the alternative retail electric supplier owned one or more electric generating facilities that generates renewable energy resources as defined in Section 1-10 of this Act, provided that such facilities are not powered by wind or photovoltaics, and the facilities generate one renewable energy credit for each megawatthour of energy produced from the facility.

The informational filing shall identify each facility that was eligible to satisfy the alternative retail electric supplier's obligations under Section 16-115D of the Public Utilities Act as described in this item (i).

(ii) For a given delivery year, the alternative retail electric supplier may elect to supply its retail customers with renewable energy credits from the facility or facilities described in item (i) of this subparagraph (H) that continue to be owned by the alternative retail electric supplier.

(iii) The alternative retail electric supplier shall notify the Agency and the applicable utility, no later than February 28 of the year preceding the applicable delivery year or 15 days after June 1, 2017 (the effective date of Public Act 99-906), whichever is later, of its election under item (ii) of this subparagraph (H) to supply renewable energy credits to retail customers of the utility. Such election shall identify the amount of renewable energy credits to be supplied by the alternative retail electric supplier to the utility's retail customers and the source of the renewable energy credits identified in the informational filing as described in item (i) of this subparagraph (H), subject to the following limitations:

For the delivery year beginning June 1, 2018, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 25% multiplied by 14.5% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016.

For delivery years beginning June 1, 2019 and each year thereafter, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 50% multiplied by 16% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016, provided that the 16% value shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

For each delivery year, the total amount of renewable energy credits supplied by all alternative retail electric suppliers under this subparagraph (H) shall not exceed 9% of the Illinois target renewable energy credit quantity. The Illinois target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered in the delivery year immediately preceding that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

If the requirements set forth in items (i) through (iii) of this subparagraph (H) are met, the charges that would otherwise be applicable to the retail customers of the alternative retail electric supplier under paragraph (6) of this subsection (c) for the applicable delivery year shall be reduced by the ratio of the quantity of renewable energy credits supplied by the alternative retail electric supplier compared to that supplier's target renewable energy credit quantity. The supplier's target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered by the alternative retail supplier in that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

On or before April 1 of each year, the Agency shall annually publish a report on its website that identifies the aggregate amount of renewable energy credits supplied by alternative retail electric suppliers under this subparagraph (H).

(I) The Agency shall design its long-term renewable energy procurement plan to maximize the State's interest in the health, safety, and welfare of its residents, including but not limited to minimizing sulfur dioxide, nitrogen oxide, particulate matter and other pollution that adversely affects public health in this State, increasing fuel and resource diversity in this State, enhancing the reliability and resiliency of the electricity distribution system in this State, meeting goals to limit carbon dioxide emissions under federal or State law, and contributing to a cleaner and healthier environment for the citizens of this State. In order to further these legislative purposes, renewable energy credits shall be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are generated from facilities located in this State. The Agency may qualify renewable energy credits from facilities located in states adjacent to Illinois or renewable energy credits associated with the electricity generated by a utility-scale wind energy facility or utility-scale photovoltaic facility and transmitted by a qualifying direct current project described in subsection (b-5) of Section 8-406 of the Public Utilities Act to a delivery point on the electric transmission grid located in this State or a state adjacent to Illinois, if the generator demonstrates and the Agency determines that the operation of such facility or facilities will help promote the State's interest in the health, safety, and welfare of its residents based on the public interest criteria described above. For the purposes of this Section, renewable resources that are delivered via a high voltage direct current converter station located in Illinois shall be deemed generated in Illinois at the time and location the energy is converted to alternating current by the high voltage direct current converter station if the high voltage direct current transmission line: (i) after the effective date of this amendatory Act of the 102nd General Assembly, was constructed with a project labor agreement; (ii) is capable of transmitting electricity at 525kv; (iii) has an Illinois converter station located and interconnected in the region of the PJM Interconnection, LLC; (iv) does not operate as a public utility; and (v) if the high voltage direct current transmission line was energized after June 1, 2023. To ensure that the public interest criteria are applied to the procurement and given full effect, the Agency's long-term procurement plan shall describe in detail how each public interest factor shall be considered and weighted for facilities located in states adjacent to Illinois.

(J) In order to promote the competitive development of renewable energy resources in furtherance of the State's interest in the health, safety, and welfare of its residents, renewable energy credits shall not be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are sourced from a generating unit whose costs were being recovered through rates regulated by this State or any other state or states on or after January 1, 2017. Each contract executed to purchase renewable energy credits under this subsection (c) shall provide for the contract's termination if the costs of the generating unit supplying the renewable energy credits subsequently begin to be recovered through rates regulated by this State or any other state or states; and each contract shall further provide that, in that event, the supplier of the credits must return 110% of all payments received under the contract. Amounts returned under the requirements of this subparagraph (J) shall be retained by the utility and all of these amounts shall be used for the procurement of additional renewable energy credits from new wind or new photovoltaic resources as defined in this subsection (c). The long-term plan shall provide that these renewable energy credits shall be procured in the next procurement event.

Notwithstanding the limitations of this subparagraph (J), renewable energy credits sourced from generating units that are constructed, purchased, owned, or leased by an electric utility as part of an approved project, program, or pilot under Section 1-56 of this Act shall be eligible to be counted toward the renewable energy requirements of this subsection (c), regardless of how the costs of these units are recovered. As long as a generating unit or an identifiable portion of a generating unit has not had and does not have its costs recovered through rates regulated by this State or any other state, HVDC renewable energy credits associated with that generating unit or identifiable portion thereof shall be eligible to be counted toward the renewable energy requirements of this subsection (c).

(K) The long-term renewable resources procurement plan developed by the Agency in accordance with subparagraph (A) of this paragraph (1) shall include an Adjustable Block program for the procurement of renewable energy credits from new photovoltaic projects that are distributed renewable energy generation devices or new photovoltaic community renewable generation projects. The Adjustable Block program shall be generally designed to provide for the steady, predictable, and sustainable growth of new solar photovoltaic development in Illinois. To this end, the Adjustable Block program shall provide a transparent annual schedule of prices and quantities to enable the photovoltaic market to scale up and for renewable energy credit prices to adjust at a predictable rate over time. The prices set by the Adjustable Block program can be reflected as a set value or as the product of a formula.

The Adjustable Block program shall include for each category of eligible projects for each delivery year: a single block of nameplate capacity, a price for renewable energy credits within that block, and the terms and conditions for securing a spot on a waitlist once the block is fully committed or reserved. Except as outlined below, the waitlist of projects in a given year will carry over to apply to the subsequent year when another block is opened. Only projects energized on or after June 1, 2017 shall be eligible for the Adjustable Block program. For each category for each delivery year the Agency shall determine the amount of generation capacity in each block, and the purchase price for each block, provided that the purchase price provided and the total amount of generation in all blocks for all categories shall be sufficient to meet the goals in this subsection (c). The Agency shall strive to issue a single block sized to provide for stability and market growth. The Agency shall establish program eligibility requirements that ensure that projects that enter the program are sufficiently mature to indicate a demonstrable path to completion. The Agency may periodically review its prior decisions establishing the amount of generation capacity in each block, and the purchase price for each block, and may propose, on an expedited basis, changes to these previously set values, including but not limited to redistributing these amounts and the available funds as necessary and appropriate, subject to Commission approval as part of the periodic plan revision process described in Section 16-111.5 of the Public Utilities Act. The Agency may define different block sizes, purchase prices, or other distinct terms and conditions for projects located in different utility service territories if the Agency deems it necessary to meet the goals in this subsection (c).

The Adjustable Block program shall include the following categories in at least the following amounts:

(i) At least 20% from distributed renewable energy generation devices with a nameplate capacity of no more than 25 kilowatts.

(ii) At least 20% from distributed renewable energy generation devices with a nameplate capacity of more than 25 kilowatts and no more than 5,000 kilowatts. The Agency may create sub-categories within this category to account for the differences between projects for small commercial customers, large commercial customers, and public or non-profit customers. A project shall not be colocated with one or more other distributed renewable energy generation projects if the aggregate nameplate capacity of the projects exceeds 5,000 kilowatts AC. Notwithstanding any other provision of this Section, if 2 or more projects are developed, owned, or controlled by or originate from the same developer or an affiliated developer and the projects serve affiliated loads, the projects shall be colocated if the projects are located on adjacent parcels. If 2 or more projects are developed, owned, or controlled by or originate from the same developer and the projects serve unaffiliated loads, the projects may be colocated if documentation indicates affiliated management and ownership in the pre-development, development, construction, and management of the projects and the projects are located on a single or adjacent parcels. Notwithstanding any subsequent transfer, assignment, or conveyance of ownership or development rights to separate legal entities, the Agency shall consider, in its determination of whether projects are affiliated, evidence that the projects were pre-developed by the same legal entity or an affiliated entity. If the Agency determines the projects are affiliated, the projects shall be treated as colocated for purposes of aggregate nameplate capacity limitations and renewable energy credit pricing adjustments. The Agency shall make exceptions on a case-by-case basis if it is demonstrated that projects on one parcel or projects on adjacent parcels are unaffiliated. For purposes of determining colocation, an approved vendor who submits an application for a distributed renewable energy generation project shall be required to submit an affidavit attesting that the project is not affiliated with any other distributed renewable energy generation project such that, if the 2 projects were deemed colocated, the projects would exceed the 5,000 kilowatts nameplate capacity limitation. The receipt of an affidavit shall not restrict the Agency's ability to investigate and determine whether the project is, in fact, colocated.

For purposes of this item (ii):

"Affiliate" has the meaning given to that term in subitem (3) of item (iii) of this subparagraph (K).

"Colocated" means 2 or more distributed renewable energy generation projects that are located on a single parcel, except for projects where the owner of the applicable retail electric account is confirmed to be unaffiliated and the projects serve distinct electrical loads.

"Control" has the meaning given to that term in subitem (3) of item (iii) of this subparagraph (K).

(iii) At least 30% from photovoltaic community renewable generation projects. Capacity for this category for the first 2 delivery years after the effective date of this amendatory Act of the 102nd General Assembly shall be allocated to waitlist projects as provided in paragraph (3) of item (iv) of subparagraph (G). Starting in the third delivery year after the effective date of this amendatory Act of the 102nd General Assembly or earlier if the Agency determines there is additional capacity needed for to meet previous delivery year requirements, the following shall apply:

(1) the Agency shall select projects on a first-come, first-serve basis, however the Agency may suggest additional methods to prioritize projects that are submitted at the same time;

(2) projects shall have subscriptions of 25 kW or less for at least 50% of the facility's nameplate capacity and the Agency shall price the renewable energy credits with that as a factor;

(3) projects shall not be colocated with one or more other community renewable generation projects such that the aggregate nameplate capacity exceeds 5,000 kilowatts. The total nameplate capacity of colocated projects shall be the sum of the nameplate capacities of the individual projects. For purposes of this subitem (3), separate legal formation of approved vendors, owners, or developers shall not preclude a finding of affiliation by the Agency. Evidence of affiliation may include, but is not limited to, shared personnel, common contractual or financing arrangements, a shared interconnection agreement, distinct interconnection agreements obtained by the same pre-development entity that are subsequently sold to distinct legal entities, familial relationships, or any demonstrable pattern of coordinated action in the pre-development, development, construction, or management of community renewable generation projects.

The Agency shall determine affiliation based on evidence that projects either (i) share a common origin on a parcel that has been subdivided in the 5 years before the date of application or (ii) were pre-developed before the beginning of construction by the same legal entity or an affiliated legal entity. The determination shall be made notwithstanding any subsequent transfer, assignment, or conveyance of ownership or development rights to separate legal entities. If the Agency determines the projects are affiliated, the projects shall be treated as colocated for the purposes of aggregate nameplate capacity limitations and renewable energy credit pricing adjustments. The Agency shall make exceptions to this subitem (3) on a case-by-case basis if it is demonstrated that projects on one parcel or projects on adjacent parcels are unaffiliated.

A parcel shall not be divided into multiple parcels within the 5 years before the submission of a project application. If a parcel is divided within the preceding 5 years, a colocation determination shall be made based on the boundaries of the previous undivided parcel.

For purposes of determining colocation, an approved vendor who submits an application for a community renewable generation project shall be required to submit an affidavit attesting that (i) the parcel on which the project is sited has not been subdivided within the 5 years preceding the project application and (ii) the project is not affiliated with any other community renewable energy project in a manner that would cause the 2 projects, if deemed colocated, to exceed the 5,000 kilowatt nameplate capacity limitation. The receipt of an affidavit shall not restrict the Agency's ability to investigate and determine whether the project is colocated.

Multiple community solar projects sited on distinct structures located on a single parcel shall be considered colocated and must demonstrate that the projects are unaffiliated in order to not be considered colocated. Each colocated project shall receive the renewable energy credit price corresponding to the total, aggregated nameplate capacity of the colocated systems, as determined at the time the second project's application is submitted to the Agency. If the second colocated project has been constructed and placed in service prior to application, and was placed in service more than 2 years after Commission approval of the original project, the colocation pricing adjustment shall not apply, and each project shall receive the standalone renewable energy credit price for its individual capacity.

For purposes of this subitem (3):

"Affiliate" means any other entity that, directly or indirectly through one or more intermediaries, is controlled by or is under common control of the primary entity or a third entity. "Affiliate" includes family members for the purposes of colocation between projects. "Affiliate" does not include entities that have shared sales or revenue-sharing arrangements or common debt and equity financing arrangements.

"Colocated" means 2 or more community renewable generation projects located on a single parcel or adjacent parcels, unless it is demonstrated that the projects are developed by unaffiliated entities.

"Control" means the possession, directly or indirectly, of the power to direct the management and policies of an entity , as defined in the Agency's first revised long-term renewable resources procurement plan approved by the Commission on February 18, 2020, such that the aggregate nameplate capacity exceeds 5,000 kilowatts; and

(4) projects greater than 2 MW may not apply until after the approval of the Agency's revised Long-Term Renewable Resources Procurement Plan after the effective date of this amendatory Act of the 102nd General Assembly.

(iv) At least 15% from distributed renewable generation devices or photovoltaic community renewable generation projects installed on public school land. The Agency may create subcategories within this category to account for the differences between project size or location. Projects located within environmental justice communities or within Organizational Units that fall within Tier 1 or Tier 2 shall be given priority. Each of the Agency's periodic updates to its long-term renewable resources procurement plan to incorporate the procurement described in this subparagraph (iv) shall also include the proposed quantities or blocks, pricing, and contract terms applicable to the procurement as indicated herein. In each such update and procurement, the Agency shall set the renewable energy credit price and establish payment terms for the renewable energy credits procured pursuant to this subparagraph (iv) that make it feasible and affordable for public schools to install photovoltaic distributed renewable energy devices on their premises, including, but not limited to, those public schools subject to the prioritization provisions of this subparagraph. For the purposes of this item (iv):

"Environmental Justice Community" shall have the same meaning set forth in the Agency's long-term renewable resources procurement plan;

"Organization Unit", "Tier 1" and "Tier 2" shall have the meanings set for in Section 18-8.15 of the School Code;

"Public schools" shall have the meaning set forth in Section 1-3 of the School Code and includes public institutions of higher education, as defined in the Board of Higher Education Act.

(v) At least 5% from community-driven community solar projects intended to provide more direct and tangible connection and benefits to the communities which they serve or in which they operate and, additionally, to increase the variety of community solar locations, models, and options in Illinois. As part of its long-term renewable resources procurement plan, the Agency shall develop selection criteria for projects participating in this category. Nothing in this Section shall preclude the Agency from creating a selection process that maximizes community ownership and community benefits in selecting projects to receive renewable energy credits. Selection criteria shall include:

(1) community ownership or community wealth-building;

(2) additional direct and indirect community benefit, beyond project participation as a subscriber, including, but not limited to, economic, environmental, social, cultural, and physical benefits;

(3) meaningful involvement in project organization and development by community members or nonprofit organizations or public entities located in or serving the community;

(4) engagement in project operations and management by nonprofit organizations, public entities, or community members; and

(5) whether a project is developed in response to a site-specific RFP developed by community members or a nonprofit organization or public entity located in or serving the community.

Selection criteria may also prioritize projects that:

(1) are developed in collaboration with or to provide complementary opportunities for the Clean Jobs Workforce Network Program, the Illinois Climate Works Preapprenticeship Program, the Returning Residents Clean Jobs Training Program, the Clean Energy Contractor Incubator Program, or the Clean Energy Primes Contractor Accelerator Program;

(2) increase the diversity of locations of community solar projects in Illinois, including by locating in urban areas and population centers;

(3) are located in Equity Investment Eligible Communities;

(4) are not greenfield projects;

(5) serve only local subscribers;

(6) have a nameplate capacity that does not exceed 500 kW;

(7) are developed by an equity eligible contractor; or

(8) otherwise meaningfully advance the goals of providing more direct and tangible connection and benefits to the communities which they serve or in which they operate and increasing the variety of community solar locations, models, and options in Illinois.

For the purposes of this item (v):

"Community" means a social unit in which people come together regularly to effect change; a social unit in which participants are marked by a cooperative spirit, a common purpose, or shared interests or characteristics; or a space understood by its residents to be delineated through geographic boundaries or landmarks.

"Community benefit" means a range of services and activities that provide affirmative, economic, environmental, social, cultural, or physical value to a community; or a mechanism that enables economic development, high-quality employment, and education opportunities for local workers and residents, or formal monitoring and oversight structures such that community members may ensure that those services and activities respond to local knowledge and needs.

"Community ownership" means an arrangement in which an electric generating facility is, or over time will be, in significant part, owned collectively by members of the community to which an electric generating facility provides benefits; members of that community participate in decisions regarding the governance, operation, maintenance, and upgrades of and to that facility; and members of that community benefit from regular use of that facility.

Terms and guidance within these criteria that are not defined in this item (v) shall be defined by the Agency, with stakeholder input, during the development of the Agency's long-term renewable resources procurement plan. The Agency shall develop regular opportunities for projects to submit applications for projects under this category, and develop selection criteria that gives preference to projects that better meet individual criteria as well as projects that address a higher number of criteria.

(vi) At least 10% from distributed renewable energy generation devices, which includes distributed renewable energy devices with a nameplate capacity under 5,000 kilowatts or photovoltaic community renewable generation projects, from applicants that are equity eligible contractors. The Agency may create subcategories within this category to account for the differences between project size and type. The Agency shall propose to increase the percentage in this item (vi) over time to 40% based on factors, including, but not limited to, the number of equity eligible contractors and capacity used in this item (vi) in previous delivery years.

The Agency shall propose a payment structure for contracts executed pursuant to this paragraph under which, upon a demonstration of qualification or need under criteria established by the Agency that is focused on supporting small and emerging businesses and businesses that most acutely face barriers to the access of capital, applicant firms are advanced capital disbursed after contract execution but before the contracted project's energization. The amount or percentage of capital advanced prior to project energization shall be sufficient to both cover any increase in development costs resulting from prevailing wage requirements or project-labor agreements, and designed to overcome barriers in access to capital faced by equity eligible contractors. The amount or percentage of advanced capital may vary by subcategory within this category and by an applicant's demonstration of need, with such levels to be established through the Long-Term Renewable Resources Procurement Plan authorized under subparagraph (A) of paragraph (1) of subsection (c) of this Section and any application requirements or evaluation criteria developed pursuant to the Plan.

Contracts developed featuring capital advanced prior to a project's energization shall feature provisions to ensure both the successful development of applicant projects and the delivery of the renewable energy credits for the full term of the contract, including ongoing collateral requirements and other provisions deemed necessary by the Agency, and may include energization timelines longer than for comparable project types. The percentage or amount of capital advanced prior to project energization shall not operate to increase the overall contract value, however contracts executed under this subparagraph may feature renewable energy credit prices higher than those offered to similar projects participating in other categories. Capital advanced prior to energization shall serve to reduce the ratable payments made after energization under items (ii) and (iii) of subparagraph (L) or payments made for each renewable energy credit delivery under item (iv) of subparagraph (L).

(vii) The remaining capacity shall be allocated by the Agency in order to respond to market demand. The Agency shall allocate any discretionary capacity prior to the beginning of each delivery year.

(viii) The Agency, through its long-term renewable resources procurement plan, may implement solutions to maintain stable and consistent REC offerings allocated to systems described in item (i) of this subparagraph (K) to avoid gaps in availability during a delivery year, including, but not limited to, creating a floating block of REC capacity in a given delivery year.

To the extent there is uncontracted capacity from any block in any of categories (i) through (vi) at the end of a delivery year, the Agency shall redistribute that capacity to one or more other categories giving priority to categories with projects on a waitlist. The redistributed capacity shall be added to the annual capacity in the subsequent delivery year, and the price for renewable energy credits shall be the price for the new delivery year. Redistributed capacity shall not be considered redistributed when determining whether the goals in this subsection (K) have been met.

Notwithstanding anything to the contrary, as the Agency increases the capacity in item (vi) to 40% over time, the Agency may reduce the capacity of items (i) through (v) proportionate to the capacity of the categories of projects in item (vi), to achieve a balance of project types.

The Adjustable Block program shall be designed to ensure that renewable energy credits are procured from projects in diverse locations and are not concentrated in a few regional areas.

(L) Notwithstanding provisions for advancing capital prior to project energization found in item (vi) of subparagraph (K), the procurement of photovoltaic renewable energy credits under items (i) through (vi) of subparagraph (K) of this paragraph (1) shall otherwise be subject to the following contract and payment terms:

(i) (Blank).

(ii) Unless otherwise provided for in the Agency's approved long-term plan, for For those renewable energy credits that qualify and are procured under item (i) of subparagraph (K) of this paragraph (1), and any similar category projects that are procured under item (vi) of subparagraph (K) of this paragraph (1) that qualify and are procured under item (vi), the contract length shall be 15 years. Beginning on the effective date of this amendatory Act of the 104th General Assembly, and including the remainder of program year 2026-2027, 50% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid The renewable energy credit delivery contract value shall be paid in full, based on the estimated generation during the first 15 years of operation, by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and compliant by the Program Administrator. The remaining portion of the renewable energy credit delivery contract value shall be paid ratably over the subsequent 6-year period. Relative to a contract structure under which the full renewable energy credit delivery contract value shall be paid in full at the time of interconnection and verification of energization, the Agency shall consider the impact of deferred payments across the subsequent payment period when establishing renewable energy credit prices. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iii) Unless otherwise provided for in the Agency's approved long-term plan, for For those renewable energy credits that qualify and are procured under item (ii) and (v) of subparagraph (K) of this paragraph (1) and any like projects similar category that qualify and are procured under items (iv) and item (vi), the contract length shall be 15 years. 15% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and compliant by the Program Administrator. The remaining portion shall be paid ratably over the subsequent 6-year period. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iv) Unless otherwise provided for in the Agency's approved long-term plan, for For those renewable energy credits that qualify and are procured under item items (iii) and (iv) of subparagraph (K) of this paragraph (1), and any like projects that qualify and are procured under items (iv) and item (vi), the renewable energy credit delivery contract length shall be 20 years and shall be paid over the delivery term, not to exceed during each delivery year the contract price multiplied by the estimated annual renewable energy credit generation amount. If generation of renewable energy credits during a delivery year exceeds the estimated annual generation amount, the excess renewable energy credits shall be carried forward to future delivery years and shall not expire during the delivery term. If generation of renewable energy credits during a delivery year, including carried forward excess renewable energy credits, if any, is less than the estimated annual generation amount, payments during such delivery year will not exceed the quantity generated plus the quantity carried forward multiplied by the contract price. The electric utility shall receive all renewable energy credits generated by the project during the first 20 years of operation and retire all renewable energy credits paid for under this item (iv) and return at the end of the delivery term all renewable energy credits that were not paid for. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility. Notwithstanding the preceding, for those projects participating under item (iii) of subparagraph (K), the contract price for a delivery year shall be based on subscription levels as measured on the higher of the first business day of the delivery year or the first business day 6 months after the first business day of the delivery year. Subscription of 90% of nameplate capacity or greater shall be deemed to be fully subscribed for the purposes of this item (iv). For projects receiving a 20-year delivery contract, REC prices shall be adjusted downward for consistency with the incentive levels previously determined to be necessary to support projects under 15-year delivery contracts, taking into consideration any additional new requirements placed on the projects, including, but not limited to, labor standards.

(v) Each contract shall include provisions to ensure the delivery of the estimated quantity of renewable energy credits and ongoing collateral requirements and other provisions deemed appropriate by the Agency.

(vi) The utility shall be the counterparty to the contracts executed under this subparagraph (L) that are approved by the Commission under the process described in Section 16-111.5 of the Public Utilities Act. No contract shall be executed for an amount that is less than one renewable energy credit per year.

(vii) If, at any time, approved applications for the Adjustable Block program exceed funds collected by the electric utility or would cause the Agency to exceed the limitation described in subparagraph (E) of this paragraph (1) on the amount of renewable energy resources that may be procured, then the Agency may consider future uncommitted funds to be reserved for these contracts on a first-come, first-served basis.

(viii) Nothing in this Section shall require the utility to advance any payment or pay any amounts that exceed the actual amount of revenues anticipated to be collected by the utility under paragraph (6) of this subsection (c) and subsection (k) of Section 16-108 of the Public Utilities Act inclusive of eligible funds collected in prior years and alternative compliance payments for use by the utility.

(ix) Notwithstanding other requirements of this subparagraph (L), no modification shall be required to Adjustable Block program contracts if they were already executed prior to the establishment, approval, and implementation of new contract forms as a result of this amendatory Act of the 102nd General Assembly.

(x) Contracts may be assignable, but only to entities first deemed by the Agency to have met program terms and requirements applicable to direct program participation. In developing contracts for the delivery of renewable energy credits, the Agency shall be permitted to establish fees applicable to each contract assignment.

(M) The Agency shall be authorized to retain one or more experts or expert consulting firms to develop, administer, implement, operate, and evaluate the Adjustable Block program described in subparagraph (K) of this paragraph (1), and the Agency shall retain the consultant or consultants in the same manner, to the extent practicable, as the Agency retains others to administer provisions of this Act, including, but not limited to, the procurement administrator. The selection of experts and expert consulting firms and the procurement process described in this subparagraph (M) are exempt from the requirements of Section 20-10 of the Illinois Procurement Code, under Section 20-10 of that Code. The Agency shall strive to minimize administrative expenses in the implementation of the Adjustable Block program.

The Program Administrator may charge application fees to participating firms to cover the cost of program administration. Any application fee amounts shall initially be determined through the long-term renewable resources procurement plan, and modifications to any application fee that deviate more than 25% from the Commission's approved value must be approved by the Commission as a long-term plan revision under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to application fees and shall notify stakeholders in advance of any planned changes.

In addition to covering the costs of program administration, the Agency, in conjunction with its Program Administrator, may also use the proceeds of such fees charged to participating firms to support public education and ongoing regional and national coordination with nonprofit organizations, public bodies, and others engaged in the implementation of renewable energy incentive programs or similar initiatives. This work may include developing papers and reports, hosting regional and national conferences, and other work deemed necessary by the Agency to position the State of Illinois as a national leader in renewable energy incentive program development and administration.

The Agency and its consultant or consultants shall monitor block activity, share program activity with stakeholders and conduct quarterly meetings to discuss program activity and market conditions. If necessary, the Agency may make prospective administrative adjustments to the Adjustable Block program design, such as making adjustments to purchase prices as necessary to achieve the goals of this subsection (c). Program modifications to any block price that do not deviate from the Commission's approved value by more than 10% shall take effect immediately and are not subject to Commission review and approval. Program modifications to any block price that deviate more than 10% from the Commission's approved value must be approved by the Commission as a long-term plan amendment under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to the Adjustable Block design and shall notify stakeholders in advance of any planned changes.

The Agency and its program administrators for both the Adjustable Block program and the Illinois Solar for All Program, consistent with the requirements of this subsection (c) and subsection (b) of Section 1-56 of this Act, shall propose the Adjustable Block program terms, conditions, and requirements, including the prices to be paid for renewable energy credits, where applicable, and requirements applicable to participating entities and project applications, through the development, review, and approval of the Agency's long-term renewable resources procurement plan described in this subsection (c) and paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. Terms, conditions, and requirements for program participation shall include the following:

(i) The Agency shall establish a registration process for entities seeking to qualify for program-administered incentive funding and establish baseline qualifications for vendor approval. The Agency shall also establish program requirements and minimum contract terms for vendors and others involved in the marketing, sale, installation, and financing of distributed generation systems and community solar subscriptions to prevent misleading marketing and abusive practices and to otherwise protect customers. The Agency must maintain a list of approved entities on each program's website, and may revoke a vendor's ability to receive program-administered incentive funding status upon a determination that the vendor failed to comply with contract terms, the law, or other program requirements.

(ii) The Agency shall establish program requirements and minimum contract terms to ensure projects are properly installed and produce their expected amounts of energy. Program requirements may include on-site inspections and photo documentation of projects under construction. The Agency may require repairs, alterations, or additions to remedy any material deficiencies discovered. Vendors who have a disproportionately high number of deficient systems may lose their eligibility to continue to receive State-administered incentive funding through Agency programs and procurements.

(iii) To discourage deceptive marketing or other bad faith business practices, the Agency may require direct program participants, including agents operating on their behalf, to provide standardized disclosures to a customer prior to that customer's execution of a contract for the development of a distributed generation system or a subscription to a community solar project.

(iv) The Agency shall establish one or multiple Consumer Complaints Centers to accept complaints regarding businesses that participate in, or otherwise benefit from, State-administered incentive funding through Agency-administered programs. The Agency shall maintain a public database of complaints with any confidential or particularly sensitive information redacted from public entries.

(v) Through a filing in the proceeding for the approval of its long-term renewable energy resources procurement plan, the Agency shall provide an annual written report to the Illinois Commerce Commission documenting the frequency and nature of complaints and any enforcement actions taken in response to those complaints.

(vi) The Agency shall schedule regular meetings with representatives of the Office of the Attorney General, the Illinois Commerce Commission, consumer protection groups, and other interested stakeholders to share relevant information about consumer protection, project compliance, and complaints received.

(vii) To the extent that complaints received implicate the jurisdiction of the Office of the Attorney General, the Illinois Commerce Commission, or local, State, or federal law enforcement, the Agency shall also refer complaints to those entities as appropriate.

(viii) The Agency shall establish a registration process for entities that provide financing for consumers for the purchase of distributed renewable generation devices. The Agency may establish baseline qualifications for financier approval, including defining the circumstances under which financing parties may be subject to registration. The Agency shall also establish program requirements for entities that provide financing for the purchase of distributed renewable generation devices, which may include marketing and disclosure requirements, other requirements as further defined by the Agency through its long-term plan, and any consumer protection requirements developed or modified thereto. The Agency shall maintain a list of approved financiers on each program's website and may revoke a financier's approval in a program upon a determination that the financier failed to comply with contract terms, the law, or other program requirements. The Agency may establish program requirements that prohibit distributed renewable generation devices intending to apply for program-administered incentive funding from receiving program funding the consumer's purchase if the device was financed by an entity whose approval status in the program has been revoked.

(ix) The Agency may propose that vendors, as part of the application and annual recertification process, present the Agency or its designee with a security bond equal to an amount determined to be reasonable by the Agency. The bond shall be for the benefit of customers harmed by the vendor's violation of Agency requirements or other applicable laws or regulations. The Agency may determine that it is reasonable to have no bond requirement for some categories of vendors or enhanced bond requirements for vendors that the Agency has deemed to pose more acute risks.

(x) For distributed renewable generation devices, the Agency may, in its discretion, establish provisions that restrict, prohibit, or create additional requirements for distributed renewable generation device sales or financing offers through which the customer is promised the pass-through of a portion or all of the payments received by the approved vendor for the delivery of renewable energy credits only after the receipt of such payment by the approved vendor. The requirements may include the use of an escrow process developed by the Agency through which renewable energy credit payments are made to an escrow agent who then disburses the promised amount to the customer and the remainder to the vendor. The requirements in this item (x) shall in no way prohibit the upfront discounting of the purchase price, lease payment, or power purchase agreement rate based on the anticipated receipt of renewable energy credit contract payments by the approved vendor.

(xi) To the extent that distributed renewable generation device sales or financing offers through which the customer is promised the pass-through of a portion or all of the payments received by the vendor for the delivery of renewable energy credits after the receipt of such payment by the vendor are permitted, the following requirements shall apply in a time and manner determined by the Agency:

(I) the vendor shall submit proof of customer payments to the Agency as the Agency deems necessary; and

(II) the vendor shall represent and warrant on a form developed by the Agency that the vendor is not insolvent, has not voluntarily filed for bankruptcy, and has not been subject to or threatened with involuntary insolvency.

(xii) To ensure that customers receive full and uninterrupted benefits and services promised by vendors, the Agency may propose additional solutions through its long-term renewable resources procurement plan described in this subsection (c) and paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. The solutions may allow for collections made pursuant to subsection (k) of Section 16-108 of the Public Utilities Act to support the programs and procurements outlined in paragraph (1) of subsection (c) of this Section to be leveraged to (1) ensure that a vendor's promised payments are received by customers, (2) incentivize vendors to establish service agreements with customers whose original vendor has become nonresponsive, (3) ensure that customers receive restitution for financial harm proven to be caused by a program vendor or its designee, or (4) otherwise ensure that customers do not suffer loss or harm through activities supported by the Adjustable Block program and the Illinois Solar for All Program.

(N) The Agency shall establish the terms, conditions, and program requirements for photovoltaic community renewable generation projects with a goal to expand access to a broader group of energy consumers, to ensure robust participation opportunities for residential and small commercial customers and those who cannot install renewable energy on their own properties. Subject to reasonable limitations, any plan approved by the Commission shall allow subscriptions to community renewable generation projects to be portable and transferable. For purposes of this subparagraph (N), "portable" means that subscriptions may be retained by the subscriber even if the subscriber relocates or changes its address within the same utility service territory; and "transferable" means that a subscriber may assign or sell subscriptions to another person within the same utility service territory.

Through the development of its long-term renewable resources procurement plan, the Agency may consider whether community renewable generation projects utilizing technologies other than photovoltaics should be supported through State-administered incentive funding, and may issue requests for information to gauge market demand.

Electric utilities shall provide a monetary credit to a subscriber's subsequent bill for service for the proportional output of a community renewable generation project attributable to that subscriber as specified in Section 16-107.5 of the Public Utilities Act.

The Agency shall purchase renewable energy credits from subscribed shares of photovoltaic community renewable generation projects through the Adjustable Block program described in subparagraph (K) of this paragraph (1) or through the Illinois Solar for All Program described in Section 1-56 of this Act. The electric utility shall purchase any unsubscribed energy from community renewable generation projects that are Qualifying Facilities ("QF") under the electric utility's tariff for purchasing the output from QFs under Public Utilities Regulatory Policies Act of 1978.

The owners of and any subscribers to a community renewable generation project shall not be considered public utilities or alternative retail electricity suppliers under the Public Utilities Act solely as a result of their interest in or subscription to a community renewable generation project and shall not be required to become an alternative retail electric supplier by participating in a community renewable generation project with a public utility.

(O) For the delivery year beginning June 1, 2018, the long-term renewable resources procurement plan required by this subsection (c) shall provide for the Agency to procure contracts to continue offering the Illinois Solar for All Program described in subsection (b) of Section 1-56 of this Act, and the contracts approved by the Commission shall be executed by the utilities that are subject to this subsection (c). The long-term renewable resources procurement plan shall allocate up to $50,000,000 per delivery year to fund the programs, and the plan shall determine the amount of funding to be apportioned to the programs identified in subsection (b) of Section 1-56 of this Act; provided that for the delivery years beginning June 1, 2021, June 1, 2022, and June 1, 2023, the long-term renewable resources procurement plan may average the annual budgets over a 3-year period to account for program ramp-up. For the delivery years beginning June 1, 2021, June 1, 2024, June 1, 2027, and June 1, 2030 and additional $10,000,000 shall be provided to the Department of Commerce and Economic Opportunity to implement the workforce development programs and reporting as outlined in Section 16-108.12 of the Public Utilities Act. In making the determinations required under this subparagraph (O), the Commission shall consider the experience and performance under the programs and any evaluation reports. The Commission shall also provide for an independent evaluation of those programs on a periodic basis that are funded under this subparagraph (O).

(P) All programs and procurements under this subsection (c) shall be designed to encourage participating projects to use a diverse and equitable workforce and a diverse set of contractors, including minority-owned businesses, disadvantaged businesses, trade unions, graduates of any workforce training programs administered under this Act, and small businesses.

The Agency shall develop a method to optimize procurement of renewable energy credits from proposed utility-scale projects that are located in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act. If this requirement conflicts with other provisions of law or the Agency determines that full compliance with the requirements of this subparagraph (P) would be unreasonably costly or administratively impractical, the Agency is to propose alternative approaches to achieve development of renewable energy resources in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act or seek an exemption from this requirement from the Commission.

(Q) Each facility listed in subitems (i) through (ix) of item (1) of this subparagraph (Q) for which a renewable energy credit delivery contract is signed after the effective date of this amendatory Act of the 102nd General Assembly is subject to the following requirements through the Agency's long-term renewable resources procurement plan:

(1) Each facility shall be subject to the prevailing wage requirements included in the Prevailing Wage Act. The Agency shall require verification that all construction performed on the facility by the renewable energy credit delivery contract holder, its contractors, or its subcontractors relating to construction of the facility is performed by construction employees receiving an amount for that work equal to or greater than the general prevailing rate, as that term is defined in Section 2 3 of the Prevailing Wage Act. For purposes of this item (1), "house of worship" means property that is both (1) used exclusively by a religious society or body of persons as a place for religious exercise or religious worship and (2) recognized as exempt from taxation pursuant to Section 15-40 of the Property Tax Code. This item (1) shall apply to any the following:

(i) all new utility-scale wind projects;

(ii) all new utility-scale photovoltaic projects and repowered wind projects;

(iii) all new brownfield photovoltaic projects;

(iv) all new photovoltaic community renewable energy facilities that qualify for item (iii) of subparagraph (K) of this paragraph (1);

(v) all new community driven community photovoltaic projects that qualify for item (v) of subparagraph (K) of this paragraph (1);

(vi) all new photovoltaic projects on public school land that qualify for item (iv) of subparagraph (K) of this paragraph (1);

(vii) all new photovoltaic distributed renewable energy generation devices that (1) qualify for item (i) of subparagraph (K) of this paragraph (1); (2) are not projects that serve single-family or multi-family residential buildings; and (3) are not houses of worship where the aggregate capacity including colocated collocated projects would not exceed 100 kilowatts;

(viii) all new photovoltaic distributed renewable energy generation devices that (1) qualify for item (ii) of subparagraph (K) of this paragraph (1); (2) are not projects that serve single-family or multi-family residential buildings; and (3) are not houses of worship where the aggregate capacity including colocated collocated projects would not exceed 100 kilowatts;

(ix) all new, modernized, or retooled hydropower facilities.

(2) Renewable energy credits procured from new utility-scale wind projects, new utility-scale solar projects, new brownfield solar projects, repowered wind projects, and retooled hydropower facilities pursuant to Agency procurement events occurring after the effective date of this amendatory Act of the 102nd General Assembly must be from facilities built by general contractors that must enter into a project labor agreement, as defined by this Act, prior to construction. The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency in this item (2) shall be considered commercially sensitive information. At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The agreement must also specify the terms and conditions as defined by this Act.

(2.5) Energy storage credits procured from battery storage projects pursuant to Agency procurement events and additional energy storage resources procured in accordance with subparagraph (B) of paragraph (3) of subsection (d-20) of this Section pursuant to Agency procurement events occurring after the effective date of this amendatory Act of the 104th General Assembly must be from facilities built by general contractors that must enter into a project labor agreement prior to construction. The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency pursuant to this item (2.5) shall be considered commercially sensitive information. At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The agreement must also specify the terms and conditions, as defined by this Act.

(3) It is the intent of this Section to ensure that economic development occurs across Illinois communities, that emerging businesses may grow, and that there is improved access to the clean energy economy by persons who have greater economic burdens to success. The Agency shall take into consideration the unique cost of compliance of this subparagraph (Q) that might be borne by equity eligible contractors, shall include such costs when determining the price of renewable energy credits in the Adjustable Block program, and shall take such costs into consideration in a nondiscriminatory manner when comparing bids for competitive procurements. The Agency shall consider costs associated with compliance whether in the development, financing, or construction of projects. The Agency shall periodically review the assumptions in these costs and may adjust prices, in compliance with subparagraph (M) of this paragraph (1).

(R) In its long-term renewable resources procurement plan, the Agency shall establish a self-direct renewable portfolio standard compliance program for eligible self-direct customers that purchase renewable energy credits from utility-scale wind and solar projects through long-term agreements for purchase of renewable energy credits as described in this Section. Such long-term agreements may include the purchase of energy or other products on a physical or financial basis and may involve an alternative retail electric supplier as defined in Section 16-102 of the Public Utilities Act. This program shall take effect in the delivery year commencing June 1, 2023.

(1) For the purposes of this subparagraph:

"Eligible self-direct customer" means any retail customers of an electric utility that serves 3,000,000 or more retail customers in the State and whose total highest 30-minute demand was more than 10,000 kilowatts, or any retail customers of an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State and whose total highest 15-minute demand was more than 10,000 kilowatts.

"Retail customer" has the meaning set forth in Section 16-102 of the Public Utilities Act and multiple retail customer accounts under the same corporate parent may aggregate their account demands to meet the 10,000 kilowatt threshold. The criteria for determining whether this subparagraph is applicable to a retail customer shall be based on the 12 consecutive billing periods prior to the start of the year in which the application is filed.

(2) For renewable energy credits to count toward the self-direct renewable portfolio standard compliance program, they must:

(i) qualify as renewable energy credits as defined in Section 1-10 of this Act;

(ii) be sourced from one or more renewable energy generating facilities that comply with the geographic requirements as set forth in subparagraph (I) of paragraph (1) of subsection (c) as interpreted through the Agency's long-term renewable resources procurement plan, or, where applicable, the geographic requirements that governed utility-scale renewable energy credits at the time the eligible self-direct customer entered into the applicable renewable energy credit purchase agreement;

(iii) be procured through long-term contracts with term lengths of at least 10 years either directly with the renewable energy generating facility or through a bundled power purchase agreement, a virtual power purchase agreement, an agreement between the renewable generating facility, an alternative retail electric supplier, and the customer, or such other structure as is permissible under this subparagraph (R);

(iv) be equivalent in volume to at least 40% of the eligible self-direct customer's usage, determined annually by the eligible self-direct customer's usage during the previous delivery year, measured to the nearest megawatt-hour;

(v) be retired by or on behalf of the large energy customer;

(vi) be sourced from new utility-scale wind projects or new utility-scale solar projects; and

(vii) if the contracts for renewable energy credits are entered into after the effective date of this amendatory Act of the 102nd General Assembly, the new utility-scale wind projects or new utility-scale solar projects must comply with the requirements established in subparagraphs (P) and (Q) of paragraph (1) of this subsection (c) and subsection (c-10).

(3) The self-direct renewable portfolio standard compliance program shall be designed to allow eligible self-direct customers to procure new renewable energy credits from new utility-scale wind projects or new utility-scale photovoltaic projects. The Agency shall annually determine the amount of utility-scale renewable energy credits it will include each year from the self-direct renewable portfolio standard compliance program, subject to receiving qualifying applications. In making this determination, the Agency shall evaluate publicly available analyses and studies of the potential market size for utility-scale renewable energy long-term purchase agreements by commercial and industrial energy customers and make that report publicly available. If demand for participation in the self-direct renewable portfolio standard compliance program exceeds availability, the Agency shall ensure participation is evenly split between commercial and industrial users to the extent there is sufficient demand from both customer classes. Each renewable energy credit procured pursuant to this subparagraph (R) by a self-direct customer shall reduce the total volume of renewable energy credits the Agency is otherwise required to procure from new utility-scale projects pursuant to subparagraph (C) of paragraph (1) of this subsection (c) on behalf of contracting utilities where the eligible self-direct customer is located. The self-direct customer shall file an annual compliance report with the Agency pursuant to terms established by the Agency through its long-term renewable resources procurement plan to be eligible for participation in this program. Customers must provide the Agency with their most recent electricity billing statements or other information deemed necessary by the Agency to demonstrate they are an eligible self-direct customer.

(4) The Commission shall approve a reduction in the volumetric charges collected pursuant to Section 16-108 of the Public Utilities Act for approved eligible self-direct customers equivalent to the anticipated cost of renewable energy credit deliveries under contracts for new utility-scale wind and new utility-scale solar entered for each delivery year after the large energy customer begins retiring eligible new utility-scale utility scale renewable energy credits for self-compliance. The self-direct credit amount shall be determined annually and is equal to the estimated portion of the cost authorized by subparagraph (E) of paragraph (1) of this subsection (c) that supported the annual procurement of utility-scale renewable energy credits in the prior delivery year using a methodology described in the long-term renewable resources procurement plan, expressed on a per kilowatthour basis, and does not include (i) costs associated with any contracts entered into before the delivery year in which the customer files the initial compliance report to be eligible for participation in the self-direct program, and (ii) costs associated with procuring renewable energy credits through existing and future contracts through the Adjustable Block Program, subsection (c-5) of this Section 1-75, and the Solar for All Program. The Agency shall assist the Commission in determining the current and future costs. The Agency must determine the self-direct credit amount for new and existing eligible self-direct customers and submit this to the Commission in an annual compliance filing. The Commission must approve the self-direct credit amount by June 1, 2023 and June 1 of each delivery year thereafter.

(5) Customers described in this subparagraph (R) shall apply, on a form developed by the Agency, to the Agency to be designated as a self-direct eligible customer. Once the Agency determines that a self-direct customer is eligible for participation in the program, the self-direct customer will remain eligible until the end of the term of the contract. Thereafter, application may be made not less than 12 months before the filing date of the long-term renewable resources procurement plan described in this Act. At a minimum, such application shall contain the following:

(i) the customer's certification that, at the time of the customer's application, the customer qualifies to be a self-direct eligible customer, including documents demonstrating that qualification;

(ii) the customer's certification that the customer has entered into or will enter into by the beginning of the applicable procurement year, one or more bilateral contracts for new wind projects or new photovoltaic projects, including supporting documentation;

(iii) certification that the contract or contracts for new renewable energy resources are long-term contracts with term lengths of at least 10 years, including supporting documentation;

(iv) certification of the quantities of renewable energy credits that the customer will purchase each year under such contract or contracts, including supporting documentation;

(v) proof that the contract is sufficient to produce renewable energy credits to be equivalent in volume to at least 40% of the large energy customer's usage from the previous delivery year, measured to the nearest megawatt-hour; and

(vi) certification that the customer intends to maintain the contract for the duration of the length of the contract.

(6) If a customer receives the self-direct credit but fails to properly procure and retire renewable energy credits as required under this subparagraph (R), the Commission, on petition from the Agency and after notice and hearing, may direct such customer's utility to recover the cost of the wrongfully received self-direct credits plus interest through an adder to charges assessed pursuant to Section 16-108 of the Public Utilities Act. Self-direct customers who knowingly fail to properly procure and retire renewable energy credits and do not notify the Agency are ineligible for continued participation in the self-direct renewable portfolio standard compliance program.

(2) (Blank).

(3) (Blank).

(4) The electric utility shall retire all renewable energy credits used to comply with the standard.

(5) Beginning with the 2010 delivery year and ending June 1, 2017, an electric utility subject to this subsection (c) shall apply the lesser of the maximum alternative compliance payment rate or the most recent estimated alternative compliance payment rate for its service territory for the corresponding compliance period, established pursuant to subsection (d) of Section 16-115D of the Public Utilities Act to its retail customers that take service pursuant to the electric utility's hourly pricing tariff or tariffs. The electric utility shall retain all amounts collected as a result of the application of the alternative compliance payment rate or rates to such customers, and, beginning in 2011, the utility shall include in the information provided under item (1) of subsection (d) of Section 16-111.5 of the Public Utilities Act the amounts collected under the alternative compliance payment rate or rates for the prior year ending May 31. Notwithstanding any limitation on the procurement of renewable energy resources imposed by item (2) of this subsection (c), the Agency shall increase its spending on the purchase of renewable energy resources to be procured by the electric utility for the next plan year by an amount equal to the amounts collected by the utility under the alternative compliance payment rate or rates in the prior year ending May 31.

(6) The electric utility shall be entitled to recover all of its costs associated with the procurement of renewable energy credits under plans approved under this Section and Section 16-111.5 of the Public Utilities Act. These costs shall include associated reasonable expenses for implementing the procurement programs, including, but not limited to, the costs of administering and evaluating the Adjustable Block program, through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act.

(7) Renewable energy credits procured from new photovoltaic projects or new distributed renewable energy generation devices under this Section after June 1, 2017 (the effective date of Public Act 99-906) must be procured from devices installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

In meeting the renewable energy requirements of this subsection (c), to the extent feasible and consistent with State and federal law, the renewable energy credit procurements, Adjustable Block solar program, and community renewable generation program shall provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(c-5) Procurement of renewable energy credits from new renewable energy facilities installed at or adjacent to the sites of electric generating facilities that burn or burned coal as their primary fuel source.

(1) In addition to the procurement of renewable energy credits pursuant to long-term renewable resources procurement plans in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, the Agency shall conduct procurement events in accordance with this subsection (c-5) for the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new renewable energy facilities to be installed at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source and meet the other criteria specified in this subsection (c-5). For purposes of this subsection (c-5), "new renewable energy facility" means a new utility-scale solar project as defined in this Section 1-75. The renewable energy credits procured pursuant to this subsection (c-5) may be included or counted for purposes of compliance with the amounts of renewable energy credits required to be procured pursuant to subsection (c) of this Section to the extent that there are otherwise shortfalls in compliance with such requirements. The procurement of renewable energy credits by electric utilities pursuant to this subsection (c-5) shall be funded solely by revenues collected from the Coal to Solar and Energy Storage Initiative Charge provided for in this subsection (c-5) and subsection (i-5) of Section 16-108 of the Public Utilities Act, shall not be funded by revenues collected through any of the other funding mechanisms provided for in subsection (c) of this Section, and shall not be subject to the limitation imposed by subsection (c) on charges to retail customers for costs to procure renewable energy resources pursuant to subsection (c), and shall not be subject to any other requirements or limitations of subsection (c).

(2) The Agency shall conduct 2 procurement events to select owners of electric generating facilities meeting the eligibility criteria specified in this subsection (c-5) to enter into long-term contracts to sell renewable energy credits to electric utilities serving more than 300,000 retail customers in this State as of January 1, 2019. The first procurement event shall be conducted no later than March 31, 2022, unless the Agency elects to delay it, until no later than May 1, 2022, due to its overall volume of work, and shall be to select owners of electric generating facilities located in this State and south of federal Interstate Highway 80 that meet the eligibility criteria specified in this subsection (c-5). The second procurement event shall be conducted no sooner than September 30, 2022 and no later than October 31, 2022 and shall be to select owners of electric generating facilities located anywhere in this State that meet the eligibility criteria specified in this subsection (c-5). The Agency shall establish and announce a time period, which shall begin no later than 30 days prior to the scheduled date for the procurement event, during which applicants may submit applications to be selected as suppliers of renewable energy credits pursuant to this subsection (c-5). The eligibility criteria for selection as a supplier of renewable energy credits pursuant to this subsection (c-5) shall be as follows:

(A) The applicant owns an electric generating facility located in this State that: (i) as of January 1, 2016, burned coal as its primary fuel to generate electricity; and (ii) has, or had prior to retirement, an electric generating capacity of at least 150 megawatts. The electric generating facility can be either: (i) retired as of the date of the procurement event; or (ii) still operating as of the date of the procurement event.

(B) The applicant is not (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in (i) or (ii); and the coal-fueled electric generating facility was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act.

(C) If participating in the first procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 20 megawatts but no more than 100 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 2 megawatts and at most 10 megawatts. If participating in the second procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 5 megawatts but no more than 20 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 0.5 megawatts and at most one megawatt.

(D) The applicant agrees that the new renewable energy facility and the energy storage facility will be constructed or installed by a qualified entity or entities in compliance with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted thereunder.

(E) The applicant agrees that personnel operating the new renewable energy facility and the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function.

(F) The applicant commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the applicant's employees engaged in construction activities associated with the new renewable energy facility and the new energy storage facility and to the employees of applicant's contractors engaged in construction activities associated with the new renewable energy facility and the new energy storage facility, and that, on or before the commercial operation date of the new renewable energy facility, the applicant shall file a report with the Agency certifying that the requirements of this subparagraph (F) have been met.

(G) The applicant commits that if selected, it will negotiate a project labor agreement for the construction of the new renewable energy facility and associated energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

(H) The applicant commits to enter into a contract or contracts for the applicable duration to provide specified numbers of renewable energy credits each year from the new renewable energy facility to electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019, at a price of $30 per renewable energy credit. The price per renewable energy credit shall be fixed at $30 for the applicable duration and the renewable energy credits shall not be indexed renewable energy credits as provided for in item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act. The applicable duration of each contract shall be 20 years, unless the applicant is physically interconnected to the PJM Interconnection, LLC transmission grid and had a generating capacity of at least 1,200 megawatts as of January 1, 2021, in which case the applicable duration of the contract shall be 15 years.

(I) The applicant's application is certified by an officer of the applicant and by an officer of the applicant's ultimate parent company, if any.

(3) An applicant may submit applications to contract to supply renewable energy credits from more than one new renewable energy facility to be constructed at or adjacent to one or more qualifying electric generating facilities owned by the applicant. The Agency may select new renewable energy facilities to be located at or adjacent to the sites of more than one qualifying electric generation facility owned by an applicant to contract with electric utilities to supply renewable energy credits from such facilities.

(4) The Agency shall assess fees to each applicant to recover the Agency's costs incurred in receiving and evaluating applications, conducting the procurement event, developing contracts for sale, delivery and purchase of renewable energy credits, and monitoring the administration of such contracts, as provided for in this subsection (c-5), including fees paid to a procurement administrator retained by the Agency for one or more of these purposes.

(5) The Agency shall select the applicants and the new renewable energy facilities to contract with electric utilities to supply renewable energy credits in accordance with this subsection (c-5). In the first procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no less than 400,000 renewable energy credits per year for the applicable duration, assuming sufficient qualifying applications to supply, in the aggregate, at least that amount of renewable energy credits per year; and not more than 580,000 renewable energy credits per year for the applicable duration. In the second procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no more than 625,000 renewable energy credits per year less the amount of renewable energy credits each year contracted for as a result of the first procurement event, for the applicable durations. The number of renewable energy credits to be procured as specified in this paragraph (5) shall not be reduced based on renewable energy credits procured in the self-direct renewable energy credit compliance program established pursuant to subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75.

(6) The obligation to purchase renewable energy credits from the applicants and their new renewable energy facilities selected by the Agency shall be allocated to the electric utilities based on their respective percentages of kilowatthours delivered to delivery services customers to the aggregate kilowatthour deliveries by the electric utilities to delivery services customers for the year ended December 31, 2021. In order to achieve these allocation percentages between or among the electric utilities, the Agency shall require each applicant that is selected in the procurement event to enter into a contract with each electric utility for the sale and purchase of renewable energy credits from each new renewable energy facility to be constructed and operated by the applicant, with the sale and purchase obligations under the contracts to aggregate to the total number of renewable energy credits per year to be supplied by the applicant from the new renewable energy facility.

(7) The Agency shall submit its proposed selection of applicants, new renewable energy facilities to be constructed, and renewable energy credit amounts for each procurement event to the Commission for approval. The Commission shall, within 2 business days after receipt of the Agency's proposed selections, approve the proposed selections if it determines that the applicants and the new renewable energy facilities to be constructed meet the selection criteria set forth in this subsection (c-5) and that the Agency seeks approval for contracts of applicable durations aggregating to no more than the maximum amount of renewable energy credits per year authorized by this subsection (c-5) for the procurement event, at a price of $30 per renewable energy credit.

(8) The Agency, in conjunction with its procurement administrator if one is retained, the electric utilities, and potential applicants for contracts to produce and supply renewable energy credits pursuant to this subsection (c-5), shall develop a standard form contract for the sale, delivery and purchase of renewable energy credits pursuant to this subsection (c-5). Each contract resulting from the first procurement event shall allow for a commercial operation date for the new renewable energy facility of either June 1, 2023 or June 1, 2024, with such dates subject to adjustment as provided in this paragraph. Each contract resulting from the second procurement event shall provide for a commercial operation date on June 1 next occurring up to 48 months after execution of the contract. Each contract shall provide that the owner shall receive payments for renewable energy credits for the applicable durations beginning with the commercial operation date of the new renewable energy facility. The form contract shall provide for adjustments to the commercial operation and payment start dates as needed due to any delays in completing the procurement and contracting processes, in finalizing interconnection agreements and installing interconnection facilities, and in obtaining other necessary governmental permits and approvals. The form contract shall be, to the maximum extent possible, consistent with standard electric industry contracts for sale, delivery, and purchase of renewable energy credits while taking into account the specific requirements of this subsection (c-5). The form contract shall provide for over-delivery and under-delivery of renewable energy credits within reasonable ranges during each 12-month period and penalty, default, and enforcement provisions for failure of the selling party to deliver renewable energy credits as specified in the contract and to comply with the requirements of this subsection (c-5). The standard form contract shall specify that all renewable energy credits delivered to the electric utility pursuant to the contract shall be retired. The Agency shall make the proposed contracts available for a reasonable period for comment by potential applicants, and shall publish the final form contract at least 30 days before the date of the first procurement event.

(9) Coal to Solar and Energy Storage Initiative Charge.

(A) By no later than July 1, 2022, each electric utility that served more than 300,000 retail customers in this State as of January 1, 2019 shall file a tariff with the Commission for the billing and collection of a Coal to Solar and Energy Storage Initiative Charge in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act, with such tariff to be effective, following review and approval or modification by the Commission, beginning January 1, 2023. The tariff shall provide for the calculation and setting of the electric utility's Coal to Solar and Energy Storage Initiative Charge to collect revenues estimated to be sufficient, in the aggregate, (i) to enable the electric utility to pay for the renewable energy credits it has contracted to purchase in the delivery year beginning June 1, 2023 and each delivery year thereafter from new renewable energy facilities located at the sites of qualifying electric generating facilities, and (ii) to fund the grant payments to be made in each delivery year by the Department of Commerce and Economic Opportunity, or any successor department or agency, which shall be referred to in this subsection (c-5) as the Department, pursuant to paragraph (10) of this subsection (c-5). The electric utility's tariff shall provide for the billing and collection of the Coal to Solar and Energy Storage Initiative Charge on each kilowatthour of electricity delivered to its delivery services customers within its service territory and shall provide for an annual reconciliation of revenues collected with actual costs, in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act.

(B) Each electric utility shall remit on a monthly basis to the State Treasurer, for deposit in the Coal to Solar and Energy Storage Initiative Fund provided for in this subsection (c-5), the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge in the amount estimated to be needed by the Department for grant payments pursuant to grant contracts entered into by the Department pursuant to paragraph (10) of this subsection (c-5).

(10) Coal to Solar and Energy Storage Initiative Fund.

(A) The Coal to Solar and Energy Storage Initiative Fund is established as a special fund in the State treasury. The Coal to Solar and Energy Storage Initiative Fund is authorized to receive, by statutory deposit, that portion specified in item (B) of paragraph (9) of this subsection (c-5) of moneys collected by electric utilities through imposition of the Coal to Solar and Energy Storage Initiative Charge required by this subsection (c-5). The Coal to Solar and Energy Storage Initiative Fund shall be administered by the Department to provide grants to support the installation and operation of energy storage facilities at the sites of qualifying electric generating facilities meeting the criteria specified in this paragraph (10).

(B) The Coal to Solar and Energy Storage Initiative Fund shall not be subject to sweeps, administrative charges, or chargebacks, including, but not limited to, those authorized under Section 8h of the State Finance Act, that would in any way result in the transfer of those funds from the Coal to Solar and Energy Storage Initiative Fund to any other fund of this State or in having any such funds utilized for any purpose other than the express purposes set forth in this paragraph (10).

(C) The Department shall utilize up to $280,500,000 in the Coal to Solar and Energy Storage Initiative Fund for grants, assuming sufficient qualifying applicants, to support installation of energy storage facilities at the sites of up to 3 qualifying electric generating facilities located in the Midcontinent Independent System Operator, Inc., region in Illinois and the sites of up to 2 qualifying electric generating facilities located in the PJM Interconnection, LLC region in Illinois that meet the criteria set forth in this subparagraph (C). The criteria for receipt of a grant pursuant to this subparagraph (C) are as follows:

(1) the electric generating facility at the site has, or had prior to retirement, an electric generating capacity of at least 150 megawatts;

(2) the electric generating facility burns (or burned prior to retirement) coal as its primary source of fuel;

(3) if the electric generating facility is retired, it was retired subsequent to January 1, 2016;

(4) the owner of the electric generating facility has not been selected by the Agency pursuant to this subsection (c-5) of this Section to enter into a contract to sell renewable energy credits to one or more electric utilities from a new renewable energy facility located or to be located at or adjacent to the site at which the electric generating facility is located;

(5) the electric generating facility located at the site was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act;

(6) the electric generating facility at the site is not owned by (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in items (i) or (ii);

(7) the proposed energy storage facility at the site will have energy storage capacity of at least 37 megawatts;

(8) the owner commits to place the energy storage facility into commercial operation on either June 1, 2023, June 1, 2024, or June 1, 2025, with such date subject to adjustment as needed due to any delays in completing the grant contracting process, in finalizing interconnection agreements and in installing interconnection facilities, and in obtaining necessary governmental permits and approvals;

(9) the owner agrees that the new energy storage facility will be constructed or installed by a qualified entity or entities consistent with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted under that Section;

(10) the owner agrees that personnel operating the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function;

(11) the owner commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the owner's employees engaged in construction activities associated with the new energy storage facility and to the employees of the owner's contractors engaged in construction activities associated with the new energy storage facility, and that, on or before the commercial operation date of the new energy storage facility, the owner shall file a report with the Department certifying that the requirements of this subparagraph (11) have been met; and

(12) the owner commits that if selected to receive a grant, it will negotiate a project labor agreement for the construction of the new energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

The Department shall accept applications for this grant program until March 31, 2022 and shall announce the award of grants no later than June 1, 2022. The Department shall make the grant payments to a recipient in equal annual amounts for 10 years following the date the energy storage facility is placed into commercial operation. The annual grant payments to a qualifying energy storage facility shall be $110,000 per megawatt of energy storage capacity, with total annual grant payments pursuant to this subparagraph (C) for qualifying energy storage facilities not to exceed $28,050,000 in any year.

(D) Grants of funding for energy storage facilities pursuant to subparagraph (C) of this paragraph (10), from the Coal to Solar and Energy Storage Initiative Fund, shall be memorialized in grant contracts between the Department and the recipient. The grant contracts shall specify the date or dates in each year on which the annual grant payments shall be paid.

(E) All disbursements from the Coal to Solar and Energy Storage Initiative Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Director of the Department or by the person or persons designated by the Director of the Department for that purpose. The Comptroller is authorized to draw the warrants upon vouchers so signed. The Treasurer shall accept all written warrants so signed and shall be released from liability for all payments made on those warrants.

(11) Diversity, equity, and inclusion plans.

(A) Each applicant selected in a procurement event to contract to supply renewable energy credits in accordance with this subsection (c-5) and each owner selected by the Department to receive a grant or grants to support the construction and operation of a new energy storage facility or facilities in accordance with this subsection (c-5) shall, within 60 days following the Commission's approval of the applicant to contract to supply renewable energy credits or within 60 days following execution of a grant contract with the Department, as applicable, submit to the Commission a diversity, equity, and inclusion plan setting forth the applicant's or owner's numeric goals for the diversity composition of its supplier entities for the new renewable energy facility or new energy storage facility, as applicable, which shall be referred to for purposes of this paragraph (11) as the project, and the applicant's or owner's action plan and schedule for achieving those goals.

(B) For purposes of this paragraph (11), diversity composition shall be based on the percentage, which shall be a minimum of 25%, of eligible expenditures for contract awards for materials and services (which shall be defined in the plan) to business enterprises owned by minority persons, women, or persons with disabilities as defined in Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act, to LGBTQ business enterprises, to veteran-owned business enterprises, and to business enterprises located in environmental justice communities. The diversity composition goals of the plan may include eligible expenditures in areas for vendor or supplier opportunities in addition to development and construction of the project, and may exclude from eligible expenditures materials and services with limited market availability, limited production and availability from suppliers in the United States, such as solar panels and storage batteries, and material and services that are subject to critical energy infrastructure or cybersecurity requirements or restrictions. The plan may provide that the diversity composition goals may be met through Tier 1 Direct or Tier 2 subcontracting expenditures or a combination thereof for the project.

(C) The plan shall provide for, but not be limited to: (i) internal initiatives, including multi-tier initiatives, by the applicant or owner, or by its engineering, procurement and construction contractor if one is used for the project, which for purposes of this paragraph (11) shall be referred to as the EPC contractor, to enable diverse businesses to be considered fairly for selection to provide materials and services; (ii) requirements for the applicant or owner or its EPC contractor to proactively solicit and utilize diverse businesses to provide materials and services; and (iii) requirements for the applicant or owner or its EPC contractor to hire a diverse workforce for the project. The plan shall include a description of the applicant's or owner's diversity recruiting efforts both for the project and for other areas of the applicant's or owner's business operations. The plan shall provide for the imposition of financial penalties on the applicant's or owner's EPC contractor for failure to exercise best efforts to comply with and execute the EPC contractor's diversity obligations under the plan. The plan may provide for the applicant or owner to set aside a portion of the work on the project to serve as an incubation program for qualified businesses, as specified in the plan, owned by minority persons, women, persons with disabilities, LGBTQ persons, and veterans, and businesses located in environmental justice communities, seeking to enter the renewable energy industry.

(D) The applicant or owner may submit a revised or updated plan to the Commission from time to time as circumstances warrant. The applicant or owner shall file annual reports with the Commission detailing the applicant's or owner's progress in implementing its plan and achieving its goals and any modifications the applicant or owner has made to its plan to better achieve its diversity, equity and inclusion goals. The applicant or owner shall file a final report on the fifth June 1 following the commercial operation date of the new renewable energy resource or new energy storage facility, but the applicant or owner shall thereafter continue to be subject to applicable reporting requirements of Section 5-117 of the Public Utilities Act.

(c-10) Equity accountability system. It is the purpose of this subsection (c-10) to create an equity accountability system, which includes the minimum equity standards for all renewable energy procurements, the equity category of the Adjustable Block Program, and the equity prioritization for noncompetitive procurements, that is successful in advancing priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes. Further, it is the purpose of this subsection to ensure that this equity accountability system is successful in advancing equity across Illinois by providing access to the clean energy economy for businesses and workers from communities that have been historically excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes.

(1) Minimum equity standards. The Agency shall create programs with the purpose of increasing access to and development of equity eligible contractors, who are prime contractors and subcontractors, across all of the programs it manages. All applications for renewable energy credit procurements shall comply with specific minimum equity commitments. Starting in the delivery year immediately following the next long-term renewable resources procurement plan, at least 10% of the project workforce for each entity participating in a procurement program outlined in this subsection (c-10) must be done by equity eligible persons or equity eligible contractors. The Agency shall increase the minimum percentage each delivery year thereafter by increments that ensure a statewide average of 30% of the project workforce for each entity participating in a procurement program is done by equity eligible persons or equity eligible contractors by 2030. The Agency shall propose a schedule of percentage increases to the minimum equity standards in its draft revised renewable energy resources procurement plan submitted to the Commission for approval pursuant to paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. In determining these annual increases, the Agency shall have the discretion to establish different minimum equity standards for different types of procurements and different regions of the State if the Agency finds that doing so will further the purposes of this subsection (c-10). The proposed schedule of annual increases shall be revisited and updated on an annual basis. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, clean energy industry representatives, and community-based organizations that work with such persons and contractors.

(A) At the start of each delivery year, the Agency shall require a compliance plan from each entity participating in a procurement program of subsection (c) of this Section, and entities opting to comply with the minimum equity standard through the Illinois Solar for All Program under Section 1-56 of this Act, that demonstrates how they will achieve compliance with the minimum equity standard percentage for work completed in that delivery year. If an entity applies for its approved vendor or designee status between delivery years, the Agency shall require a compliance plan at the time of application.

(B) Halfway through each delivery year, the Agency shall require each entity participating in a procurement program to confirm that it will achieve compliance in that delivery year, when applicable. The Agency may offer corrective action plans to entities that are not on track to achieve compliance.

(C) At the end of each delivery year, each entity participating and completing work in that delivery year in a procurement program of subsection (c) shall submit a report to the Agency that demonstrates how it achieved compliance with the minimum equity standards percentage for that delivery year.

(D) The Agency shall prohibit participation in procurement programs by an approved vendor or designee, as applicable, or entities with which an approved vendor or designee, as applicable, shares a common parent company if an approved vendor or designee, as applicable, failed to meet the minimum equity standards for the prior delivery year. Waivers approved for lack of equity eligible persons or equity eligible contractors in a geographic area of a project shall not count against the approved vendor or designee. The Agency shall offer a corrective action plan for any such entities to assist them in obtaining compliance and shall allow continued access to procurement programs upon an approved vendor or designee demonstrating compliance.

(E) The Agency shall pursue efficiencies achieved by combining with other approved vendor or designee reporting.

(2) Equity accountability system within the Adjustable Block program. The equity category described in item (vi) of subparagraph (K) of subsection (c) is only available to applicants that are equity eligible contractors.

(3) Equity accountability system within competitive procurements. Through its long-term renewable resources procurement plan, the Agency shall develop requirements for ensuring that competitive procurement processes, including utility-scale solar, utility-scale wind, and brownfield site photovoltaic projects, advance the equity goals of this subsection (c-10). Subject to Commission approval, the Agency shall develop bid application requirements and a bid evaluation methodology for ensuring that utilization of equity eligible contractors, whether as bidders or as participants on project development, is optimized, including requiring that winning or successful applicants for utility-scale projects are or will partner with equity eligible contractors and giving preference to bids through which a higher portion of contract value flows to equity eligible contractors. To the extent practicable, entities participating in competitive procurements shall also be required to meet all the equity accountability requirements for approved vendors and their designees under this subsection (c-10). In developing these requirements, the Agency shall also consider whether equity goals can be further advanced through additional measures.

(4) In the first revision to the long-term renewable energy resources procurement plan and each revision thereafter, the Agency shall include the following:

(A) The current status and number of equity eligible contractors listed in the Energy Workforce Equity Database designed in subsection (c-25), including the number of equity eligible contractors with current certifications as issued by the Agency.

(B) A mechanism for measuring, tracking, and reporting project workforce at the approved vendor or designee level, as applicable, which shall include a measurement methodology and records to be made available for audit by the Agency or the Program Administrator.

(C) A program for approved vendors, designees, eligible persons, and equity eligible contractors to receive trainings, guidance, and other support from the Agency or its designee regarding the equity category outlined in item (vi) of subparagraph (K) of paragraph (1) of subsection (c) and in meeting the minimum equity standards of this subsection (c-10).

(D) A process for certifying equity eligible contractors and equity eligible persons. The certification process shall coordinate with the Energy Workforce Equity Database set forth in subsection (c-25).

(E) An application for waiver of the minimum equity standards of this subsection, which the Agency shall have the discretion to grant in rare circumstances. The Agency may grant such a waiver where the applicant provides evidence of significant efforts toward meeting the minimum equity commitment, including: use of the Energy Workforce Equity Database; efforts to hire or contract with entities that hire eligible persons; and efforts to establish contracting relationships with eligible contractors. The Agency shall support applicants in understanding the Energy Workforce Equity Database and other resources for pursuing compliance of the minimum equity standards. Waivers shall be project-specific, unless the Agency deems it necessary to grant a waiver across a portfolio of projects, and in effect for no longer than one year. Any waiver extension or subsequent waiver request from an applicant shall be subject to the requirements of this Section and shall specify efforts made to reach compliance. When considering whether to grant a waiver, and to what extent, the Agency shall consider the degree to which similarly situated applicants have been able to meet these minimum equity commitments. For repeated waiver requests for specific lack of eligible persons or eligible contractors available, the Agency shall make recommendations to target recruitment to add such eligible persons or eligible contractors to the database.

(5) The Agency shall collect information about work on projects or portfolios of projects subject to these minimum equity standards to ensure compliance with this subsection (c-10). Reporting in furtherance of this requirement may be combined with other annual reporting requirements. Such reporting shall include proof of certification of each equity eligible contractor or equity eligible person during the applicable time period.

(6) The Agency shall keep confidential all information and communication that provides private or personal information.

(7) Modifications to the equity accountability system. As part of the update of the long-term renewable resources procurement plan to be initiated in 2023, or sooner if the Agency deems necessary, the Agency shall determine the extent to which the equity accountability system described in this subsection (c-10) has advanced the goals of this amendatory Act of the 102nd General Assembly, including through the inclusion of equity eligible persons and equity eligible contractors in renewable energy credit projects. If the Agency finds that the equity accountability system has failed to meet those goals to its fullest potential, the Agency may revise the following criteria for future Agency procurements: (A) the percentage of project workforce, or other appropriate workforce measure, certified as equity eligible persons or equity eligible contractors; (B) definitions for equity investment eligible persons and equity investment eligible community; and (C) such other modifications necessary to advance the goals of this amendatory Act of the 102nd General Assembly effectively. Such revised criteria may also establish distinct equity accountability systems for different types of procurements or different regions of the State if the Agency finds that doing so will further the purposes of such programs. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, and community-based organizations that work with such persons and contractors.

(c-15) Racial discrimination elimination powers and process.

(1) Purpose. It is the purpose of this subsection to empower the Agency and other State actors to remedy racial discrimination in Illinois' clean energy economy as effectively and expediently as possible, including through the use of race-conscious remedies, such as race-conscious contracting and hiring goals, as consistent with State and federal law.

(2) Racial disparity and discrimination review process.

(A) Within one year after awarding contracts using the equity actions processes established in this Section, the Agency shall publish a report evaluating the effectiveness of the equity actions point criteria of this Section in increasing participation of equity eligible persons and equity eligible contractors. The report shall disaggregate participating workers and contractors by race and ethnicity. The report shall be forwarded to the Governor, the General Assembly, and the Illinois Commerce Commission and be made available to the public.

(B) As soon as is practicable thereafter, the Agency, in consultation with the Department of Commerce and Economic Opportunity, Department of Labor, and other agencies that may be relevant, shall commission and publish a disparity and availability study that measures the presence and impact of discrimination on minority businesses and workers in Illinois' clean energy economy. The Agency may hire consultants and experts to conduct the disparity and availability study, with the retention of those consultants and experts exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Illinois Power Agency shall forward a copy of its findings and recommendations to the Governor, the General Assembly, and the Illinois Commerce Commission. If the disparity and availability study establishes a strong basis in evidence that there is discrimination in Illinois' clean energy economy, the Agency, Department of Commerce and Economic Opportunity, Department of Labor, Department of Corrections, and other appropriate agencies shall take appropriate remedial actions, including race-conscious remedial actions as consistent with State and federal law, to effectively remedy this discrimination. Such remedies may include modification of the equity accountability system as described in subsection (c-10).

(c-20) Program data collection.

(1) Purpose. Data collection, data analysis, and reporting are critical to ensure that the benefits of the clean energy economy provided to Illinois residents and businesses are equitably distributed across the State. The Agency shall collect data from program applicants in order to track and improve equitable distribution of benefits across Illinois communities for all procurements the Agency conducts. The Agency shall use this data to, among other things, measure any potential impact of racial discrimination on the distribution of benefits and provide information necessary to correct any discrimination through methods consistent with State and federal law.

(2) Agency collection of program data. The Agency shall collect demographic and geographic data for each entity awarded contracts under any Agency-administered program.

(3) Required information to be collected. The Agency shall collect the following information from applicants and program participants where applicable:

(A) demographic information, including racial or ethnic identity for real persons employed, contracted, or subcontracted through the program and owners of businesses or entities that apply to receive renewable energy credits from the Agency;

(B) geographic location of the residency of real persons employed, contracted, or subcontracted through the program and geographic location of the headquarters of the business or entity that applies to receive renewable energy credits from the Agency; and

(C) any other information the Agency determines is necessary for the purpose of achieving the purpose of this subsection.

(4) Publication of collected information. The Agency shall publish, at least annually, information on the demographics of program participants on an aggregate basis.

(5) Nothing in this subsection shall be interpreted to limit the authority of the Agency, or other agency or department of the State, to require or collect demographic information from applicants of other State programs.

(c-25) Energy Workforce Equity Database.

(1) The Agency, in consultation with the Department of Commerce and Economic Opportunity, shall create an Energy Workforce Equity Database, and may contract with a third party to do so ("database program administrator"). If the Department decides to contract with a third party, that third party shall be exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Energy Workforce Equity Database shall be a searchable database of suppliers, vendors, and subcontractors for clean energy industries that is:

(A) publicly accessible;

(B) easy for people to find and use;

(C) organized by company specialty or field;

(D) region-specific; and

(E) populated with information including, but not limited to, contacts for suppliers, vendors, or subcontractors who are minority and women-owned business enterprise certified or who participate or have participated in any of the programs described in this Act.

(2) The Agency shall create an easily accessible, public facing online tool using the database information that includes, at a minimum, the following:

(A) a map of environmental justice and equity investment eligible communities;

(B) job postings and recruiting opportunities;

(C) a means by which recruiting clean energy companies can find and interact with current or former participants of clean energy workforce training programs;

(D) information on workforce training service providers and training opportunities available to prospective workers;

(E) renewable energy company diversity reporting;

(F) a list of equity eligible contractors with their contact information, types of work performed, and locations worked in;

(G) reporting on outcomes of the programs described in the workforce programs of the Energy Transition Act, including information such as, but not limited to, retention rate, graduation rate, and placement rates of trainees; and

(H) information about the Jobs and Environmental Justice Grant Program, the Clean Energy Jobs and Justice Fund, and other sources of capital.

(3) The Agency shall ensure the database is regularly updated to ensure information is current and shall coordinate with the Department of Commerce and Economic Opportunity to ensure that it includes information on individuals and entities that are or have participated in the Clean Jobs Workforce Network Program, Clean Energy Contractor Incubator Program, Returning Residents Clean Jobs Training Program, or Clean Energy Primes Contractor Accelerator Program.

(c-30) Enforcement of minimum equity standards. All entities seeking renewable energy credits must submit an annual report to demonstrate compliance with each of the equity commitments required under subsection (c-10). If the Agency concludes the entity has not met or maintained its minimum equity standards required under the applicable subparagraphs under subsection (c-10), the Agency shall deny the entity's ability to participate in procurement programs in subsection (c), including by withholding approved vendor or designee status. The Agency may require the entity to enter into a corrective action plan. An entity that is not recertified for failing to meet required equity actions in subparagraph (c-10) may reapply once they have a corrective action plan and achieve compliance with the minimum equity standards.

(d) Clean coal portfolio standard.

(1) The procurement plans shall include electricity generated using clean coal. Each utility shall enter into one or more sourcing agreements with the initial clean coal facility, as provided in paragraph (3) of this subsection (d), covering electricity generated by the initial clean coal facility representing at least 5% of each utility's total supply to serve the load of eligible retail customers in 2015 and each year thereafter, as described in paragraph (3) of this subsection (d), subject to the limits specified in paragraph (2) of this subsection (d). It is the goal of the State that by January 1, 2025, 25% of the electricity used in the State shall be generated by cost-effective clean coal facilities. For purposes of this subsection (d), "cost-effective" means that the expenditures pursuant to such sourcing agreements do not cause the limit stated in paragraph (2) of this subsection (d) to be exceeded and do not exceed cost-based benchmarks, which shall be developed to assess all expenditures pursuant to such sourcing agreements covering electricity generated by clean coal facilities, other than the initial clean coal facility, by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

A utility party to a sourcing agreement shall immediately retire any emission credits that it receives in connection with the electricity covered by such agreement.

Utilities shall maintain adequate records documenting the purchases under the sourcing agreement to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act.

A utility shall be deemed to have complied with the clean coal portfolio standard specified in this subsection (d) if the utility enters into a sourcing agreement as required by this subsection (d).

(2) For purposes of this subsection (d), the required execution of sourcing agreements with the initial clean coal facility for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the planning year ending immediately prior to the agreement's execution. For purposes of this subsection (d), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges and add-on taxes.

Notwithstanding the requirements of this subsection (d), the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any given year shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to:

(A) in 2010, no more than 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(B) in 2011, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2010 or 1% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(C) in 2012, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2011 or 1.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(D) in 2013, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2012 or 2% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009; and

(E) thereafter, the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of (i) 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or (ii) the incremental amount per kilowatthour paid for these resources in 2013. These requirements may be altered only as provided by statute.

No later than June 30, 2015, the Commission shall review the limitation on the total amount paid under sourcing agreements, if any, with clean coal facilities pursuant to this subsection (d) and report to the General Assembly its findings as to whether that limitation unduly constrains the amount of electricity generated by cost-effective clean coal facilities that is covered by sourcing agreements.

(3) Initial clean coal facility. In order to promote development of clean coal facilities in Illinois, each electric utility subject to this Section shall execute a sourcing agreement to source electricity from a proposed clean coal facility in Illinois (the "initial clean coal facility") that will have a nameplate capacity of at least 500 MW when commercial operation commences, that has a final Clean Air Act permit on June 1, 2009 (the effective date of Public Act 95-1027), and that will meet the definition of clean coal facility in Section 1-10 of this Act when commercial operation commences. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of paragraph (4) of this subsection (d) and shall be executed within 90 days after any such approval by the General Assembly. The Agency and the Commission shall have authority to inspect all books and records associated with the initial clean coal facility during the term of such a sourcing agreement. A utility's sourcing agreement for electricity produced by the initial clean coal facility shall include:

(A) a formula contractual price (the "contract price") approved pursuant to paragraph (4) of this subsection (d), which shall:

(i) be determined using a cost of service methodology employing either a level or deferred capital recovery component, based on a capital structure consisting of 45% equity and 55% debt, and a return on equity as may be approved by the Federal Energy Regulatory Commission, which in any case may not exceed the lower of 11.5% or the rate of return approved by the General Assembly pursuant to paragraph (4) of this subsection (d); and

(ii) provide that all miscellaneous net revenue, including but not limited to net revenue from the sale of emission allowances, if any, substitute natural gas, if any, grants or other support provided by the State of Illinois or the United States Government, firm transmission rights, if any, by-products produced by the facility, energy or capacity derived from the facility and not covered by a sourcing agreement pursuant to paragraph (3) of this subsection (d) or item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, whether generated from the synthesis gas derived from coal, from SNG, or from natural gas, shall be credited against the revenue requirement for this initial clean coal facility;

(B) power purchase provisions, which shall:

(i) provide that the utility party to such sourcing agreement shall pay the contract price for electricity delivered under such sourcing agreement;

(ii) require delivery of electricity to the regional transmission organization market of the utility that is party to such sourcing agreement;

(iii) require the utility party to such sourcing agreement to buy from the initial clean coal facility in each hour an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount purchased by the utility in any year will be limited by paragraph (2) of this subsection (d); and

(iv) be considered pre-existing contracts in such utility's procurement plans for eligible retail customers;

(C) contract for differences provisions, which shall:

(i) require the utility party to such sourcing agreement to contract with the initial clean coal facility in each hour with respect to an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the utility's service territory in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount paid by the utility in any year will be limited by paragraph (2) of this subsection (d);

(ii) provide that the utility's payment obligation in respect of the quantity of electricity determined pursuant to the preceding clause (i) shall be limited to an amount equal to (1) the difference between the contract price determined pursuant to subparagraph (A) of paragraph (3) of this subsection (d) and the day-ahead price for electricity delivered to the regional transmission organization market of the utility that is party to such sourcing agreement (or any successor delivery point at which such utility's supply obligations are financially settled on an hourly basis) (the "reference price") on the day preceding the day on which the electricity is delivered to the initial clean coal facility busbar, multiplied by (2) the quantity of electricity determined pursuant to the preceding clause (i); and

(iii) not require the utility to take physical delivery of the electricity produced by the facility;

(D) general provisions, which shall:

(i) specify a term of no more than 30 years, commencing on the commercial operation date of the facility;

(ii) provide that utilities shall maintain adequate records documenting purchases under the sourcing agreements entered into to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act;

(iii) provide that all costs associated with the initial clean coal facility will be periodically reported to the Federal Energy Regulatory Commission and to purchasers in accordance with applicable laws governing cost-based wholesale power contracts;

(iv) permit the Illinois Power Agency to assume ownership of the initial clean coal facility, without monetary consideration and otherwise on reasonable terms acceptable to the Agency, if the Agency so requests no less than 3 years prior to the end of the stated contract term;

(v) require the owner of the initial clean coal facility to provide documentation to the Commission each year, starting in the facility's first year of commercial operation, accurately reporting the quantity of carbon emissions from the facility that have been captured and sequestered and report any quantities of carbon released from the site or sites at which carbon emissions were sequestered in prior years, based on continuous monitoring of such sites. If, in any year after the first year of commercial operation, the owner of the facility fails to demonstrate that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon dioxide into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The cost of such offsets for the facility that are not recoverable shall not exceed $15 million in any given year. No costs of any such purchases of carbon offsets may be recovered from a utility or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements specified in paragraph (3) of this subsection (d) shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General. The Commission may, in the course of the review specified in item (vii), reduce the allowable return on equity for the facility if the facility willfully fails to comply with the carbon capture and sequestration requirements set forth in this item (v);

(vi) include limits on, and accordingly provide for modification of, the amount the utility is required to source under the sourcing agreement consistent with paragraph (2) of this subsection (d);

(vii) require Commission review: (1) to determine the justness, reasonableness, and prudence of the inputs to the formula referenced in subparagraphs (A)(i) through (A)(iii) of paragraph (3) of this subsection (d), prior to an adjustment in those inputs including, without limitation, the capital structure and return on equity, fuel costs, and other operations and maintenance costs and (2) to approve the costs to be passed through to customers under the sourcing agreement by which the utility satisfies its statutory obligations. Commission review shall occur no less than every 3 years, regardless of whether any adjustments have been proposed, and shall be completed within 9 months;

(viii) limit the utility's obligation to such amount as the utility is allowed to recover through tariffs filed with the Commission, provided that neither the clean coal facility nor the utility waives any right to assert federal pre-emption or any other argument in response to a purported disallowance of recovery costs;

(ix) limit the utility's or alternative retail electric supplier's obligation to incur any liability until such time as the facility is in commercial operation and generating power and energy and such power and energy is being delivered to the facility busbar;

(x) provide that the owner or owners of the initial clean coal facility, which is the counterparty to such sourcing agreement, shall have the right from time to time to elect whether the obligations of the utility party thereto shall be governed by the power purchase provisions or the contract for differences provisions;

(xi) append documentation showing that the formula rate and contract, insofar as they relate to the power purchase provisions, have been approved by the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act;

(xii) provide that any changes to the terms of the contract, insofar as such changes relate to the power purchase provisions, are subject to review under the public interest standard applied by the Federal Energy Regulatory Commission pursuant to Sections 205 and 206 of the Federal Power Act; and

(xiii) conform with customary lender requirements in power purchase agreements used as the basis for financing non-utility generators.

(4) Effective date of sourcing agreements with the initial clean coal facility. Any proposed sourcing agreement with the initial clean coal facility shall not become effective unless the following reports are prepared and submitted and authorizations and approvals obtained:

(i) Facility cost report. The owner of the initial clean coal facility shall submit to the Commission, the Agency, and the General Assembly a front-end engineering and design study, a facility cost report, method of financing (including but not limited to structure and associated costs), and an operating and maintenance cost quote for the facility (collectively "facility cost report"), which shall be prepared in accordance with the requirements of this paragraph (4) of subsection (d) of this Section, and shall provide the Commission and the Agency access to the work papers, relied upon documents, and any other backup documentation related to the facility cost report.

(ii) Commission report. Within 6 months following receipt of the facility cost report, the Commission, in consultation with the Agency, shall submit a report to the General Assembly setting forth its analysis of the facility cost report. Such report shall include, but not be limited to, a comparison of the costs associated with electricity generated by the initial clean coal facility to the costs associated with electricity generated by other types of generation facilities, an analysis of the rate impacts on residential and small business customers over the life of the sourcing agreements, and an analysis of the likelihood that the initial clean coal facility will commence commercial operation by and be delivering power to the facility's busbar by 2016. To assist in the preparation of its report, the Commission, in consultation with the Agency, may hire one or more experts or consultants, the costs of which shall be paid for by the owner of the initial clean coal facility. The Commission and Agency may begin the process of selecting such experts or consultants prior to receipt of the facility cost report.

(iii) General Assembly approval. The proposed sourcing agreements shall not take effect unless, based on the facility cost report and the Commission's report, the General Assembly enacts authorizing legislation approving (A) the projected price, stated in cents per kilowatthour, to be charged for electricity generated by the initial clean coal facility, (B) the projected impact on residential and small business customers' bills over the life of the sourcing agreements, and (C) the maximum allowable return on equity for the project; and

(iv) Commission review. If the General Assembly enacts authorizing legislation pursuant to subparagraph (iii) approving a sourcing agreement, the Commission shall, within 90 days of such enactment, complete a review of such sourcing agreement. During such time period, the Commission shall implement any directive of the General Assembly, resolve any disputes between the parties to the sourcing agreement concerning the terms of such agreement, approve the form of such agreement, and issue an order finding that the sourcing agreement is prudent and reasonable.

The facility cost report shall be prepared as follows:

(A) The facility cost report shall be prepared by duly licensed engineering and construction firms detailing the estimated capital costs payable to one or more contractors or suppliers for the engineering, procurement and construction of the components comprising the initial clean coal facility and the estimated costs of operation and maintenance of the facility. The facility cost report shall include:

(i) an estimate of the capital cost of the core plant based on one or more front end engineering and design studies for the gasification island and related facilities. The core plant shall include all civil, structural, mechanical, electrical, control, and safety systems.

(ii) an estimate of the capital cost of the balance of the plant, including any capital costs associated with sequestration of carbon dioxide emissions and all interconnects and interfaces required to operate the facility, such as transmission of electricity, construction or backfeed power supply, pipelines to transport substitute natural gas or carbon dioxide, potable water supply, natural gas supply, water supply, water discharge, landfill, access roads, and coal delivery.

The quoted construction costs shall be expressed in nominal dollars as of the date that the quote is prepared and shall include capitalized financing costs during construction, taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the construction cost quote is expressed.

(B) The front end engineering and design study for the gasification island and the cost study for the balance of plant shall include sufficient design work to permit quantification of major categories of materials, commodities and labor hours, and receipt of quotes from vendors of major equipment required to construct and operate the clean coal facility.

(C) The facility cost report shall also include an operating and maintenance cost quote that will provide the estimated cost of delivered fuel, personnel, maintenance contracts, chemicals, catalysts, consumables, spares, and other fixed and variable operations and maintenance costs. The delivered fuel cost estimate will be provided by a recognized third party expert or experts in the fuel and transportation industries. The balance of the operating and maintenance cost quote, excluding delivered fuel costs, will be developed based on the inputs provided by duly licensed engineering and construction firms performing the construction cost quote, potential vendors under long-term service agreements and plant operating agreements, or recognized third party plant operator or operators.

The operating and maintenance cost quote (including the cost of the front end engineering and design study) shall be expressed in nominal dollars as of the date that the quote is prepared and shall include taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the operating and maintenance cost quote is expressed.

(D) The facility cost report shall also include an analysis of the initial clean coal facility's ability to deliver power and energy into the applicable regional transmission organization markets and an analysis of the expected capacity factor for the initial clean coal facility.

(E) Amounts paid to third parties unrelated to the owner or owners of the initial clean coal facility to prepare the core plant construction cost quote, including the front end engineering and design study, and the operating and maintenance cost quote will be reimbursed through Coal Development Bonds.

(5) Re-powering and retrofitting coal-fired power plants previously owned by Illinois utilities to qualify as clean coal facilities. During the 2009 procurement planning process and thereafter, the Agency and the Commission shall consider sourcing agreements covering electricity generated by power plants that were previously owned by Illinois utilities and that have been or will be converted into clean coal facilities, as defined by Section 1-10 of this Act. Pursuant to such procurement planning process, the owners of such facilities may propose to the Agency sourcing agreements with utilities and alternative retail electric suppliers required to comply with subsection (d) of this Section and item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, covering electricity generated by such facilities. In the case of sourcing agreements that are power purchase agreements, the contract price for electricity sales shall be established on a cost of service basis. In the case of sourcing agreements that are contracts for differences, the contract price from which the reference price is subtracted shall be established on a cost of service basis. The Agency and the Commission may approve any such utility sourcing agreements that do not exceed cost-based benchmarks developed by the procurement administrator, in consultation with the Commission staff, Agency staff and the procurement monitor, subject to Commission review and approval. The Commission shall have authority to inspect all books and records associated with these clean coal facilities during the term of any such contract.

(6) Costs incurred under this subsection (d) or pursuant to a contract entered into under this subsection (d) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

(d-5) Zero emission standard.

(1) Beginning with the delivery year commencing on June 1, 2017, the Agency shall, for electric utilities that serve at least 100,000 retail customers in this State, procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the actual amount of electricity delivered by each electric utility to retail customers in the State during calendar year 2014. For an electric utility serving fewer than 100,000 retail customers in this State that requested, under Section 16-111.5 of the Public Utilities Act, that the Agency procure power and energy for all or a portion of the utility's Illinois load for the delivery year commencing June 1, 2016, the Agency shall procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the portion of power and energy to be procured by the Agency for the utility. The duration of the contracts procured under this subsection (d-5) shall be for a term of 10 years ending May 31, 2027. The quantity of zero emission credits to be procured under the contracts shall be all of the zero emission credits generated by the zero emission facility in each delivery year; however, if the zero emission facility is owned by more than one entity, then the quantity of zero emission credits to be procured under the contracts shall be the amount of zero emission credits that are generated from the portion of the zero emission facility that is owned by the winning supplier.

The 16% value identified in this paragraph (1) is the average of the percentage targets in subparagraph (B) of paragraph (1) of subsection (c) of this Section for the 5 delivery years beginning June 1, 2017.

The procurement process shall be subject to the following provisions:

(A) Those zero emission facilities that intend to participate in the procurement shall submit to the Agency the following eligibility information for each zero emission facility on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the zero emission facility;

(ii) the amount of power generated annually for each of the years 2005 through 2015, and the projected zero emission credits to be generated over the remaining useful life of the zero emission facility, which shall be used to determine the capability of each facility;

(iii) the annual zero emission facility cost projections, expressed on a per megawatthour basis, over the next 6 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; non-fuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this item (iii), that the costs could reasonably be avoided only by ceasing operations of the zero emission facility; and

(iv) a commitment to continue operating, for the duration of the contract or contracts executed under the procurement held under this subsection (d-5), the zero emission facility that produces the zero emission credits to be procured in the procurement.

The information described in item (iii) of this subparagraph (A) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(B) The price for each zero emission credit procured under this subsection (d-5) for each delivery year shall be in an amount that equals the Social Cost of Carbon, expressed on a price per megawatthour basis. However, to ensure that the procurement remains affordable to retail customers in this State if electricity prices increase, the price in an applicable delivery year shall be reduced below the Social Cost of Carbon by the amount ("Price Adjustment") by which the market price index for the applicable delivery year exceeds the baseline market price index for the consecutive 12-month period ending May 31, 2016. If the Price Adjustment is greater than or equal to the Social Cost of Carbon in an applicable delivery year, then no payments shall be due in that delivery year. The components of this calculation are defined as follows:

(i) Social Cost of Carbon: The Social Cost of Carbon is $16.50 per megawatthour, which is based on the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each year of the program. Beginning with the delivery year commencing June 1, 2023, the price per megawatthour shall increase by $1 per megawatthour, and continue to increase by an additional $1 per megawatthour each delivery year thereafter.

(ii) Baseline market price index: The baseline market price index for the consecutive 12-month period ending May 31, 2016 is $31.40 per megawatthour, which is based on the sum of (aa) the average day-ahead energy price across all hours of such 12-month period at the PJM Interconnection LLC Northern Illinois Hub, (bb) 50% multiplied by the Base Residual Auction, or its successor, capacity price for the rest of the RTO zone group determined by PJM Interconnection LLC, divided by 24 hours per day, and (cc) 50% multiplied by the Planning Resource Auction, or its successor, capacity price for Zone 4 determined by the Midcontinent Independent System Operator, Inc., divided by 24 hours per day.

(iii) Market price index: The market price index for a delivery year shall be the sum of projected energy prices and projected capacity prices determined as follows:

(aa) Projected energy prices: the projected energy prices for the applicable delivery year shall be calculated once for the year using the forward market price for the PJM Interconnection, LLC Northern Illinois Hub. The forward market price shall be calculated as follows: the energy forward prices for each month of the applicable delivery year averaged for each trade date during the calendar year immediately preceding that delivery year to produce a single energy forward price for the delivery year. The forward market price calculation shall use data published by the Intercontinental Exchange, or its successor.

(bb) Projected capacity prices:

(I) For the delivery years commencing June 1, 2017, June 1, 2018, and June 1, 2019, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the rest of the RTO zone group as determined by PJM Interconnection LLC, divided by 24 hours per day and, (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

(II) For the delivery year commencing June 1, 2020, and each year thereafter, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the ComEd zone as determined by PJM Interconnection LLC, divided by 24 hours per day, and (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

For purposes of this subsection (d-5):

"Rest of the RTO" and "ComEd Zone" shall have the meaning ascribed to them by PJM Interconnection, LLC.

"RTO" means regional transmission organization.

(C) No later than 45 days after June 1, 2017 (the effective date of Public Act 99-906), the Agency shall publish its proposed zero emission standard procurement plan. The plan shall be consistent with the provisions of this paragraph (1) and shall provide that winning bids shall be selected based on public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. In particular, the selection of winning bids shall take into account the incremental environmental benefits resulting from the procurement, such as any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would cease to exist if the procurements were not held, including the preservation of zero emission facilities. The plan shall also describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement and given full effect.

For purposes of developing the plan, the Agency shall consider any reports issued by a State agency, board, or commission under House Resolution 1146 of the 98th General Assembly and paragraph (4) of subsection (d) of this Section, as well as publicly available analyses and studies performed by or for regional transmission organizations that serve the State and their independent market monitors.

Upon publishing of the zero emission standard procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 10 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 60 days later than June 1, 2017 (the effective date of Public Act 99-906), the Agency shall revise the plan as necessary based on the comments received and file its zero emission standard procurement plan with the Commission.

If the Commission determines that the plan will result in the procurement of cost-effective zero emission credits, then the Commission shall, after notice and hearing, but no later than 45 days after the Agency filed the plan, approve the plan or approve with modification. For purposes of this subsection (d-5), "cost effective" means the projected costs of procuring zero emission credits from zero emission facilities do not cause the limit stated in paragraph (2) of this subsection to be exceeded.

(C-5) As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the winning bids satisfy the public interest criteria described in subparagraph (C) of this paragraph (1) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of winning bids takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would have ceased to exist if the procurements had not been held, such as the preservation of zero emission facilities;

(iii) quantify the environmental benefit of preserving the resources identified in item (ii) of this subparagraph (C-5), including the following:

(aa) the value of avoided greenhouse gas emissions measured as the product of the zero emission facilities' output over the contract term multiplied by the U.S. Environmental Protection Agency eGrid subregion carbon dioxide emission rate and the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each delivery year; and

(bb) the costs of replacement with other zero carbon dioxide resources, including wind and photovoltaic, based upon the simple average of the following:

(I) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale wind projects in the procurement events specified in item (i) of subparagraph (G) of paragraph (1) of subsection (c) of this Section; and

(II) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects in the procurement events specified in item (ii) of subparagraph (G) of paragraph (1) of subsection (c) of this Section and, after January 1, 2015, renewable energy credits from photovoltaic distributed generation projects in procurement events held under subsection (c) of this Section.

Each utility shall enter into binding contractual arrangements with the winning suppliers.

The procurement described in this subsection (d-5), including, but not limited to, the execution of all contracts procured, shall be completed no later than May 10, 2017. Based on the effective date of Public Act 99-906, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (C) and (D) of this paragraph (1). The procurement and plan approval processes required by this subsection (d-5) shall be conducted in conjunction with the procurement and plan approval processes required by subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. Notwithstanding whether a procurement event is conducted under Section 16-111.5 of the Public Utilities Act, the Agency shall immediately initiate a procurement process on June 1, 2017 (the effective date of Public Act 99-906).

(D) Following the procurement event described in this paragraph (1) and consistent with subparagraph (B) of this paragraph (1), the Agency shall calculate the payments to be made under each contract for the next delivery year based on the market price index for that delivery year. The Agency shall publish the payment calculations no later than May 25, 2017 and every May 25 thereafter.

(E) Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the zero emission facility may, as applicable, suspend or terminate performance under the contracts in the following instances:

(i) A zero emission facility shall be excused from its performance under the contract for any cause beyond the control of the resource, including, but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of the foregoing cases, by exercise of commercially reasonable efforts the zero emission facility could not reasonably have been expected to avoid, and which, by the exercise of commercially reasonable efforts, it has been unable to overcome. In such event, the zero emission facility shall be excused from performance for the duration of the event, including, but not limited to, delivery of zero emission credits, and no payment shall be due to the zero emission facility during the duration of the event.

(ii) A zero emission facility shall be permitted to terminate the contract if legislation is enacted into law by the General Assembly that imposes or authorizes a new tax, special assessment, or fee on the generation of electricity, the ownership or leasehold of a generating unit, or the privilege or occupation of such generation, ownership, or leasehold of generation units by a zero emission facility. However, the provisions of this item (ii) do not apply to any generally applicable tax, special assessment or fee, or requirements imposed by federal law.

(iii) A zero emission facility shall be permitted to terminate the contract in the event that the resource requires capital expenditures in excess of $40,000,000 that were neither known nor reasonably foreseeable at the time it executed the contract and that a prudent owner or operator of such resource would not undertake.

(iv) A zero emission facility shall be permitted to terminate the contract in the event the Nuclear Regulatory Commission terminates the resource's license.

(F) If the zero emission facility elects to terminate a contract under subparagraph (E) of this paragraph (1), then the Commission shall reopen the docket in which the Commission approved the zero emission standard procurement plan under subparagraph (C) of this paragraph (1) and, after notice and hearing, enter an order acknowledging the contract termination election if such termination is consistent with the provisions of this subsection (d-5).

(2) For purposes of this subsection (d-5), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d-5), the total amount paid for electric service includes, without limitation, amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the total of zero emission credits procured under a procurement plan shall be subject to the limitations of this paragraph (2). For each delivery year, the contractual volume receiving payments in such year shall be reduced for all retail customers based on the amount necessary to limit the net increase that delivery year to the costs of those credits included in the amounts paid by eligible retail customers in connection with electric service to no more than 1.65% of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009. The result of this computation shall apply to and reduce the procurement for all retail customers, and all those customers shall pay the same single, uniform cents per kilowatthour charge under subsection (k) of Section 16-108 of the Public Utilities Act. To arrive at a maximum dollar amount of zero emission credits to be paid for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the delivery year immediately prior to the procurement, to all retail customers in its service territory. Unpaid contractual volume for any delivery year shall be paid in any subsequent delivery year in which such payments can be made without exceeding the amount specified in this paragraph (2). The calculations required by this paragraph (2) shall be made only once for each procurement plan year. Once the determination as to the amount of zero emission credits to be paid is made based on the calculations set forth in this paragraph (2), no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. All costs incurred under those contracts and in implementing this subsection (d-5) shall be recovered by the electric utility as provided in this Section.

No later than June 30, 2019, the Commission shall review the limitation on the amount of zero emission credits procured under this subsection (d-5) and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of cost-effective zero emission credits.

(3) Six years after the execution of a contract under this subsection (d-5), the Agency shall determine whether the actual zero emission credit payments received by the supplier over the 6-year period exceed the Average ZEC Payment. In addition, at the end of the term of a contract executed under this subsection (d-5), or at the time, if any, a zero emission facility's contract is terminated under subparagraph (E) of paragraph (1) of this subsection (d-5), then the Agency shall determine whether the actual zero emission credit payments received by the supplier over the term of the contract exceed the Average ZEC Payment, after taking into account any amounts previously credited back to the utility under this paragraph (3). If the Agency determines that the actual zero emission credit payments received by the supplier over the relevant period exceed the Average ZEC Payment, then the supplier shall credit the difference back to the utility. The amount of the credit shall be remitted to the applicable electric utility no later than 120 days after the Agency's determination, which the utility shall reflect as a credit on its retail customer bills as soon as practicable; however, the credit remitted to the utility shall not exceed the total amount of payments received by the facility under its contract.

For purposes of this Section, the Average ZEC Payment shall be calculated by multiplying the quantity of zero emission credits delivered under the contract times the average contract price. The average contract price shall be determined by subtracting the amount calculated under subparagraph (B) of this paragraph (3) from the amount calculated under subparagraph (A) of this paragraph (3), as follows:

(A) The average of the Social Cost of Carbon, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract.

(B) The average of the market price indices, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract, minus the baseline market price index, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5).

If the subtraction yields a negative number, then the Average ZEC Payment shall be zero.

(4) Cost-effective zero emission credits procured from zero emission facilities shall satisfy the applicable definitions set forth in Section 1-10 of this Act.

(5) The electric utility shall retire all zero emission credits used to comply with the requirements of this subsection (d-5).

(6) Electric utilities shall be entitled to recover all of the costs associated with the procurement of zero emission credits through an automatic adjustment clause tariff in accordance with subsection (k) and (m) of Section 16-108 of the Public Utilities Act, and the contracts executed under this subsection (d-5) shall provide that the utilities' payment obligations under such contracts shall be reduced if an adjustment is required under subsection (m) of Section 16-108 of the Public Utilities Act.

(7) This subsection (d-5) shall become inoperative on January 1, 2028.

(d-10) Nuclear Plant Assistance; carbon mitigation credits.

(1) The General Assembly finds:

(A) The health, welfare, and prosperity of all Illinois citizens require that the State of Illinois act to avoid and not increase carbon emissions from electric generation sources while continuing to ensure affordable, stable, and reliable electricity to all citizens.

(B) Absent immediate action by the State to preserve existing carbon-free energy resources, those resources may retire, and the electric generation needs of Illinois' retail customers may be met instead by facilities that emit significant amounts of carbon pollution and other harmful air pollutants at a high social and economic cost until Illinois is able to develop other forms of clean energy.

(C) The General Assembly finds that nuclear power generation is necessary for the State's transition to 100% clean energy, and ensuring continued operation of nuclear plants advances environmental and public health interests through providing carbon-free electricity while reducing the air pollution profile of the Illinois energy generation fleet.

(D) The clean energy attributes of nuclear generation facilities support the State in its efforts to achieve 100% clean energy.

(E) The State currently invests in various forms of clean energy, including, but not limited to, renewable energy, energy efficiency, and low-emission vehicles, among others.

(F) The Environmental Protection Agency commissioned an independent audit which provided a detailed assessment of the financial condition of the Illinois nuclear fleet to evaluate its financial viability and whether the environmental benefits of such resources were at risk. The report identified the risk of losing the environmental benefits of several specific nuclear units. The report also identified that the LaSalle County Generating Station will continue to operate through 2026 and therefore is not eligible to participate in the carbon mitigation credit program.

(G) Nuclear plants provide carbon-free energy, which helps to avoid many health-related negative impacts for Illinois residents.

(H) The procurement of carbon mitigation credits representing the environmental benefits of carbon-free generation will further the State's efforts at achieving 100% clean energy and decarbonizing the electricity sector in a safe, reliable, and affordable manner. Further, the procurement of carbon emission credits will enhance the health and welfare of Illinois residents through decreased reliance on more highly polluting generation.

(I) The General Assembly therefore finds it necessary to establish carbon mitigation credits to ensure decreased reliance on more carbon-intensive energy resources, for transitioning to a fully decarbonized electricity sector, and to help ensure health and welfare of the State's residents.

(2) As used in this subsection:

"Baseline costs" means costs used to establish a customer protection cap that have been evaluated through an independent audit of a carbon-free energy resource conducted by the Environmental Protection Agency that evaluated projected annual costs for operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this definition, that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource.

"Carbon mitigation credit" means a tradable credit that represents the carbon emission reduction attributes of one megawatt-hour of energy produced from a carbon-free energy resource.

"Carbon-free energy resource" means a generation facility that: (1) is fueled by nuclear power; and (2) is interconnected to PJM Interconnection, LLC.

(3) Procurement.

(A) Beginning with the delivery year commencing on June 1, 2022, the Agency shall, for electric utilities serving at least 3,000,000 retail customers in the State, seek to procure contracts for no more than approximately 54,500,000 cost-effective carbon mitigation credits from carbon-free energy resources because such credits are necessary to support current levels of carbon-free energy generation and ensure the State meets its carbon dioxide emissions reduction goals. The Agency shall not make a partial award of a contract for carbon mitigation credits covering a fractional amount of a carbon-free energy resource's projected output.

(B) Each carbon-free energy resource that intends to participate in a procurement shall be required to submit to the Agency the following information for the resource on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the carbon-free energy resource;

(ii) the amount of power generated annually for each of the past 10 years, which shall be used to determine the capability of each facility;

(iii) a commitment to be reflected in any contract entered into pursuant to this subsection (d-10) to continue operating the carbon-free energy resource at a capacity factor of at least 88% annually on average for the duration of the contract or contracts executed under the procurement held under this subsection (d-10), except in an instance described in subparagraph (E) of paragraph (1) of subsection (d-5) of this Section or made impracticable as a result of compliance with law or regulation;

(iv) financial need and the risk of loss of the environmental benefits of such resource, which shall include the following information:

(I) the carbon-free energy resource's cost projections, expressed on a per megawatt-hour basis, over the next 5 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this subitem (I), that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource; and

(II) the carbon-free energy resource's revenue projections, including energy, capacity, ancillary services, any other direct State support, known or anticipated federal attribute credits, known or anticipated tax credits, and any other direct federal support.

The information described in this subparagraph (B) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of the Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(C) The Agency shall solicit bids for the contracts described in this subsection (d-10) from carbon-free energy resources that have satisfied the requirements of subparagraph (B) of this paragraph (3). The contracts procured pursuant to a procurement event shall reflect, and be subject to, the following terms, requirements, and limitations:

(i) Contracts are for delivery of carbon mitigation credits, and are not energy or capacity sales contracts requiring physical delivery. Pursuant to item (iii), contract payments shall fully deduct the value of any monetized federal production tax credits, credits issued pursuant to a federal clean energy standard, and other federal credits if applicable.

(ii) Contracts for carbon mitigation credits shall commence with the delivery year beginning on June 1, 2022 and shall be for a term of 5 delivery years concluding on May 31, 2027.

(iii) The price per carbon mitigation credit to be paid under a contract for a given delivery year shall be equal to an accepted bid price less the sum of:

(I) one of the following energy price indices, selected by the bidder at the time of the bid for the term of the contract:

(aa) the weighted-average hourly day-ahead price for the applicable delivery year at the busbar of all resources procured pursuant to this subsection (d-10), weighted by actual production from the resources; or

(bb) the projected energy price for the PJM Interconnection, LLC Northern Illinois Hub for the applicable delivery year determined according to subitem (aa) of item (iii) of subparagraph (B) of paragraph (1) of subsection (d-5).

(II) the Base Residual Auction Capacity Price for the ComEd zone as determined by PJM Interconnection, LLC, divided by 24 hours per day, for the applicable delivery year for the first 3 delivery years, and then any subsequent delivery years unless the PJM Interconnection, LLC applies the Minimum Offer Price Rule to participating carbon-free energy resources because they supply carbon mitigation credits pursuant to this Section at which time, upon notice by the carbon-free energy resource to the Commission and subject to the Commission's confirmation, the value under this subitem shall be zero, as further described in the carbon mitigation credit procurement plan; and

(III) any value of monetized federal tax credits, direct payments, or similar subsidy provided to the carbon-free energy resource from any unit of government that is not already reflected in energy prices.

If the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net positive value, then the electric utility counterparty to the contract shall multiply such net value by the applicable contract quantity and remit the amount to the supplier.

To protect retail customers from retail rate impacts that may arise upon the initiation of carbon policy changes, if the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net negative value, then the supplier counterparty to the contract shall multiply such net value by the applicable contract quantity and remit such amount to the electric utility counterparty. The electric utility shall reflect such amounts remitted by suppliers as a credit on its retail customer bills as soon as practicable.

(iv) To ensure that retail customers in Northern Illinois do not pay more for carbon mitigation credits than the value such credits provide, and notwithstanding the provisions of this subsection (d-10), the Agency shall not accept bids for contracts that exceed a customer protection cap equal to the baseline costs of carbon-free energy resources.

The baseline costs for the applicable year shall be the following:

(I) For the delivery year beginning June 1, 2022, the baseline costs shall be an amount equal to $30.30 per megawatt-hour.

(II) For the delivery year beginning June 1, 2023, the baseline costs shall be an amount equal to $32.50 per megawatt-hour.

(III) For the delivery year beginning June 1, 2024, the baseline costs shall be an amount equal to $33.43 per megawatt-hour.

(IV) For the delivery year beginning June 1, 2025, the baseline costs shall be an amount equal to $33.50 per megawatt-hour.

(V) For the delivery year beginning June 1, 2026, the baseline costs shall be an amount equal to $34.50 per megawatt-hour.

An Environmental Protection Agency consultant forecast, included in a report issued April 14, 2021, projects that a carbon-free energy resource has the opportunity to earn on average approximately $30.28 per megawatt-hour, for the sale of energy and capacity during the time period between 2022 and 2027. Therefore, the sale of carbon mitigation credits provides the opportunity to receive an additional amount per megawatt-hour in addition to the projected prices for energy and capacity.

Although actual energy and capacity prices may vary from year-to-year, the General Assembly finds that this customer protection cap will help ensure that the cost of carbon mitigation credits will be less than its value, based upon the social cost of carbon identified in the Technical Support Document issued in February 2021 by the U.S. Interagency Working Group on Social Cost of Greenhouse Gases and the PJM Interconnection, LLC carbon dioxide marginal emission rate for 2020, and that a carbon-free energy resource receiving payment for carbon mitigation credits receives no more than necessary to keep those units in operation.

(D) No later than 7 days after the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall publish its proposed carbon mitigation credit procurement plan. The Plan shall provide that winning bids shall be selected by taking into consideration which resources best match public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. The selection of winning bids shall also take into account the incremental environmental benefits resulting from the procurement or procurements, such as any existing environmental benefits that are preserved by a procurement held under this subsection (d-10) and would cease to exist if the procurement were not held, including the preservation of carbon-free energy resources. For those bidders having the same public interest criteria score, the relative ranking of such bidders shall be determined by price. The Plan shall describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement. The Plan shall, to the extent practical and permissible by federal law, ensure that successful bidders make commercially reasonable efforts to apply for federal tax credits, direct payments, or similar subsidy programs that support carbon-free generation and for which the successful bidder is eligible. Upon publishing of the carbon mitigation credit procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 7 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 19 days later than the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall revise the plan as necessary based on the comments received and file its carbon mitigation credit procurement plan with the Commission.

(E) If the Commission determines that the plan is likely to result in the procurement of cost-effective carbon mitigation credits, then the Commission shall, after notice and hearing and opportunity for comment, but no later than 42 days after the Agency filed the plan, approve the plan or approve it with modification. For purposes of this subsection (d-10), "cost-effective" means carbon mitigation credits that are procured from carbon-free energy resources at prices that are within the limits specified in this paragraph (3). As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the selected carbon-free energy resources satisfy the public interest criteria described in this paragraph (3) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of carbon-free energy resources takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under this amendatory Act of the 102nd General Assembly and would have ceased to exist if the procurements had not been held, such as the preservation of carbon-free energy resources;

(iii) quantify the environmental benefit of preserving the carbon-free energy resources procured pursuant to this subsection (d-10), including the following:

(I) an assessment value of avoided greenhouse gas emissions measured as the product of the carbon-free energy resources' output over the contract term, using generally accepted methodologies for the valuation of avoided emissions; and

(II) an assessment of costs of replacement with other carbon-free energy resources and renewable energy resources, including wind and photovoltaic generation, based upon an assessment of the prices paid for renewable energy credits through programs and procurements conducted pursuant to subsection (c) of Section 1-75 of this Act, and the additional storage necessary to produce the same or similar capability of matching customer usage patterns.

(F) The procurements described in this paragraph (3), including, but not limited to, the execution of all contracts procured, shall be completed no later than December 3, 2021. The procurement and plan approval processes required by this paragraph (3) shall be conducted in conjunction with the procurement and plan approval processes required by Section 16-111.5 of the Public Utilities Act, to the extent practicable. However, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (D) and (E) of this paragraph (3) to meet the December 3, 2021 contract execution deadline. Following the completion of such procurements, and consistent with this paragraph (3), the Agency shall calculate the payments to be made under each contract in a timely fashion.

(F-1) Costs incurred by the electric utility pursuant to a contract authorized by this subsection (d-10) shall be deemed prudently incurred and reasonable in amount, and the electric utility shall be entitled to full cost recovery pursuant to a tariff or tariffs filed with the Commission.

(G) The counterparty electric utility shall retire all carbon mitigation credits used to comply with the requirements of this subsection (d-10).

(H) If a carbon-free energy resource is sold to another owner, the rights, obligations, and commitments under this subsection (d-10) shall continue to the subsequent owner.

(I) This subsection (d-10) shall become inoperative on January 1, 2028.

(d-20) Energy storage system portfolio standard.

(1) The General Assembly finds that the deployment of energy storage systems is necessary to successfully integrate high levels of renewable energy, to avoid the creation and increase of carbon emissions from electric generation sources, and to ensure affordable, stable, clean, reliable, and resilient electricity.

(2) The Agency shall develop an energy storage system resources procurement plan that includes the competitive procurement events, procurement programs, or both, as necessary (i) to meet the goals set forth in this subsection (d-20), (ii) to meet the planning requirements established under Sections 16-201 and 16-202 of the Public Utilities Act, (iii) to meet the clean energy policy established by Public Act 102-662, and (iv) to cause electric utilities serving more than 300,000 customers in the State as of January 1, 2019 to contract for energy storage resources. The energy storage system resources procurement plan approval processes shall be conducted consistent with the processes outlined in paragraph (6) of subsection (b) of Section 16-111.5 of the Public Utilities Act, with the initial energy storage system resources procurement plan released for comment in calendar year 2027. The Agency shall review and may revise the energy storage system resources procurement plan at least every 2 years. The Agency shall establish, and the Commission shall approve or approve as modified, an energy storage system resources procurement plan that includes:

(A) storage targets in addition to the initial procurements specified in paragraph (3) of this subsection (d-20) at levels identified through the integrated resource planning process outlined in Section 16-202 of the Public Utilities Act;

(B) a bid selection process that is based on the bid price, when compared with an equal energy storage duration and interconnected to the same independent system operator (ISO) or regional transmission organization (RTO), and that may provide for consideration of the following:

(i) the project's viability and ability to meet or exceed operational date targets;

(ii) the developer's experience;

(iii) requirements for demonstration of binding site control that are sufficient for proposed energy storage facilities;

(iv) the availability or dependence on any transmission expansion or upgrades needed; and

(v) other resource adequacy and reliability considerations;

(C) consideration of the need to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time;

(D) proposals for the financial support of energy storage systems using contract models, which may include, but are not limited to, the following:

(i) an indexed storage credit procurement, including payments to energy storage system owners or operators with any offsets and refunds for potential energy and capacity revenues;

(ii) support for energy storage system resources through contract structures that do not create contractual obligations on utilities that are not contingent on full and timely cost recovery, that avoid negative financial impacts on the utilities, and that are agreed upon by the utilities; and

(iii) other approaches as deemed suitable by the Agency and the Commission; and

(E) consideration that the Agency may include a methodology that could prioritize procurement of energy storage resources that are located in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act.

In developing its procurement plan and conducting the storage procurements outlined in this paragraph (2) and in paragraph (3), the Agency may use the services of expert consulting firms identified in paragraphs (1) and (2) of subsection (a) of this Section.

(3) Notwithstanding whether an energy storage system resources procurement plan has been approved, the following provisions shall apply to the Agency's initial procurement of energy storage system resources under this subsection (d-20):

(A) The Agency shall conduct an initial energy storage procurement on or before August 26, 2026 or 90 days after the effective date of this amendatory Act of the 104th General Assembly, whichever is earlier. For the purposes of this initial energy storage procurement, the Agency shall conduct a procurement that results in electric utilities that served more than 300,000 customers in the State as of January 1, 2019 contracting for at least 1,038 megawatts of cost-effective stand-alone energy storage systems that can achieve commercial operation on or before December 31, 2029 or an alternative date proposed by the Agency that is no later than December 31, 2030. The procurement target shall be separated for projects interconnected within Midcontinent Independent System Operator Local Resource Zone 4 (MISO Zone 4) and for projects interconnected within the PJM Interconnection, LLC ComEd Locational Deliverability Area (PJM ComEd Area) as follows:

(i) 450 megawatts in MISO Zone 4; and

(ii) 588 megawatts in the PJM ComEd Area.

For purposes of this subsection (d-20), "stand-alone" means systems that are (i) separately metered by a revenue-quality meter that satisfies the requirements of the RTO; (ii) operate independently without constraints or hindrances from other generation units; and (iii) demonstrate the ability to charge and discharge independent of any generation unit output.

(B) The Agency shall conduct a series of additional energy storage procurements that result in electric utilities contracting for energy storage resources in an amount of at least 3,000 megawatts of cumulative energy storage capacity for projects committed to reaching commercial operation on or before December 31, 2029, or an alternative date proposed by the Agency that is no later than December 31, 2030, subject to extension for a delay due to interconnection of the energy storage system, a delay in obtaining permits necessary to build or operate the energy storage system, or other circumstances at the discretion of the Agency and in an amount of at least 6,000 megawatts of cumulative energy storage capacity for projects committed to reaching commercial operation on or before December 31, 2034, subject to extension for a delay due to interconnection of the energy storage system, a delay in obtaining permits necessary to build or operate the energy storage system, or other circumstances at the discretion of the Agency.

The additional energy storage resources procurements shall be conducted in calendar years 2026, 2027, 2028, and 2029 in a manner that ensures the quantities listed in this subparagraph (B) are met in the specified timeframe. The procurements shall be conducted in a manner that maximizes projects available in the MISO and PJM queues, ensures the likelihood of project development through the development of project maturity requirements, enables sufficient competition for price competitiveness, and aligns to the extent practicable with regional transmission organization study phases. The procurements shall select projects interconnected to MISO Zone 4 and the PJM ComEd Area and shall follow either (i) a similar geographic split to the ratio of quantities established in subparagraph (A) of this paragraph (3), (ii) an alternative geographic split proposed by the Agency based on project availability in advanced stages of the MISO and PJM queues, or (iii) that is informed by MISO and PJM planning activities, auctions, or reports that indicate capacity resource shortages or impending shortages and that reflect the assessments made through the processes outlined in subparagraph (A) of paragraph (2). The additional energy storage capacity procurements may be adjusted upward if determined necessary through the planning process outlined in Section 16-201 of the Public Utilities Act at times determined by the Commission.

(C) The initial energy storage resources procurement under subparagraph (A) of this paragraph (3) shall adopt a standard indexed storage credit contract modeled after the contract and follow a process modeled after the process included in the staff report submitted to the Governor, General Assembly, and Commission pursuant to subsection (g) of Section 16-135 of the Public Utilities Act on May 1, 2025. In developing the procurement rules and procurement process for the initial procurement, the Agency shall provide an opportunity for comment on the indexed storage credit contract included in the May 1, 2025 staff report and shall adopt modifications to the contract consistent with the process outlined in paragraph (2) of subsection (e) of Section 16-111.5 of the Public Utilities Act.

(D) For the additional energy storage resources procurements conducted in accordance with subparagraph (B) of this paragraph (3), the Agency may, among other considerations, consider other contract structures if such contract structures and agreements do not create contractual obligations on utilities that are not contingent on full and timely cost recovery, avoid negative financial impacts on the utilities, and are agreed upon by the participating utility.

(E) The initial and additional energy storage resources procurements under this paragraph (3) shall solicit 20-year contracts.

(F) The Agency shall submit its proposed selection of successful bids for each procurement event pursuant to paragraphs (2) and (3) to the Commission for approval consistent with the processes outlined in Section 16-111.5 of the Public Utilities Act to the extent practicable.

(4) The energy storage system resources procurement plans developed by the Agency may consider alternatives to the initial and additional procurement terms described in paragraph (3) of this subsection (d-20), including, but not limited to:

(A) alternatives to the standard indexed storage credit contract used in the initial terms described in subparagraph (C) of paragraph (3) of this subsection (d-20);

(B) energy storage systems that are not stand-alone;

(C) proportionate allocations between MISO Zone 4 and the PJM ComEd Area that are not based upon load share, including allocations reflecting the assessments made through the processes outlined in subparagraph (A) of paragraph (2);

(D) contract lengths other than 20 years;

(E) energy storage system durations other than 4 hours; and

(F) energy storage systems connected to the distribution systems of the electric utilities.

The Agency may propose specific timelines for energy storage system resources procurements, which may differ across RTO zones, that are based in part upon a consideration of (i) the timing of the release of interconnection cost information through both MISO and PJM interconnection queue processes, (ii) factors that maximize the likelihood of successful project development, (iii) enabling sufficient competition for price competitiveness, and (iv) aligning to the extent practicable with RTO study phases.

(5) The Agency shall procure cost-effective energy storage credits or other contract instruments intended to facilitate the successful development of energy storage projects. The procurement administrator shall establish confidential price benchmarks based on publicly available data on regional technology costs. Confidential price benchmarks shall be developed by the procurement administrator, in consultation with Commission staff, Agency staff, and the procurement monitor, and shall be subject to Commission review and approval. Price benchmarks shall reflect development costs, financing costs, and related costs resulting from requirements imposed through other provisions of State law. As used in this paragraph (5), "cost-effective" means a bidder's bid price that does not exceed confidential price benchmarks.

(6) All procurements under this subsection (d-20) shall comply with the geographic requirements in subparagraph (I) of paragraph (1) of subsection (c) of Section 1-75 and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. The processes and procedures may be expedited to accommodate the schedule established by this Section. The Agency shall require all bidders to pay to the Agency a nonrefundable deposit determined by the Agency and no less than $10,000 per bid as practical. The Agency may also assess bidder and supplier fees to cover the cost of procurement events and develop collateral requirements to maximize the likelihood of successful project development. Bidders in the initial and additional procurements described in paragraph (3) of this subsection (d-20) shall also demonstrate experience in developing to commercial readiness. As used in this paragraph (6), "developing to commercial readiness" means having notice to proceed in owning or operating energy facilities with a combined nameplate capacity of at least 100 megawatts.

(7) In order to advance priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes, the Agency shall apply its equity accountability system and minimum equity standards established under subsections (c-10), (c-15), (c-20), (c-25), and (c-30) of this Section to energy storage procurement and programs and may include any proposed modifications to the equity accountability system and minimum equity standards that may be warranted with respect to energy storage resources in its plan submission to the Commission under Section 16-111.5 of the Public Utilities Act.

(8) Projects shall be developed in compliance with the prevailing wage and project labor agreement requirements for renewable energy projects in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75.

(9) An entity operating an energy storage facility shall demonstrate that it has entered into a labor peace agreement with a bona fide labor organization that is actively engaged in representing its employees. The labor peace agreement shall apply to the employees necessary for the ongoing maintenance and operation of the energy storage facility. The existence of a labor peace agreement shall be an ongoing material condition of an entity's authorization to maintain and operate the energy storage facility.

(10) In order to promote the competitive development of energy storage systems in furtherance of the State's interest in the health, safety, and welfare of its residents, storage credits shall not be eligible to be selected under this subsection (d-20) if the energy storage resources are sourced from an energy storage system whose costs were being recovered through rates regulated by the State or any other state or states on or after January 1, 2017. No entity shall be permitted to bid unless it certifies to the Agency that it is not an electric utility, as defined in Section 16-102 of the Public Utilities Act, serving more than 10,000 customers in the State.

(11) The Agency shall require, as a prerequisite to payment for any storage credits, that the winning bidder provide the Agency or its designee a copy of the interconnection agreement under which the applicable energy storage system is connected to the transmission or distribution system.

(12) Contracts shall provide that, if the cost recovery mechanism referenced in subsection (k) of Section 16-108 of the Public Utilities Act remains in full force without amendment or the utility is otherwise authorized or entitled to full, prompt, and uninterrupted recovery of its costs through any other mechanism, then such seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this paragraph (12).

(e) The draft procurement plans are subject to public comment, as required by Section 16-111.5 of the Public Utilities Act.

(f) The Agency shall submit the final procurement plan to the Commission. The Agency shall revise a procurement plan if the Commission determines that it does not meet the standards set forth in Section 16-111.5 of the Public Utilities Act.

(g) The Agency shall assess fees to each affected utility to recover the costs incurred in preparation of procurement plans and in the operation of programs the annual procurement plan for the utility.

(h) The Agency shall assess fees to each bidder to recover the costs incurred in connection with a competitive procurement process.

(i) A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit can only be used once to comply with a single portfolio or other standard as set forth in subsection (c), subsection (d), or subsection (d-5) of this Section, respectively. A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit cannot be used to satisfy the requirements of more than one standard. If more than one type of credit is issued for the same megawatt hour of energy, only one credit can be used to satisfy the requirements of a single standard. After such use, the credit must be retired together with any other credits issued for the same megawatt hour of energy.

(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24; 103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)

(20 ILCS 3855/1-125)

Sec. 1-125. Agency annual reports.

(a) By March February 15 of each year, the Agency shall report annually to the Governor and the General Assembly on the operations and transactions of the Agency. The annual report shall include, but not be limited to, each of the following:

(1) The average quantity, price, and term of all contracts for electricity procured under the procurement plans for electric utilities.

(2) (Blank).

(3) The quantity, price, and rate impact of all energy efficiency and demand response measures purchased for electric utilities, and any measures included in the procurement plan pursuant to Section 16-111.5B of the Public Utilities Act.

(4) The amount of power and energy produced by each Agency facility.

(5) The quantity of electricity supplied by each Agency facility to municipal electric systems, governmental aggregators, or rural electric cooperatives in Illinois.

(6) The revenues as allocated by the Agency to each facility.

(7) The costs as allocated by the Agency to each facility.

(8) The accumulated depreciation for each facility.

(9) The status of any projects under development.

(10) Basic financial and operating information specifically detailed for the reporting year and including, but not limited to, income and expense statements, balance sheets, and changes in financial position, all in accordance with generally accepted accounting principles, debt structure, and a summary of funds on a cash basis.

(11) The average quantity, price, contract type and term, and rate impact of all renewable resources procured under the long-term renewable resources procurement plans for electric utilities.

(12) A comparison of the costs associated with the Agency's procurement of renewable energy resources to (A) the Agency's costs associated with electricity generated by other types of generation facilities and (B) the benefits associated with the Agency's procurement of renewable energy resources.

(13) An analysis of the rate impacts associated with the Illinois Power Agency's procurement of renewable resources, including, but not limited to, any long-term contracts, on the eligible retail customers of electric utilities. The analysis shall include the Agency's estimate of the total dollar impact that the Agency's procurement of renewable resources has had on the annual electricity bills of the customer classes that comprise each eligible retail customer class taking service from an electric utility.

(14) (Blank).

(b) In addition to reporting on the transactions and operations of the Agency, the Agency shall also endeavor to report on the following items through its annual report, recognizing that full and accurate information may not be available for certain items:

(1) The overall nameplate capacity amount of installed and scheduled renewable energy generation capacity physically located in Illinois.

(2) The percentage of installed and scheduled renewable energy generation capacity as a share of overall electricity generation capacity physically located in Illinois.

(3) The amount of megawatt hours produced by renewable energy generation capacity physically located in Illinois for the preceding delivery year.

(4) The percentage of megawatt hours produced by renewable energy generation capacity physically located in Illinois as a share of overall electricity generation from facilities physically located in Illinois for the preceding delivery year and as a share of retail electricity sales in Illinois.

(5) The renewable portfolio standard expenditures made pursuant to paragraph (1) of subsection (c) of Section 1-75 and the total scheduled and installed renewable generation capacity expected to result from these investments. This information shall include the total cost of REC delivery contracts of the renewable portfolio standard by project category, including, but not limited to, renewable energy credits delivery contracts entered into pursuant to subparagraphs (C), (G), (K), and (R) of paragraph (1) of subsection (c) Section 1-75. The Agency shall also report on the total amount of customer load featuring renewable portfolio standard compliance obligations scheduled to be met by self-direct customers pursuant to subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75, as well as the minimum annual quantities of renewable energy credits scheduled to be retired by those customers and amount of installed renewable energy generating capacity used to meet the requirements of subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75.

The Agency may seek assistance from the Illinois Commerce Commission in developing its annual report and may also retain the services of its expert consulting firm used to develop its procurement plans as outlined in paragraph (1) of subsection (a) of Section 1-75. Confidential or commercially sensitive business information provided by retail customers, alternative retail electric suppliers, or other parties shall be kept confidential by the Agency consistent with Section 1-120, but may be publicly reported in aggregate form.

(Source: P.A. 102-662, eff. 9-15-21.)

Section 90-15. The Illinois Procurement Code is amended by changing Sections 1-10 and 30-20 as follows:

(30 ILCS 500/1-10)

Sec. 1-10. Application.

(a) This Code applies only to procurements for which bidders, offerors, potential contractors, or contractors were first solicited on or after July 1, 1998. This Code shall not be construed to affect or impair any contract, or any provision of a contract, entered into based on a solicitation prior to the implementation date of this Code as described in Article 99, including, but not limited to, any covenant entered into with respect to any revenue bonds or similar instruments. All procurements for which contracts are solicited between the effective date of Articles 50 and 99 and July 1, 1998 shall be substantially in accordance with this Code and its intent.

(b) This Code shall apply regardless of the source of the funds with which the contracts are paid, including federal assistance moneys. This Code shall not apply to:

(1) Contracts between the State and its political subdivisions or other governments, or between State governmental bodies, except as specifically provided in this Code.

(2) Grants, except for the filing requirements of Section 20-80.

(3) Purchase of care, except as provided in Section 5-30.6 of the Illinois Public Aid Code and this Section.

(4) Hiring of an individual as an employee and not as an independent contractor, whether pursuant to an employment code or policy or by contract directly with that individual.

(5) Collective bargaining contracts.

(6) Purchase of real estate, except that notice of this type of contract with a value of more than $25,000 must be published in the Procurement Bulletin within 10 calendar days after the deed is recorded in the county of jurisdiction. The notice shall identify the real estate purchased, the names of all parties to the contract, the value of the contract, and the effective date of the contract.

(7) Contracts necessary to prepare for anticipated litigation, enforcement actions, or investigations, provided that the chief legal counsel to the Governor shall give his or her prior approval when the procuring agency is one subject to the jurisdiction of the Governor, and provided that the chief legal counsel of any other procuring entity subject to this Code shall give his or her prior approval when the procuring entity is not one subject to the jurisdiction of the Governor.

(8) (Blank).

(9) Procurement expenditures by the Illinois Conservation Foundation when only private funds are used.

(10) (Blank).

(11) Public-private agreements entered into according to the procurement requirements of Section 20 of the Public-Private Partnerships for Transportation Act and design-build agreements entered into according to the procurement requirements of Section 25 of the Public-Private Partnerships for Transportation Act.

(12) (A) Contracts for legal, financial, and other professional and artistic services entered into by the Illinois Finance Authority in which the State of Illinois is not obligated. Such contracts shall be awarded through a competitive process authorized by the members of the Illinois Finance Authority and are subject to Sections 5-30, 20-160, 50-13, 50-20, 50-35, and 50-37 of this Code, as well as the final approval by the members of the Illinois Finance Authority of the terms of the contract.

(B) Contracts for legal and financial services entered into by the Illinois Housing Development Authority in connection with the issuance of bonds in which the State of Illinois is not obligated. Such contracts shall be awarded through a competitive process authorized by the members of the Illinois Housing Development Authority and are subject to Sections 5-30, 20-160, 50-13, 50-20, 50-35, and 50-37 of this Code, as well as the final approval by the members of the Illinois Housing Development Authority of the terms of the contract.

(13) Contracts for services, commodities, and equipment to support the delivery of timely forensic science services in consultation with and subject to the approval of the Chief Procurement Officer as provided in subsection (d) of Section 5-4-3a of the Unified Code of Corrections, except for the requirements of Sections 20-60, 20-65, 20-70, and 20-160 and Article 50 of this Code; however, the Chief Procurement Officer may, in writing with justification, waive any certification required under Article 50 of this Code. For any contracts for services which are currently provided by members of a collective bargaining agreement, the applicable terms of the collective bargaining agreement concerning subcontracting shall be followed.

On and after January 1, 2019, this paragraph (13), except for this sentence, is inoperative.

(14) Contracts for participation expenditures required by a domestic or international trade show or exhibition of an exhibitor, member, or sponsor.

(15) Contracts with a railroad or utility that requires the State to reimburse the railroad or utilities for the relocation of utilities for construction or other public purpose. Contracts included within this paragraph (15) shall include, but not be limited to, those associated with: relocations, crossings, installations, and maintenance. For the purposes of this paragraph (15), "railroad" means any form of non-highway ground transportation that runs on rails or electromagnetic guideways and "utility" means: (1) public utilities as defined in Section 3-105 of the Public Utilities Act, (2) telecommunications carriers as defined in Section 13-202 of the Public Utilities Act, (3) electric cooperatives as defined in Section 3.4 of the Electric Supplier Act, (4) telephone or telecommunications cooperatives as defined in Section 13-212 of the Public Utilities Act, (5) rural water or waste water systems with 10,000 connections or less, (6) a holder as defined in Section 21-201 of the Public Utilities Act, and (7) municipalities owning or operating utility systems consisting of public utilities as that term is defined in Section 11-117-2 of the Illinois Municipal Code.

(16) Procurement expenditures necessary for the Department of Public Health to provide the delivery of timely newborn screening services in accordance with the Newborn Metabolic Screening Act.

(17) Procurement expenditures necessary for the Department of Agriculture, the Department of Financial and Professional Regulation, the Department of Human Services, and the Department of Public Health to implement the Compassionate Use of Medical Cannabis Program and Opioid Alternative Pilot Program requirements and ensure access to medical cannabis for patients with debilitating medical conditions in accordance with the Compassionate Use of Medical Cannabis Program Act.

(18) This Code does not apply to any procurements necessary for the Department of Agriculture, the Department of Financial and Professional Regulation, the Department of Human Services, the Department of Commerce and Economic Opportunity, and the Department of Public Health to implement the Cannabis Regulation and Tax Act if the applicable agency has made a good faith determination that it is necessary and appropriate for the expenditure to fall within this exemption and if the process is conducted in a manner substantially in accordance with the requirements of Sections 20-160, 25-60, 30-22, 50-5, 50-10, 50-10.5, 50-12, 50-13, 50-15, 50-20, 50-21, 50-35, 50-36, 50-37, 50-38, and 50-50 of this Code; however, for Section 50-35, compliance applies only to contracts or subcontracts over $100,000. Notice of each contract entered into under this paragraph (18) that is related to the procurement of goods and services identified in paragraph (1) through (9) of this subsection shall be published in the Procurement Bulletin within 14 calendar days after contract execution. The Chief Procurement Officer shall prescribe the form and content of the notice. Each agency shall provide the Chief Procurement Officer, on a monthly basis, in the form and content prescribed by the Chief Procurement Officer, a report of contracts that are related to the procurement of goods and services identified in this subsection. At a minimum, this report shall include the name of the contractor, a description of the supply or service provided, the total amount of the contract, the term of the contract, and the exception to this Code utilized. A copy of any or all of these contracts shall be made available to the Chief Procurement Officer immediately upon request. The Chief Procurement Officer shall submit a report to the Governor and General Assembly no later than November 1 of each year that includes, at a minimum, an annual summary of the monthly information reported to the Chief Procurement Officer. This exemption becomes inoperative 5 years after June 25, 2019 (the effective date of Public Act 101-27).

(19) Acquisition of modifications or adjustments, limited to assistive technology devices and assistive technology services, adaptive equipment, repairs, and replacement parts to provide reasonable accommodations (i) that enable a qualified applicant with a disability to complete the job application process and be considered for the position such qualified applicant desires, (ii) that modify or adjust the work environment to enable a qualified current employee with a disability to perform the essential functions of the position held by that employee, (iii) to enable a qualified current employee with a disability to enjoy equal benefits and privileges of employment as are enjoyed by other similarly situated employees without disabilities, and (iv) that allow a customer, client, claimant, or member of the public seeking State services full use and enjoyment of and access to its programs, services, or benefits.

For purposes of this paragraph (19):

"Assistive technology devices" means any item, piece of equipment, or product system, whether acquired commercially off the shelf, modified, or customized, that is used to increase, maintain, or improve functional capabilities of individuals with disabilities.

"Assistive technology services" means any service that directly assists an individual with a disability in selection, acquisition, or use of an assistive technology device.

"Qualified" has the same meaning and use as provided under the federal Americans with Disabilities Act when describing an individual with a disability.

(20) Procurement expenditures necessary for the Illinois Commerce Commission to hire third-party facilitators pursuant to Sections 16-105.17 and 16-108.18 of the Public Utilities Act or an ombudsman pursuant to Section 16-107.5 of the Public Utilities Act, a facilitator pursuant to Section 16-105.17 of the Public Utilities Act, or a grid auditor pursuant to Section 16-105.10 of the Public Utilities Act, a facilitator, expert, or consultant pursuant to Sections 8-104A, 16-126.2, and 16-202 of the Public Utilities Act, a procurement monitor pursuant to Section 16-111.5 of the Public Utilities Act, an ombudsperson pursuant to Section 20-145 of the Public Utilities Act, or consultants and experts pursuant to Section 15 of the Utility Data Access Act.

(21) Procurement expenditures for the purchase, renewal, and expansion of software, software licenses, or software maintenance agreements that support the efforts of the Illinois State Police to enforce, regulate, and administer the Firearm Owners Identification Card Act, the Firearm Concealed Carry Act, the Firearms Restraining Order Act, the Firearm Dealer License Certification Act, the Law Enforcement Agencies Data System (LEADS), the Uniform Crime Reporting Act, the Criminal Identification Act, the Illinois Uniform Conviction Information Act, and the Gun Trafficking Information Act, or establish or maintain record management systems necessary to conduct human trafficking investigations or gun trafficking or other stolen firearm investigations. This paragraph (21) applies to contracts entered into on or after January 10, 2023 (the effective date of Public Act 102-1116) and the renewal of contracts that are in effect on January 10, 2023 (the effective date of Public Act 102-1116).

(22) Contracts for project management services and system integration services required for the completion of the State's enterprise resource planning project. This exemption becomes inoperative 5 years after June 7, 2023 (the effective date of the changes made to this Section by Public Act 103-8). This paragraph (22) applies to contracts entered into on or after June 7, 2023 (the effective date of the changes made to this Section by Public Act 103-8) and the renewal of contracts that are in effect on June 7, 2023 (the effective date of the changes made to this Section by Public Act 103-8).

(23) Procurements necessary for the Department of Insurance to implement the Illinois Health Benefits Exchange Law if the Department of Insurance has made a good faith determination that it is necessary and appropriate for the expenditure to fall within this exemption. The procurement process shall be conducted in a manner substantially in accordance with the requirements of Sections 20-160 and 25-60 and Article 50 of this Code. A copy of these contracts shall be made available to the Chief Procurement Officer immediately upon request. This paragraph is inoperative 5 years after June 27, 2023 (the effective date of Public Act 103-103).

(24) Contracts for public education programming, noncommercial sustaining announcements, public service announcements, and public awareness and education messaging with the nonprofit trade associations of the providers of those services that inform the public on immediate and ongoing health and safety risks and hazards.

(25) Procurements necessary for the Department of Early Childhood to implement the Department of Early Childhood Act if the Department has made a good faith determination that it is necessary and appropriate for the expenditure to fall within this exemption. This exemption shall only be used for products and services procured solely for use by the Department of Early Childhood. The procurements may include those necessary to design and build integrated, operational systems of programs and services. The procurements may include, but are not limited to, those necessary to align and update program standards, integrate funding systems, design and establish data and reporting systems, align and update models for technical assistance and professional development, design systems to manage grants and ensure compliance, design and implement management and operational structures, and establish new means of engaging with families, educators, providers, and stakeholders. The procurement processes shall be conducted in a manner substantially in accordance with the requirements of Article 50 (ethics) and Sections 5-5 (Procurement Policy Board), 5-7 (Commission on Equity and Inclusion), 20-80 (contract files), 20-120 (subcontractors), 20-155 (paperwork), 20-160 (ethics/campaign contribution prohibitions), 25-60 (prevailing wage), and 25-90 (prohibited and authorized cybersecurity) of this Code. Beginning January 1, 2025, the Department of Early Childhood shall provide a quarterly report to the General Assembly detailing a list of expenditures and contracts for which the Department uses this exemption. This paragraph is inoperative on and after July 1, 2027.

(26) (25) Procurements that are necessary for increasing the recruitment and retention of State employees, particularly minority candidates for employment, including:

(A) procurements related to registration fees for job fairs and other outreach and recruitment events;

(B) production of recruitment materials; and

(C) other services related to recruitment and retention of State employees.

The exemption under this paragraph (26) (25) applies only if the State agency has made a good faith determination that it is necessary and appropriate for the expenditure to fall within this paragraph (26) (25). The procurement process under this paragraph (26) (25) shall be conducted in a manner substantially in accordance with the requirements of Sections 20-160 and 25-60 and Article 50 of this Code. A copy of these contracts shall be made available to the Chief Procurement Officer immediately upon request. Nothing in this paragraph (26) (25) authorizes the replacement or diminishment of State responsibilities in hiring or the positions that effectuate that hiring. This paragraph (26) (25) is inoperative on and after June 30, 2029.

Notwithstanding any other provision of law, for contracts with an annual value of more than $100,000 entered into on or after October 1, 2017 under an exemption provided in any paragraph of this subsection (b), except paragraph (1), (2), or (5), each State agency shall post to the appropriate procurement bulletin the name of the contractor, a description of the supply or service provided, the total amount of the contract, the term of the contract, and the exception to the Code utilized. The chief procurement officer shall submit a report to the Governor and General Assembly no later than November 1 of each year that shall include, at a minimum, an annual summary of the monthly information reported to the chief procurement officer.

(c) This Code does not apply to the electric power procurement process provided for under Section 1-75 of the Illinois Power Agency Act and Section 16-111.5 of the Public Utilities Act. This Code does not apply to the procurement of technical and policy experts pursuant to Section 1-129 of the Illinois Power Agency Act.

(d) Except for Section 20-160 and Article 50 of this Code, and as expressly required by Section 9.1 of the Illinois Lottery Law, the provisions of this Code do not apply to the procurement process provided for under Section 9.1 of the Illinois Lottery Law.

(e) This Code does not apply to the process used by the Capital Development Board to retain a person or entity to assist the Capital Development Board with its duties related to the determination of costs of a clean coal SNG brownfield facility, as defined by Section 1-10 of the Illinois Power Agency Act, as required in subsection (h-3) of Section 9-220 of the Public Utilities Act, including calculating the range of capital costs, the range of operating and maintenance costs, or the sequestration costs or monitoring the construction of clean coal SNG brownfield facility for the full duration of construction.

(f) (Blank).

(g) (Blank).

(h) This Code does not apply to the process to procure or contracts entered into in accordance with Sections 11-5.2 and 11-5.3 of the Illinois Public Aid Code.

(i) Each chief procurement officer may access records necessary to review whether a contract, purchase, or other expenditure is or is not subject to the provisions of this Code, unless such records would be subject to attorney-client privilege.

(j) This Code does not apply to the process used by the Capital Development Board to retain an artist or work or works of art as required in Section 14 of the Capital Development Board Act.

(k) This Code does not apply to the process to procure contracts, or contracts entered into, by the State Board of Elections or the State Electoral Board for hearing officers appointed pursuant to the Election Code.

(l) This Code does not apply to the processes used by the Illinois Student Assistance Commission to procure supplies and services paid for from the private funds of the Illinois Prepaid Tuition Fund. As used in this subsection (l), "private funds" means funds derived from deposits paid into the Illinois Prepaid Tuition Trust Fund and the earnings thereon.

(m) This Code shall apply regardless of the source of funds with which contracts are paid, including federal assistance moneys. Except as specifically provided in this Code, this Code shall not apply to procurement expenditures necessary for the Department of Public Health to conduct the Healthy Illinois Survey in accordance with Section 2310-431 of the Department of Public Health Powers and Duties Law of the Civil Administrative Code of Illinois.

(Source: P.A. 102-175, eff. 7-29-21; 102-483, eff 1-1-22; 102-558, eff. 8-20-21; 102-600, eff. 8-27-21; 102-662, eff. 9-15-21; 102-721, eff. 1-1-23; 102-813, eff. 5-13-22; 102-1116, eff. 1-10-23; 103-8, eff. 6-7-23; 103-103, eff. 6-27-23; 103-570, eff. 1-1-24; 103-580, eff. 12-8-23; 103-594, eff. 6-25-24; 103-605, eff. 7-1-24; 103-865, eff. 1-1-25; revised 11-26-24.)

(30 ILCS 500/30-20)

Sec. 30-20. Prequalification.

(a) The Capital Development Board shall promulgate rules for the development of prequalified supplier lists for construction and construction-related professional services and the periodic updating of those lists. Construction and construction-related professional services contracts over $25,000 may be awarded to any qualified suppliers.

(b) If deemed necessary by the Agency, the The Illinois Power Agency shall promulgate rules for the development of prequalified supplier lists for construction and construction-related professional services and the periodic updating of those lists. Construction and construction-related construction related professional services contracts over $25,000 may be awarded to any qualified suppliers, pursuant to a competitive bidding process.

(Source: P.A. 95-481, eff. 8-28-07.)

Section 90-17. The Illinois Works Jobs Program Act is amended by changing Section 20-15 as follows:

(30 ILCS 559/20-15)

Sec. 20-15. Illinois Works Preapprenticeship Program; Illinois Works Bid Credit Program.

(a) The Illinois Works Preapprenticeship Program is established and shall be administered by the Department. The goal of the Illinois Works Preapprenticeship Program is to create a network of community-based organizations throughout the State that will recruit, prescreen, and provide preapprenticeship skills training, for which participants may attend free of charge and receive a stipend, to create a qualified, diverse pipeline of workers who are prepared for careers in the construction and building trades. Upon completion of the Illinois Works Preapprenticeship Program, the candidates will be skilled and work-ready.

(b) There is created the Illinois Works Fund, a special fund in the State treasury. The Illinois Works Fund shall be administered by the Department. The Illinois Works Fund shall be used to provide funding for community-based organizations throughout the State. In addition to any other transfers that may be provided for by law, on and after July 1, 2019 at the direction of the Director of the Governor's Office of Management and Budget, the State Comptroller shall direct and the State Treasurer shall transfer amounts not exceeding a total of $50,000,000 from the Rebuild Illinois Projects Fund to the Illinois Works Fund.

(b-5) In addition to any other transfers that may be provided for by law, beginning July 1, 2024 and each July 1 thereafter, or as soon thereafter as practical, the State Comptroller shall direct and the State Treasurer shall transfer $27,500,000 from the Capital Projects Fund to the Illinois Works Fund.

(c) Each community-based organization that receives funding from the Illinois Works Fund shall provide an annual report to the Illinois Works Review Panel by April 1 of each calendar year. The annual report shall include the following information:

(1) a description of the community-based organization's recruitment, screening, and training efforts;

(2) the number of individuals who apply to, participate in, and complete the community-based organization's program, broken down by race, gender, age, and veteran status; and

(3) the number of the individuals referenced in item (2) of this subsection who are initially accepted and placed into apprenticeship programs in the construction and building trades.

(d) The Department shall create and administer the Illinois Works Bid Credit Program that shall provide economic incentives, through bid credits, to encourage contractors and subcontractors to provide contracting and employment opportunities to historically underrepresented populations in the construction industry.

The Illinois Works Bid Credit Program shall allow contractors and subcontractors to earn bid credits for use toward future bids for public works projects contracted by the State or an agency of the State in order to increase the chances that the contractor and the subcontractors will be selected.

Contractors or subcontractors may be eligible to earn bid credits for employing apprentices who have been verified by the Department to have completed the Illinois Works Preapprenticeship Program, the Climate Works Preapprenticeship Program, or the Highway Construction Careers Training Program. Contractors or subcontractors shall earn bid credits at a rate established by the Department and based on labor hours worked by apprentices who have been verified by the Department to have completed the Illinois Works Preapprenticeship Program, the Climate Works Preapprenticeship Program, or the Highway Construction Careers Training Program. In order to earn bid credits, contractors and subcontractors shall provide the Department with certified payroll documenting the hours performed by apprentices who have been verified by the Department to have completed the Illinois Works Preapprenticeship Program, the Climate Works Preapprenticeship Program, or the Highway Construction Careers Training Program. Contractors and subcontractors can use bid credits toward future bids for public works projects contracted or funded by the State or an agency of the State in order to increase the likelihood of being selected as the contractor for the public works project toward which they have applied the bid credit. The Department shall establish the rate by rule and shall publish it on the Department's website. The rule may include maximum bid credits allowed per contractor, per subcontractor, per apprentice, per bid, or per year.

The Illinois Works Credit Bank is hereby created and shall be administered by the Department. The Illinois Works Credit Bank shall track the bid credits.

A contractor or subcontractor who has been awarded bid credits under any other State program for employing apprentices who have completed the Illinois Works Preapprenticeship Program is not eligible to receive bid credits under the Illinois Works Bid Credit Program relating to the same contract.

The Department shall report to the Illinois Works Review Panel the following: (i) the number of bid credits awarded by the Department; (ii) the number of bid credits submitted by the contractor or subcontractor to the agency administering the public works contract; and (iii) the number of bid credits accepted by the agency for such contract. Any agency that awards bid credits pursuant to the Illinois Works Credit Bank Program shall report to the Department the number of bid credits it accepted for the public works contract.

Upon a finding that a contractor or subcontractor has reported falsified records to the Department in order to fraudulently obtain bid credits, the Department may bar the contractor or subcontractor from participating in the Illinois Works Bid Credit Program and may suspend the contractor or subcontractor from bidding on or participating in any public works project. False or fraudulent claims for payment relating to false bid credits may be subject to damages and penalties under applicable law.

(e) The Department shall adopt any rules deemed necessary to implement this Section. In order to provide for the expeditious and timely implementation of this Act, the Department may adopt emergency rules. The adoption of emergency rules authorized by this subsection is deemed to be necessary for the public interest, safety, and welfare.

(Source: P.A. 103-8, eff. 6-7-23; 103-305, eff. 7-28-23; 103-588, eff. 6-5-24; 103-605, eff. 7-1-24; 104-2, eff. 6-16-25.)

Section 90-20. The Property Tax Code is amended by adding Division 22 as follows:

(35 ILCS 200/Art. 10 Div. 22 heading new)

Division 22. Commercial energy storage systems

(35 ILCS 200/10-920 new)

Sec. 10-920. Definitions. As used in this Division:

"Allowance for physical depreciation" means the product of the quotient that is generated by dividing the actual age in years of the commercial energy storage system on the assessment date by 25 years multiplied by the commercial energy storage system's trended real property cost basis. "Allowance for physical depreciation" may not exceed an amount that reduces the value of the commercial energy storage system to 30% of its trended real property cost basis or less.

"Commercial energy storage system" means any device or assembly of devices that is (i) either installed as a stand-alone system or tied to a power generation system, (ii) used for the primary purpose of storing of energy for wholesale or retail sale and not primarily for storage to later consume on the property on which the device resides, and (iii) an energy storage system, as defined in Section 16-135 of the Public Utilities Act.

"Commercial energy storage system real property cost basis" means the owner of the commercial energy storage system's interest in the land within the project boundaries and real property improvements and shall be calculated at $65 per kilowatt-hour of rated kilowatt-hour energy capacity.

"Consumer Price Index" means the index published by the Bureau of Labor Statistics of the United States Department of Labor that measures the average change in prices of goods and services purchased by all urban consumers, United States city average, all items, 1982-84 = 100.

"Rated kWh energy capacity" means the maximum amount of stored energy in kilowatt hours. "Trended real property cost basis" means the commercial energy storage system real property cost basis multiplied by the trending factor.

"Trending factor" means the following:

(1) for stand-alone commercial energy storage systems, the lesser of 2% or the number generated by dividing the Consumer Price Index published by the Bureau of Labor Statistics in the December immediately preceding the assessment date by the Consumer Price Index published by the Bureau of Labor Statistics in December of 2024; or

(2) for commercial energy storage systems tied to a power generation system, a trending factor of 1.00.

(35 ILCS 200/10-925 new)

Sec. 10-925. Improvement valuation of commercial energy systems. Beginning in assessment year 2026, the fair cash value of commercial energy storage system improvements shall be determined by subtracting the allowance for physical depreciation from the commercial energy storage system trended real property cost basis. Functional obsolescence and external obsolescence of the commercial energy storage system improvements may further reduce the fair cash value of the improvements to the extent the obsolescence is proven by the taxpayer by clear and convincing evidence, except that the combined depreciation from all functional and economic obsolescence shall not exceed 70% of the trended real property cost basis. The chief county assessment officer may make reasonable adjustments to the actual age of the commercial energy storage system to account for the routine replacement or upgrade of system components.

(35 ILCS 200/10-930 new)

Sec. 10-930. Commercial energy storage systems; equalization. Commercial energy storage systems that are subject to assessment under this Division are not subject to equalization factors applied by the Department, any board of review, an assessor, or a chief county assessment officer.

(35 ILCS 200/10-935 new)

Sec. 10-935. Survey for commercial energy storage systems; parcel identification numbers. Notwithstanding any other provision of law, the owner of the commercial energy storage system shall commission a metes and bounds survey description of the land upon which the commercial energy storage system is located, including access routes, over which the owner of the commercial energy storage system has exclusive control. Land held for future development shall not be included in the project area for real property assessment purposes. The owner of the commercial energy storage system shall, at the owner's own expense, use a State-registered land surveyor to prepare the survey. The owner of the commercial energy storage system shall deliver a copy of the survey to the chief county assessment officer and to the owner of the land upon which the commercial energy storage system is located. Upon receiving a copy of the survey and an agreed acknowledgment to the separate parcel identification number by the owner of the land upon which the commercial energy storage system is constructed, the chief county assessment officer shall issue a separate parcel identification number for the real property improvements, including the land containing the commercial energy storage system, to be used only for the purposes of property assessment for taxation. If no survey is provided, the chief county assessment officer shall determine the area of the site that is occupied by the commercial energy storage system. The chief county assessment officer's determination shall be final and may not be challenged on review by the owner of the commercial energy storage system. The property records shall contain the legal description of the commercial energy storage system parcel and describe any leasehold interest or other interest of the owner of the commercial energy storage system in the property. A plat prepared under this Section shall not be construed as a violation of the Plat Act.

Surveys that are prepared in accordance with either Section 10-740 or Section 10-620 and that also include the location of a commercial energy storage system in the survey's metes and bounds description shall satisfy the requirements of this Section.

(35 ILCS 200/10-940 new)

Sec. 10-940. Real estate taxes. Notwithstanding the provisions of Section 9-175 of this Code, the owner of the commercial energy storage system shall be liable for the real estate taxes for the land and real property improvements of the commercial energy storage system. Notwithstanding the foregoing, the owner of the land upon which a commercial energy storage system is located may pay any unpaid tax of the commercial energy storage system parcel prior to the initiation of any tax sale proceedings.

(35 ILCS 200/10-945 new)

Sec. 10-945. Property assessed as farmland. Notwithstanding any other provision of law, real property assessed as farmland in accordance with Section 10-110 in the assessment year prior to valuation under this Division shall return to being assessed as farmland in accordance with Section 10-110 in the year following completion of the removal of the commercial energy storage system if the property is returned to a farm use, as defined in Section 1-60, notwithstanding that the land was not used for farming for the 2 preceding years.

(35 ILCS 200/10-950 new)

Sec. 10-950. Abatements. Any taxing district may, upon a majority vote of its governing authority and after the determination of the assessed valuation as set forth in this Code, order the clerk of the appropriate municipality or county to abate any portion of real property taxes otherwise levied or extended by the taxing district on a commercial energy storage system.

(35 ILCS 200/10-953 new)

Sec. 10-953. Cook County exemption. This Division 22 does not apply to any property located within Cook County.

(35 ILCS 200/10-955 new)

Sec. 10-955. Applicability. The provisions of this Division apply for assessment years 2026 through 2040.

Section 90-26. The Counties Code is amended by adding Division 5-46 and Section 5-12024 and changing Section 5-12020 as follows:

(55 ILCS 5/5-12020)

Sec. 5-12020. Commercial wind energy facilities and commercial solar energy facilities.

(a) As used in this Section:

"Commercial solar energy facility" means a "commercial solar energy system" as defined in Section 10-720 of the Property Tax Code. "Commercial solar energy facility" does not mean a utility-scale solar energy facility being constructed at a site that was eligible to participate in a procurement event conducted by the Illinois Power Agency pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act.

"Commercial wind energy facility" means a wind energy conversion facility of equal or greater than 500 kilowatts in total nameplate generating capacity. "Commercial wind energy facility" includes a wind energy conversion facility seeking an extension of a permit to construct granted by a county or municipality before January 27, 2023 (the effective date of Public Act 102-1123).

"Facility owner" means (i) a person with a direct ownership interest in a commercial wind energy facility or a commercial solar energy facility, or both, regardless of whether the person is involved in acquiring the necessary rights, permits, and approvals or otherwise planning for the construction and operation of the facility, and (ii) at the time the facility is being developed, a person who is acting as a developer of the facility by acquiring the necessary rights, permits, and approvals or by planning for the construction and operation of the facility, regardless of whether the person will own or operate the facility.

"Nonparticipating property" means real property that is not a participating property.

"Nonparticipating residence" means a residence that is located on nonparticipating property and that is existing and occupied on the date that an application for a permit to develop the commercial wind energy facility or the commercial solar energy facility is filed with the county.

"Occupied community building" means any one or more of the following buildings that is existing and occupied on the date that the application for a permit to develop the commercial wind energy facility or the commercial solar energy facility is filed with the county: a school, place of worship, day care facility, public library, or community center.

"Participating property" means real property that is the subject of a written agreement between a facility owner and the owner of the real property that provides the facility owner an easement, option, lease, or license to use the real property for the purpose of constructing a commercial wind energy facility, a commercial solar energy facility, or supporting facilities. "Participating property" also includes real property that is owned by a facility owner for the purpose of constructing a commercial wind energy facility, a commercial solar energy facility, or supporting facilities.

"Participating residence" means a residence that is located on participating property and that is existing and occupied on the date that an application for a permit to develop the commercial wind energy facility or the commercial solar energy facility is filed with the county.

"Protected lands" means real property that is:

(1) subject to a permanent conservation right consistent with the Real Property Conservation Rights Act; or

(2) registered or designated as a nature preserve, buffer, or land and water reserve under the Illinois Natural Areas Preservation Act.

"Supporting facilities" means the transmission lines, substations, access roads, meteorological towers, storage containers, and equipment associated with the generation and storage of electricity by the commercial wind energy facility or commercial solar energy facility. "Supporting facilities" includes energy storage systems capable of absorbing energy and storing it for use at a later time, including, but not limited to, batteries and other electrochemical and electromechanical technologies or systems.

"Wind tower" includes the wind turbine tower, nacelle, and blades.

(b) Notwithstanding any other provision of law or whether the county has formed a zoning commission and adopted formal zoning under Section 5-12007, a county may establish standards for commercial wind energy facilities, commercial solar energy facilities, or both. The standards may include all of the requirements specified in this Section but may not include requirements for commercial wind energy facilities or commercial solar energy facilities that are more restrictive than specified in this Section. A county may also regulate the siting of commercial wind energy facilities with standards that are not more restrictive than the requirements specified in this Section in unincorporated areas of the county that are outside the zoning jurisdiction of a municipality and that are outside the 1.5-mile radius surrounding the zoning jurisdiction of a municipality. A county may also regulate the siting of commercial solar energy facilities with standards that are not more restrictive than the requirements specified in this Section in unincorporated areas of the county that are outside of the zoning jurisdiction of a municipality.

(c) If a county has elected to establish standards under subsection (b), before the county grants siting approval or a special use permit for a commercial wind energy facility or a commercial solar energy facility, or modification of an approved siting or special use permit, the county board of the county in which the facility is to be sited or the zoning board of appeals for the county shall hold at least one public hearing. The public hearing shall be conducted in accordance with the Open Meetings Act and shall conclude be held not more than 60 days after the filing of the application for the facility. The county shall allow interested parties to a special use permit an opportunity to present evidence and to cross-examine witnesses at the hearing, but the county may impose reasonable restrictions on the public hearing, including reasonable time limitations on the presentation of evidence and the cross-examination of witnesses. The county shall also allow public comment at the public hearing in accordance with the Open Meetings Act. The county shall make its siting and permitting decisions not more than 30 days after the conclusion of the public hearing. Notice of the hearing shall be published in a newspaper of general circulation in the county. A facility owner must enter into an agricultural impact mitigation agreement with the Department of Agriculture prior to the date of the required public hearing. A commercial wind energy facility owner seeking an extension of a permit granted by a county prior to July 24, 2015 (the effective date of Public Act 99-132) must enter into an agricultural impact mitigation agreement with the Department of Agriculture prior to a decision by the county to grant the permit extension. Counties may allow test wind towers or test solar energy systems to be sited without formal approval by the county board.

(d) A county with an existing zoning ordinance in conflict with this Section shall amend that zoning ordinance to be in compliance with this Section within 120 days after January 27, 2023 (the effective date of Public Act 102-1123).

(e) A county may require:

(1) a wind tower of a commercial wind energy facility to be sited as follows, with setback distances measured from the center of the base of the wind tower:

Setback Description Setback Distance

Occupied Community 2.1 times the maximum blade tip Buildings height of the wind tower to the nearest point on the outside wall of the structure

Participating Residences 1.1 times the maximum blade tip height of the wind tower to the nearest point on the outside wall of the structure

Nonparticipating Residences 2.1 times the maximum blade tip height of the wind tower to the nearest point on the outside wall of the structure

Boundary Lines of None Participating Property

Boundary Lines of 1.1 times the maximum blade tip Nonparticipating Property height of the wind tower to the nearest point on the property line of the nonparticipating property

Public Road Rights-of-Way 1.1 times the maximum blade tip height of the wind tower to the center point of the public road right-of-way

Overhead Communication and 1.1 times the maximum blade tip Electric Transmission height of the wind tower to the and Distribution Facilities nearest edge of the property (Not Including Overhead line, easement, or Utility Service Lines to right-of-way Individual Houses or containing the overhead line Outbuildings)

Overhead Utility Service None Lines to Individual Houses or Outbuildings

Fish and Wildlife Areas 2.1 times the maximum blade and Illinois Nature tip height of the wind tower Preserve Commission to the nearest point on the Protected Lands property line of the fish and wildlife area or protected land

This Section does not exempt or excuse compliance with electric facility clearances approved or required by the National Electrical Code, the The National Electrical Safety Code, the Illinois Commerce Commission, and the Federal Energy Regulatory Commission, and their designees or successors; .

(2) a wind tower of a commercial wind energy facility to be sited so that industry standard computer modeling indicates that any occupied community building or nonparticipating residence will not experience more than 30 hours per year of shadow flicker under planned operating conditions;

(3) a commercial solar energy facility to be sited as follows, with setback distances measured from the nearest edge of any above-ground component of the facility, excluding fencing:

Setback Description Setback Distance

Occupied Community 150 feet from the nearest Buildings and Dwellings on point on the outside wall Nonparticipating Properties of the structure

Boundary Lines of None Participating Property

Public Road Rights-of-Way 50 feet from the nearest edge of the public

right-of-way

Boundary Lines of 50 feet to the nearest Nonparticipating Property point on the property line of the nonparticipating property

(4) a commercial solar energy facility to be sited so that the facility's perimeter is enclosed by fencing having a height of at least 6 feet and no more than 25 feet; and

(5) a commercial solar energy facility to be sited so that no component of a solar panel has a height of more than 20 feet above ground when the solar energy facility's arrays are at full tilt.

The requirements set forth in this subsection (e) may be waived subject to the written consent of the owner of each affected nonparticipating property.

(f) A county may not set a sound limitation for wind towers in commercial wind energy facilities or any components in commercial solar energy facilities that is more restrictive than the sound limitations established by the Illinois Pollution Control Board under 35 Ill. Adm. Code Parts 900, 901, and 910.

(g) A county may not place any restriction on the installation or use of a commercial wind energy facility or a commercial solar energy facility unless it adopts an ordinance that complies with this Section. A county may not establish siting standards for supporting facilities that preclude development of commercial wind energy facilities or commercial solar energy facilities.

A request for siting approval or a special use permit for a commercial wind energy facility or a commercial solar energy facility, or modification of an approved siting or special use permit, shall be approved if the request is in compliance with the standards and conditions imposed in this Act, the zoning ordinance adopted consistent with this Act Code, and the conditions imposed under State and federal statutes and regulations.

(h) A county may not adopt zoning regulations that disallow, permanently or temporarily, commercial wind energy facilities or commercial solar energy facilities from being developed or operated in any district zoned to allow agricultural or industrial uses.

(i) (Blank). A county may not require permit application fees for a commercial wind energy facility or commercial solar energy facility that are unreasonable. All application fees imposed by the county shall be consistent with fees for projects in the county with similar capital value and cost.

(i-5) All siting approval or special use permit application fees for a commercial wind energy facility or commercial solar energy facility shall not exceed $5,000 per each megawatt of nameplate capacity of the energy facility, and the maximum fee is $125,000. A county may also require reimbursement from the applicant for any reasonable expenses incurred by the county in processing the siting approval or special use permit application in excess of the maximum fee. A siting approval or special use permit shall not be subject to any time deadline to start construction or obtain a building permit of less than 5 years from the date of siting approval or special use permit approval. A county shall allow an applicant to request an extension of the deadline based upon reasonable cause for the extension request. The exemption shall not be unreasonably withheld, conditioned, or denied.

(i-10) A county may require, for a commercial wind energy facility or commercial solar energy facility, a single building permit and permit fee for the facility which includes all supporting facilities. A county building permit fee for a commercial wind energy facility or commercial solar energy facility shall not exceed $5,000 per each megawatt of nameplate capacity of the energy facility, and the maximum fee is $75,000. A county may also require reimbursement from the applicant for any reasonable expenses incurred by the county in processing the building permit in excess of the maximum fee. A county may require an applicant, upon start of construction of the facility, to maintain liability insurance that is commercially reasonable and consistent with prevailing industry standards for similar energy facilities.

(j) Except as otherwise provided in this Section, a county shall not require standards for construction, decommissioning, or deconstruction of a commercial wind energy facility or commercial solar energy facility or related financial assurances that are more restrictive than those included in the Department of Agriculture's standard wind farm agricultural impact mitigation agreement, template 81818, or standard solar agricultural impact mitigation agreement, version 8.19.19, as applicable and in effect on December 31, 2022. The amount of any decommissioning payment shall be in accordance with the financial assurance required by those agricultural impact mitigation agreements.

(j-5) A commercial wind energy facility or a commercial solar energy facility shall file a farmland drainage plan with the county and impacted drainage districts outlining how surface and subsurface drainage of farmland will be restored during and following construction or deconstruction of the facility. The plan is to be created independently by the facility developer and shall include the location of any potentially impacted drainage district facilities to the extent this information is publicly available from the county or the drainage district, plans to repair any subsurface drainage affected during construction or deconstruction using procedures outlined in the agricultural impact mitigation agreement entered into by the commercial wind energy facility owner or commercial solar energy facility owner, and procedures for the repair and restoration of surface drainage affected during construction or deconstruction. All surface and subsurface damage shall be repaired as soon as reasonably practicable.

(k) A county may not condition approval of a commercial wind energy facility or commercial solar energy facility on a property value guarantee and may not require a facility owner to pay into a neighboring property devaluation escrow account.

(l) A county may require certain vegetative screening between a surrounding a commercial wind energy facility or commercial solar energy facility and nonparticipating residences. A county but may not require earthen berms or similar structures. Vegetative screening requirements shall be commercially reasonable and limited in height at full maturity to avoid reduction of the productive energy output of the commercial solar energy facility. A county may not require vegetative screening to exceed 5 feet in height when first installed or prior to commercial operation date. The screening requirements shall take into account the size and location of the facility, visibility from nonparticipating residences, compatibility of native plant species, cost and feasibility of installation and maintenance, and industry standards and best practices for commercial solar energy facilities.

(m) A county may set blade tip height limitations for wind towers in commercial wind energy facilities but may not set a blade tip height limitation that is more restrictive than the height allowed under a Determination of No Hazard to Air Navigation by the Federal Aviation Administration under 14 CFR Part 77.

(n) A county may require that a commercial wind energy facility owner or commercial solar energy facility owner provide:

(1) the results and recommendations from consultation with the Illinois Department of Natural Resources that are obtained through the Ecological Compliance Assessment Tool (EcoCAT) or a comparable successor tool; and

(2) the results of the United States Fish and Wildlife Service's Information for Planning and Consulting environmental review or a comparable successor tool that is consistent with (i) the "U.S. Fish and Wildlife Service's Land-Based Wind Energy Guidelines" and (ii) any applicable United States Fish and Wildlife Service solar wildlife guidelines that have been subject to public review.

(o) A county may require a commercial wind energy facility or commercial solar energy facility to adhere to the recommendations provided by the Illinois Department of Natural Resources in an EcoCAT natural resource review report under 17 Ill. Adm. Code Part 1075.

(p) A county may require a facility owner to:

(1) demonstrate avoidance of protected lands as identified by the Illinois Department of Natural Resources and the Illinois Nature Preserve Commission; or

(2) consider the recommendations of the Illinois Department of Natural Resources for setbacks from protected lands, including areas identified by the Illinois Nature Preserve Commission.

(q) A county may require that a facility owner provide evidence of consultation with the Illinois State Historic Preservation Office to assess potential impacts on State-registered historic sites under the Illinois State Agency Historic Resources Preservation Act.

(r) To maximize community benefits, including, but not limited to, reduced stormwater runoff, flooding, and erosion at the ground mounted solar energy system, improved soil health, and increased foraging habitat for game birds, songbirds, and pollinators, a county may (1) require a commercial solar energy facility owner to plant, establish, and maintain for the life of the facility vegetative ground cover, consistent with the goals of the Pollinator-Friendly Solar Site Act and (2) require the submittal of a vegetation management plan that is in compliance with the agricultural impact mitigation agreement in the application to construct and operate a commercial solar energy facility in the county if the vegetative ground cover and vegetation management plan comply with the requirements of the underlying agreement with the landowner or landowners where the facility will be constructed.

No later than 90 days after January 27, 2023 (the effective date of Public Act 102-1123), the Illinois Department of Natural Resources shall develop guidelines for vegetation management plans that may be required under this subsection for commercial solar energy facilities. The guidelines must include guidance for short-term and long-term property management practices that provide and maintain native and non-invasive naturalized perennial vegetation to protect the health and well-being of pollinators.

(s) If a facility owner enters into a road use agreement with the Illinois Department of Transportation, a road district, or other unit of local government relating to a commercial wind energy facility or a commercial solar energy facility, the road use agreement shall require the facility owner to be responsible for (i) the reasonable cost of improving roads used by the facility owner to construct the commercial wind energy facility or the commercial solar energy facility and (ii) the reasonable cost of repairing roads used by the facility owner during construction of the commercial wind energy facility or the commercial solar energy facility so that those roads are in a condition that is safe for the driving public after the completion of the facility's construction. Roadways improved in preparation for and during the construction of the commercial wind energy facility or commercial solar energy facility shall be repaired and restored to the improved condition at the reasonable cost of the developer if the roadways have degraded or were damaged as a result of construction-related activities.

The road use agreement shall not require the facility owner to pay costs, fees, or charges for road work that is not specifically and uniquely attributable to the construction of the commercial wind energy facility or the commercial solar energy facility. No road district or other unit of local government may request or require permit fees, fines, or other payment obligations as a requirement for a road use agreement with a facility owner unless the amount of the permit fee or payment is equivalent to the amount of actual expenses incurred by the road district or other unit of local government for negotiating, executing, constructing, or implementing the road use agreement. The road use agreement shall not require any road work to be performed by or paid for by the facility owner that is unrelated to the road improvements required for the construction of the commercial wind energy facility or the commercial solar energy facility or the restoration of the roads used by the facility owner during construction-related activities. Road-related fees, permit fees, or other charges imposed by the Illinois Department of Transportation, a road district, or other unit of local government under a road use agreement with the facility owner shall be reasonably related to the cost of administration of the road use agreement.

(s-5) The facility owner shall also compensate landowners for crop losses or other agricultural damages resulting from damage to the drainage system caused by the construction of the commercial wind energy facility or the commercial solar energy facility. The commercial wind energy facility owner or commercial solar energy facility owner shall repair or pay for the repair of all damage to the subsurface drainage system caused by the construction of the commercial wind energy facility or the commercial solar energy facility in accordance with the agriculture impact mitigation agreement requirements for repair of drainage. The commercial wind energy facility owner or commercial solar energy facility owner shall repair or pay for the repair and restoration of surface drainage caused by the construction or deconstruction of the commercial wind energy facility or the commercial solar energy facility as soon as reasonably practicable.

(t) Notwithstanding any other provision of law, a facility owner with siting approval from a county to construct a commercial wind energy facility or a commercial solar energy facility is authorized to cross or impact a drainage system, including, but not limited to, drainage tiles, open drainage ditches, culverts, and water gathering vaults, owned or under the control of a drainage district under the Illinois Drainage Code without obtaining prior agreement or approval from the drainage district in accordance with the farmland drainage plan required by subsection (j-5).

(u) The amendments to this Section adopted in Public Act 102-1123 do not apply to: (1) an application for siting approval or for a special use permit for a commercial wind energy facility or commercial solar energy facility if the application was submitted to a unit of local government before January 27, 2023 (the effective date of Public Act 102-1123); (2) a commercial wind energy facility or a commercial solar energy facility if the facility owner has submitted an agricultural impact mitigation agreement to the Department of Agriculture before January 27, 2023 (the effective date of Public Act 102-1123); or (3) a commercial wind energy or commercial solar energy development on property that is located within an enterprise zone certified under the Illinois Enterprise Zone Act, that was classified as industrial by the appropriate zoning authority on or before January 27, 2023, and that is located within 4 miles of the intersection of Interstate 88 and Interstate 39.

(Source: P.A. 102-1123, eff. 1-27-23; 103-81, eff. 6-9-23; 103-580, eff. 12-8-23; revised 7-29-24.)

(55 ILCS 5/5-12024 new)

Sec. 5-12024. Energy storage systems.

(a) As used in this Section:

"Energy storage system" means a facility with an aggregate energy capacity that is greater than 1,000 kilowatts and that is capable of absorbing energy and storing it for use at a later time, including, but not limited to, electrochemical and electromechanical technologies. "Energy storage system" does not include technologies that require combustion. "Energy storage system" also does not include energy storage systems associated with commercial solar energy facilities or commercial wind energy facilities as defined in Section 5-12020.

"Excused service interruption" means any period during which an energy storage system does not store or discharge electricity and that is planned or reasonably foreseeable for standard commercial operation, including any unavailability caused by a buyer; storage capacity tests; system emergencies; curtailments, including curtailment orders; transmission system outages; compliance with any operating restriction; serial defects; and planned outages.

"Facility owner" means (i) a person with a direct ownership interest in an energy storage system, regardless of whether the person is involved in acquiring the necessary rights, permits, and approvals or otherwise planning for the construction and operation of the facility and (ii) a person who, at the time the facility is being developed, is acting as a developer of the facility by acquiring the necessary rights, permits, and approvals or by planning for the construction and operation of the facility, regardless of whether the person will own or operate the facility.

"Force majeure" means any event or circumstance that delays or prevents an energy storage system from timely performing all or a portion of its commercial operations if the act or event, despite the exercise of commercially reasonable efforts, cannot be avoided by and is beyond the reasonable control, whether direct or indirect, of, and without the fault or negligence of, a facility owner or operator or any of its assignees. "Force majeure" includes, but is not limited to:

(1) fire, flood, tornado, or other natural disasters or acts of God;

(2) war, civil strife, terrorist attack, or other similar acts of violence;

(3) unavailability of materials, equipment, services, or labor, including unavailability due to global supply chain shortages;

(4) utility or energy shortages or acts or omissions of public utility providers;

(5) any delay resulting from a pandemic, epidemic, or other public health emergency or related restrictions; and

(6) litigation or a regulatory proceeding regarding a facility.

"NFPA" means the National Fire Protection Association.

"Nonparticipating property" means real property that is not a participating property.

"Nonparticipating residence" means a residence that is located on nonparticipating property and that exists and is occupied on the date that the application for a permit to develop an energy storage system is filed with the county.

"Occupied community building" means a school, place of worship, day care facility, public library, or community center that is occupied on the date that the application for a permit to develop an energy storage system is filed with the county in which the building is located.

"Participating property" means real property that is the subject of a written agreement between a facility owner and the owner of the real property and that provides the facility owner an easement, option, lease, or license to use the real property for the purpose of constructing an energy storage system or supporting facilities.

"Protected lands" means real property that is: (i) subject to a permanent conservation right consistent with the Real Property Conservation Rights Act; or (ii) registered or designated as a nature preserve, buffer, or land and water reserve under the Illinois Natural Areas Preservation Act.

"Supporting facilities" means the transmission lines, substations, switchyard, access roads, meteorological towers, storage containers, and equipment associated with the generation, storage, and dispatch of electricity by an energy storage system.

(b) Notwithstanding any other provision of law, if a county has formed a zoning commission and adopted formal zoning under Section 5-12007, then a county may establish standards for energy storage systems in areas of the county that are not within the zoning jurisdiction of a municipality. The standards may include all of the requirements specified in this Section but may not include requirements for energy storage systems that are more restrictive than specified in this Section or requirements that are not specified in this Section.

(c) A county may require the energy storage facility to comply with the version of NFPA 855 "Standard for the Installation of Stationary Energy Storage Systems" in effect on the effective date of this amendatory Act or any successor standard issued by the NFPA in effect on the date of siting or special use permit approval. A county may not include requirements for energy storage systems that are more restrictive than NFPA 855 "Standard for the Installation of Stationary Energy Storage Systems" unless required by this Section.

(d) If a county has elected to establish standards under subsection (b), then the zoning board of appeals for the county shall hold at least one public hearing before the county grants (i) siting approval or a special use permit for an energy storage system or (ii) modification of an approved siting or special use permit. The public hearing shall be conducted in accordance with the Open Meetings Act and shall conclude not more than 60 days after the filing of the application for the facility. The county shall allow interested parties to a special use permit an opportunity to present evidence and to cross-examine witnesses at the hearing, but the county may impose reasonable restrictions on the public hearing, including reasonable time limitations on the presentation of evidence and the cross-examination of witnesses. The county shall also allow public comment at the public hearing in accordance with the Open Meetings Act. The county shall make its siting and permitting decisions not more than 30 days after the conclusion of the public hearing. Notice of the hearing shall be published in a newspaper of general circulation in the county.

(e) A county with an existing zoning ordinance in conflict with this Section shall amend that zoning ordinance to comply with this Section within 120 days after the effective date of this amendatory Act of the 104th General Assembly.

(f) A county shall require an energy storage system to be sited as follows, with setback distances measured from the nearest edge of the nearest battery or other electrochemical or electromechanical enclosure: Setback Description Setback Distance Occupied Community 150 feet from the nearest Buildings and point of the outside wall of Nonparticipating Residences the occupied community building

or nonparticipating residence Boundary Lines of 50 feet to the nearest point Occupied Community on the property line of Buildings and the occupied community building Nonparticipating Residences or nonparticipating property Public Road Rights-of-Way 50 feet from the nearest edge

of the right-of-way (2) A county shall also require an energy storage syste m to be sited so that the facility's perimeter is enclosed by fencing having a height of at least 7 feet and no mo re than 25 feet. Thi s Section does not exempt or excuse compliance with electric fa cility clearances approved or required by the Nationa l Electrical Code, the National Electrical Safety Code, the Illinois Commerce Commissi on, the Federal Energy Regulatory Commission, and their designee s or successors. (g ) A county may not set a sound limitation for energy stora ge systems that is more restrictive than the sound limitation s established by the Illinois Pollution Control Board under 35 Ill. Adm. Code Parts 900, 901, and 910. After commercial o peration, a county may require the facility owner to pr ovide, not more than once, octave band sound pressure level measurements from a reasonable number of sampled locations at the per imeter of the energy storage system to demonstrate compliance w ith this Section. (h) The provisions set forth in subsection (f) may be waive d subject to the written consent of the owner of each affected nonparticipating property or nonpar ticipating residence. (i) A county may not place any restriction on the installation or use of an energy storage system unless it has formed a zoning commission and adopted formal zoning under Section 5-12 007 and adopts an ordinance that complies with this Section. A county may not establish siting standards for supporting facilities that preclude development of an energy st orage system. (j) A requ est for siting approval or a special use permit for an energ y storage system, or modification of an approved siting approva l or special use permit, shall be approved if the request c omplies with the standards and conditions imposed in th is Code, the zoning ordinance adopted consistent with t his Section, and other State and federal statutes and regulatio ns. The siting approval or special use permit approved by the c ounty shall grant the facility owner a period of at least 3 ye ars after county approval to obtain a building permit or com mence construction of the energy storage system, before the siting approval or special use permit may become subje ct to revocation by the county. Facility owners may be g ranted an extension on obtaining building permits or commencing constructing upon a showing of good cause. A facility owner's re quest for an extension may not be unreasonably withheld, con ditioned, or denied. (k) A county may not adopt zoning regulations that disallow, pe rmanently or temporarily, an energy storage system from being devel oped or operated in any district zones to allow agricultural or in dustrial uses. (l) A faci lity owner shall file a farmland drainage plan with the county and impacted drainage districts that outlin es how surface and subsurface drainage of farmland will be rest ored during and following the construction or deconstruction o f the energy storage system. The plan shall be created inde pendently by the facility owner and shall include the location of any potentially impacted drainage district facilities to t he extent the information is publicly available from the county or the drainage district and plans to re pair any subsurface drainage affected during construction or d econstruction using procedures outlined in the decommissioning plan. All su rface and subsurface damage shall be repaired as soon as reasonably practicable. (m) A facil ity owner shall compensate landowners for crop losses or o ther agricultural damages resulting from damage to a drainage s ystem caused by the construction of an energy storage system. The facility owner shall repair or pay for the repair of all da mage to the subsurface drainage system caused by the constru ction of the energy storage system. The facility owner shall r epair or pay for the repair and restoration of surfac e drainage caused by the construction or d econstruction of the energy storage facility as soon as re asonably practicable. (n) County siting approval or special use permit applicatio n fees for an energy storage system shall not exceed the lesser of (i) $5,000 per e ach megawatt of nameplate capacity of the energy storage system or (ii) $50,000. (o) The c ounty may require a facility owner to provide a decommissioning plan to the county. The decommissioning plan may include all requirements for decommis sioning plans in NFPA 855 and may also require the facility own er to: (1) state how the energy storage system will be decommis sioned, including removal to a depth of 3 feet of al l structures that have no ongoing purpose and all debris an d restoration of the soil and any vegetation to a con dition as close as reasonably practicable to the soil's and vegetation's preconstruction condition within 18 months of the end of project life or facility aband onment; (2) include provisions related to commercially reas onable efforts to reuse or recycle of equipment and com ponents associated with the commercial offsite energy storage sy stem; (3) include financial assurance in the form of a reclamati on or surety bond or other commercially available financial assurance that is acceptable to the county, with the co unty or participating property owner as beneficiary. T he amount of the financial assurance shall not be more tha n the estimated cost of decommissioning the energy facili ty, after deducting salvage value, as calculated by a prof essional engineer licensed to practice engineering i n this State with expertise in preparing decommissioning es timates, retained by the applicant. The financia l assurance shall be provided to the county incrementally as foll ows:

(A) 25% before the start of full commercial operat ion;

(B) 50% before the start of the 5th year of commercial operation ; and (C) 100% by the start of the tenth year of commercial operation ; (4) update the amount of the financial assuranc e not more than every 5 years for the duration of commerci al operations. The amount shall be calculated by a professi onal engineer licensed to practice engineering in this Stat e with expertise in decommissioning, hired by the facility own er; and (5) decommission the energy storage system, in accorda nce with an approved decommissioning plan, within 18 months after abandonment. An energy storage system that has not st ored electrical energy for 12 consecutive months or th at fails, for a period of 6 consecutive months, to pay a pr operty owner who is party to a written agreement, incl uding, but not limited to, an easement, option, lease, or license under the terms of which an energy storage syst em is constructed on the property, amounts owed in accor dance with the written agreement shall be considered abando ned, except when the inability to store en ergy is the result of an event of force majeure or excused ser vice interruption. ( p) A county may not condition approval of an energy storage system on a property value guarantee and may not require a facility owner to pay into a neighboring property devaluation escrow account. (q) A county may require that a facility owner provide:

(1) the results and recommendations from consultation with the Department of Natural Resources that are obtained through the Ecological Co mpliance Assessment Tool (EcoCAT) or a comparable successor tool; and ( 2) the results of the United States Fish and Wildlife S ervice's Information for Planning and Consulting or a comparab le successor tool. (r) A county may require an energy storage system to adhere to the recommendations provided by the Department of Natural Resources in an Agency Action Report under 17 Ill. Admin. Code 1075. (s) A county may require a facility own er to: (1) demonstrate avoidance of protected lands as identified by the Department of Natural Resources and the Illinois Nature Preserves Commission; or

(2) consider the recommendations of the Departme nt of Natural Resources for setbacks from protecte d lands, including areas identified by the Illinois Nature Prese rves Commission. (t) A county may require that a facility owner prov ide evidence of consultation with the Illinois Historic Preserv ation Division to assess potential impacts on State-registered his toric sites under the Illinois State Agency Historic Resources Pr eservation Act. (u) A county may require that an application for siting approval or special use permit include the following information on a site plan : (1) a description of the property lines and physical features, including roads, for the facility site; (2) a description of the proposed changes to the lan dscape of the facility site, including vegetation clear ing and planting, exterior lighting, and screening or structures; an d (3) a description of the zoning district designation for the parcel of land comprising th e facility site. ( v) A county may not prohibit an energy storage system from und ertaking periodic augmentation to maintain the approximate or iginal capacity of the energy storage system. A county may not require renewed or additional siting approval or spec ial use permit approval of periodic augmenta tion to maintain the approximate original capacity of the energ y storage system. (w ) A county that issues a building permit for energy storag e systems shall review and process building permit applicat ions within 60 days after receipt of the building permit application. If a county does not grant or deny the building p ermit application within 60 days, the building permit shall be deemed granted. If a county denies a building permit applicati on, it shall specify the reason for the denial in writing as pa rt of its denial. (x) A county may require a single building permit and permit fee f or the facility which includes all supporting facilities. A county building permit fee for an energy storage system shall not exceed the lesser of (i) $5,000 per each megawatt of na meplate capacity of the energy storage system or (ii) $50,000. A county may require that the application for building permit contain: (1) an electrical diagram detailing the battery en ergy storage system layout, associated components, and electrical interconnection methods, with all Nation al Electrical Code compliant disconnects and overcurrent devices; and (2) an equipment specif ication sheet. (y) A county may require the facility owner to submit to the cou nty prior to the facility's commercial operation a commission ing report meeting the requirements of NFPA 855 Sections 4. 2.4, 6.1.3, and 6.1.5.5, as publi shed in 2023, or the applicable Sections in the most recent versio n of NFPA 855. (z) A county may require the facility owner to submit to the count y prior to the facility's commercial operation a hazard mitiga tion analysis meeting the requirements of NFPA 85 5 Section 4.4 or the applicable Sections in the most recent version of NFPA 855. ( aa) A county may require the facility owner to submit to the co unty an emergency operations plan meeting the requirements of N FPA 855 Section 4.3.2.1.4, published in 2023, or applicable Sections in the most recent version of NFPA 855, prior to comme rcial operation. (bb) A c ounty may require a warning that complies with requirements in NFPA 855 Section 4.7.4, p ublished in 2023, or applicable sections in the most recent vers ion of NFPA 855. (cc) A county may require the energy storage system to adhere to the pr inciples for responsible outdoor lighting provided by the Inter national Dark-Sky Association and shall limit outdoor lig hting to that which is minimally required for safety and operational purposes. Any outdoor lighting shall be reasonably shielded and downcast from all residences and adjacent properties. (dd) This Sec tion does not exempt compliance with fire and safety standards and guidance established for the i nstallation of lithium-ion battery energy storage systems s et by the NFPA. (ee) Prio r to commencement of commercial operation, the facility owne r shall offer to provide training for local fire departments and emergency responders in accordance with the facility emergency operations plan. A copy of the emergency operations p lan shall be given to the facility owner, the local fire de partment, and emergency responders. All batteries integrated wi thin an energy storage system shall be listed under the UL 1 973 Standard. All batteries integrated within an energy st orage system shall be listed in accordan ce with UL 9540 Standard, either from the manufacturer or by a fiel d evaluation. (ff) If a facility owner enters into a road use agreement with the De partment of Transportation, a road district, or other unit of l ocal government relating to an energy storage system, t hen the road use agreement shall require the facility owner t o be responsible for (i) the reasonable cost of improving, i f necessary, roads used by the facility owner to construct the energy storage system and (ii) the reasonable cost of rep airing roads used by the facility owner during construction o f the energy storage system so that those roads are in a condition that is safe for the driving public after the complet ion of the facility's construction. A roadway improved in pr eparation for and during the construction of the energy storag e system shall be repaired and restored to the improved co ndition at the reasonable cost of the developer if the roadways hav e degraded or were damaged as a result of construction-re lated activities. The road use agreement shall not require the facility owner to pay cos ts, fees, or charges for road work that is not specifically a nd uniquely attributable to the construction of the energy stor age system. No road district or other unit of local gover nment may request or require a fine, permit fee, or other payme nt obligation as a requirement for a road use agreement with a facility owner unless the amount of the fine, permit fee, or other payment obligation is equivalent to the amount of actual expenses incurred by the road district or other unit of local government for negotiating, executing, constructing, or implementing the road use agreement. The road use agre ement shall not require the facility owner to perform or pay for any road work that is unrelated to the road improvements required for the construction of the commercial wind energy facility or the commercial solar energy facility or the restoration of th e roads used by the facility owner during construction-rela ted activities. (gg) T he provisions of this amendatory Act of the 104th General Assem bly do not apply to an application for siting approval or speci al use permit for an energy storage system if the application was submitted to a county before the effective date of this amendato ry Act of the 104th General Assembly.

(55 ILCS 5/Art. 5 Div. 5-46 heading new) Division 5-46. Solar Bill of Rights (55 ILCS 5/5-46005 new) Sec. 5-46005. Definitions. As used in this Di vision: "Low-volt age solar-powered device" means a piece of equipment des igned for a particular purpose, including, but not limited to, doorbells, security systems, and illumination equipment, power ed by a solar collector operating at less than 50 volts, and locat ed:

(1) entirely within the lot or parcel owned by the property owner; or (2) within a common area without being permanently attached to common pr operty. "Solar collector" m eans: (1) an assembly, structure, or design, including pass ive elements, used for gathering, concentrating, or absorbing direct and indirect solar energy and specia lly designed for holding a substantial amount of useful thermal energy and to transfer t hat energy to a gas, solid, or liquid or to use that energy directly; (2) a mechanism that absorbs solar energy and converts it into electricit y; (3) a mechanism or process used for gathering solar energy through wind or thermal gradients; o r (4) a component used to transf er thermal energy to a gas, solid, or liquid, or to convert it into electricity. "Solar energ y" means radiant energy received from the sun at wavelengths suitable for heat transfer, photosynthetic use, or photovoltaic u se. "Solar energy system" mea ns: (1) a complete assembly, structure, or design of a sola r collector or a solar storage mechanism that uses solar energy for generating electricity or f or heating or cooling gases, solids, liquids, or other materials; and (2) the design, materials, or elements of a system and its main tenance, operation, and labor components, and the necessary components, if any, of supplemental conventional energy systems designed or constructed to interface with a sola r energy system. "So lar storage mechanism" means equipment or elements, such as pi ping and transfer mechanisms, containers, heat exchanger s, batteries, or controls thereof and gases, solids, liqu ids, or combinations thereof, that are utilized for storing solar energy, gathe red by a solar collector, for subsequent use. (55 ILCS 5/5-46010 new) Sec. 5-46010. Prohibitions. Notwithstanding any provision of this C ode or other provision of law, the adoption of any ordinanc e or resolution or the exercise of any power by a county th at prohibits or has the effect of prohibiting the installation of a solar energy system or low-voltage solar-powered devices is expressly prohibited. (55 ILCS 5/5-46020 new) Sec. 5-46020. Costs; attorney's fees. In any litigation arising under this Division or involving the application of this Division, the prevailing party shall be enti tled to costs and reasonable attorney's fees. (55 ILCS 5/5-46025 new) Sec. 5-46025. Applicability. (a) As used in this Section, "shared roof" means any roof that (i) serves more than one unit, including, but not limited to, a contiguous roof serving adjacent units, or (ii) is part of the common elements or common area of a unit. (b) This Division shall not apply to any building tha t:

(1) is greater than 60 feet in height; or (2) has a shared roof and is subject to a homeowners' association, common in terest community association, or condominium unit owners ' association. (b) Notwithstanding subsection (a) of this Section, this Division shall apply to any building with a shared roof: (1) where the solar energy system is located entirely within that p ortion of the shared roof owned and maintained by the property owner;

(2) where all property owners sharing the shared roof are in agreement to install a solar energy system; or (3) to th e extent this Division applies to low-voltage solar-po wered devices. (c) Notwithstanding subsection (b) of this S ection, this Division shall apply to any building with a shared roof:

(1) where the solar energy system is located entirely within that p ortion of the shared roof owned and maintained by the property owner;

(2) where all property owners sharing the shared roof are in agreement to install a solar energy system; or (3) to the extent this Division applies to low-voltage solar-powered devices. Section 90-30. The Illinois Municipal Code is amended by adding Divisio n 15.5 as follows: (65 ILCS 5/Art. 11 Div. 15.5 heading new) Division 15.5. Solar Bill of Rights (65 ILCS 5/11-15.5-5 new) Sec. 11-15.5-5. Definitions. As used in this Di vision: "Low-volt age solar-powered device" means a piece of equipment des igned for a particular purpose, including, but not limited to, doorbells, security systems, and illumination equipment, power ed by a solar collector operating at less than 50 volts, and locat ed:

(1) entirely within the lot or parcel owned by the property owner; or (2) within a common area without being permanently attached to common pr operty. "Solar collector" m eans: (1) an assembly, structure, or design, including pass ive elements, used for gathering, concentrating, or absorbing direct and indirect solar energy and specia lly designed for holding a substantial amount of useful thermal energy and to transfer t hat energy to a gas, solid, or liquid or to use that energy directly; (2) a mechanism that absorbs solar energy and converts it into electricit y; (3) a mechanism or process used for gathering solar energy through wind or thermal gradients; o r (4) a component used to transf er thermal energy to a gas, solid, or liquid, or to convert it into electricity. "Solar energ y" means radiant energy received from the sun at wavelengths suitable for heat transfer, photosynthetic use, or photovoltaic u se. "Solar energy system" mea ns: (1) a complete assembly, structure, or design of a sola r collector or a solar storage mechanism that uses solar energy for generating electricity or f or heating or cooling gases, solids, liquids, or other materials; and (2) the design, materials, or elements of a system and its main tenance, operation, and labor components, and the necessary components, if any, of supplemental conventional energy systems designed or constructed to interface with a sola r energy system. "So lar storage mechanism" means equipment or elements, such as pi ping and transfer mechanisms, containers, heat exchanger s, batteries, or controls thereof and gases, solids, liqu ids, or combinations thereof, that are utilized for storing solar energy, gathe red by a solar collector, for subsequent use. (65 ILCS 5/11-15.5-10 new) Sec. 11-15.5-10. Prohibitions. Notwithstanding any provision of this Code or other provision of law, the adoption of any ordinance or resolution or the exercise of any power, by municipality th at prohibits or has the effect of prohibiting the installation of a solar energy system or low-voltage solar-powere d devices is expressly prohibited. Municipalities that own local ele ctric distribution systems may adopt and implement reasonable p olicies, consistent with Section 17-900 of the Public Utilities Act, regarding the int erconnection and use of solar energy systems. (65 ILCS 5/11-15.5-20 new) Sec. 11-15.5-20. Costs; attorney's fees. In any litigation arising under this Division or involving the application of this Division, the prevailing party shall be enti tled to costs and reasonable attorney's fees. (65 ILCS 5/11-15.5-25 new) Sec. 11-15.5-25. Applicability. (a) As used in this Section, "shared roof" means any roof that (i) serves more than one unit, including, but not limited to, a contiguous roof serving adjacent units, or (ii) is part of the common elements or common area of a unit. (b) This Division shall not apply to any building that: (1) is greater than 60 feet in height; or (2) has a shared roof and is subject to a homeowners' association, common interest community association, or condominium unit owners ' association. (c) Notwithstanding subsection (b) of this S ection, this Division shall apply to any building with a shared roof:

(1) where the solar energy system is located entirely within that p ortion of the shared roof owned and maintained by the property owner;

(2) where all property owners sharing the shared roof are in agreement to install a solar energy system; or (3) to the extent this Division applies to low-voltage solar-powered devices. Section 90-35. The Public Uti lities Act is amended by changing Sections 7-102, 8-103B, 8-406, 8-512, 9-229, 16-107.5, 16-107.6, 16-108, 16-108.19, 16-1 08.30, 16-111.5, 16-111.7, 16-115A, 16-119A, and 17-900 and by adding Sect ions 8-101.1, 8-513, 16-107.8, 16-107.9, 16-126.2, 16-145, 16-201, 16-202, 20-140, an d 20-145 as follows: (220 ILCS 5/7-1

02) (from Ch. 111 2/3, par. 7-102) Sec. 7-102. Transactions requiring Commi ssion approval. (A) Unless the consent and approval of the Commission is first obta ined or unless such approval is waived by the Commission or is exempted in accor dance with the provisions of this Section or of any oth er Section of this Act: (a) No 2 or more public utilities may enter into con tracts with each other that will enable such pu blic utilities to operate their lines or plants in connecti on with each other. (b) No public utility may purchase, lease, or in any other man ner acquire control, direct or indirect, over the franchises, licenses, permi ts, plants, equipment, business or other property of any other public utility. (c) No public utility may assign, transfer, leas e, mortgage, sell (by option or otherwise), or otherwise di spose of or encumber the whole or any part of its franc hises, licenses, permits, plant, equipment, business, or other property, but the consent and approval of the C ommission shall not be required for the sale, lease, assignment or transfer (1) by any public utility of any tangible personal property which is not necessary or useful in the performance of its duties to the p ublic, or (2) by any elec tric utility, as defined by Section 16-105, of functional control to a regional transmission operator, as define d in Section 16-126, of facilities operating a t 69,000 volts and that would otherwise qualify for such transfer und er the applicable rules of the regional transmission operator taking functional contro l, or (3) by any railroad of any real or tangi ble personal property. (d) No public utility may by any means, direct or ind irect, merge or consolidate its franchises, licenses, permits, plants , equipment, business or other property with that of any ot her public utility. (e) No public utility may purchase, acquire, take o r receive any stock, stock certificates , bonds, notes or other evidences of indebtedness of any ot her public utility. ( f) No public utility may in any manner, directly or indire ctly, guarantee the performance of any con tract or other obligation of any other person, firm or corpo ration whatsoever. (g) N o public utility may use, appropriate, or divert any of its moneys, property or other resources in or to any business or enterprise which is not, prior to such use , appropriation or diversion essentially and directly conn ected with or a proper and necessary department or divisi on of the business of such public utility; provided that this subsection sh all not be construed as modifying subsections (a) through (e) of this Section.

(h) No public utility may, directly or indirectly, invest, loan or advance, or permit to be invested, loaned or advanc ed any of its moneys, property or other resources in, f or, in behalf of or to any other person, firm, trust, gr oup, association, company or corporation whatsoever, excep t that no consent or approval by the Commission is nec essary for the purchase of stock in development credit c orporations organized under the Illinois Development Credit Corporation Act, providing that no such purchase may be ma de hereunder if, as a result of such purchase, the cumulative p urchase price of all such shares owned by the utilit y would exceed one-fiftieth of one per cent of the utility's gross operating revenue for the preceding calendar year. (B) Any pu blic utility may present to the Commission for approval opti ons or contracts to sell or lease real property, notwith standing that the value of the property under option may have changed between the date of the option and the subsequent date of sale or lease. If the options or contracts are approved by the Commission, subsequent sales or leases in conformance wit h those options or contracts may be made by the public ut ility without any further action by the Commission. If approval of the options or contracts is denied by the Commis sion, the options or contracts are void and any consi deration theretofore paid to th e public utility must be refunded within 30 days follo wing disapproval of the application. (C) Th e proceedings for obtaining the approval of the Commission pro vided for in this Section shall be as follows: There shall be filed with the Commission a petition, joint or ot herwise, as the case may be, signed and verified by the president, any vice president, secretary, treasurer, comptroll er, general manager, or chief engineer of the respective compan ies, or by the person or company, as the case may be, clearly setting forth the object and purposes desired, and setting fort h the full and complete terms of the proposed assignment, tran sfer, lease, mortgage, purchase, sale, merger, consolidation, c ontract or other transaction, as the case may be. Upon th e filing of such petition, the Commission shall, if it deems necessary, fix a time and place for the hearing there on. After such hearing, or in case no hearing is required, if the Commission is satisfied that such petition should reas onably be granted, and that the public will be convenienced ther eby, the Commission shall make such order in the premises as i t may deem proper and as the circumstances may require, attach ing such conditions as it may deem proper, and thereupon it shall be lawful to do the things provided for in su ch order. The Commission shall i mpose such conditions as will protect the interest of minority and preferred stockholders. (D) Th e Commission shall have power by general rules applicable alike to all public utilities, other than electric and gas publ ic utilities, affected thereby to waive the filing and necess ity for approval of the following: (a) sales of property in volving a consideration of not more than $300,000 for utilities with gross revenues in excess of $50,000,000 annually and a c onsideration of not more than $100,000 for all other utilities; (b) leases, easements and licenses involving a consider ation or rental of not more than $30,000 per year for ut ilities with gross revenues in excess of $50,000,000 annually a nd a consideration or rental of not more than $10,000 per year for all other utilities; (c) leases of office building space not required by the public utility in rendering service to the public; (d) the temporary leasing, lending or interchanging of equ ipment in the ordinary course of business or in case of an em ergency; and (e) purchase-money mortgages given by a p ublic utility in connection with the purchase of tangible p ersonal property where the total obligation to be secured shal l be payable within a period not exceeding one year. However, i f the Commission, after a hearing, finds that any publi c utility to which such rule is applicable is abusing or has abused such general rule and thereby is evading compli ance with the standard established herein, the Commission shall have power to require such public utility to thereafter file and receive the Commission's approval upon all such tran sactions as described in this Section, but such general rule shall remain i n full force and effect as to all other public utilitie s to which such rule is applicable. (E) T he filing of, and the consent and approval of the Commiss ion for, any assignment, transfer, lease, mortgage, purchase , sale, merger, consolidation, contract or other transaction by an electric or gas public utility with gross revenues in all j urisdictions of $250,000,000 or more annually involving a sale price or annual consideration in an amount of $5,000,000 or less shall not be required. The Commission shall also have the authority, on petition by an electric or gas public uti lity with gross revenues in all jurisdictions of $250,000,000 or more annually, to establish by order higher thresholds than the foregoing for the requirement of approval of transactions by the Commission pursuant to this Section for the electr ic or gas public utility, but no greater than 1% of the elec tric or gas public utility's average total gross utility plant in service in the case of sale, assignment or acquisition of property, or 2.5% of the electric or gas public utility's total revenue in the case of other sales price or annual c onsideration, in each case based on the preceding calendar ye ar, and subject to the power of the Commission, after notice a nd hearing, to further revise those thresholds at a later date. In addition to the foregoing, the Commission shall hav e power by general rules applicable alike to all electric an d gas public utilities affected thereby to waive the filing and necessity for approval of the following: (a) sales of prop erty involving a consideration of $100,000 or less for electri c and gas utilities with gross revenues in all jurisdictions o f less than $250,000,000 annually; (b) leases, easements and l icenses involving a consideration or rental of not mor e than $10,000 per year for electric and gas utilities with gro ss revenues in all jurisdictions of less than $250,000,000 a nnually; (c) leases of office building space not required by the electric or gas public utility in rendering service to the public; (d) the temporary leasing, lending or interchanging of equipment in the ordinary course of business or in th e case of an emergency; and (e) purchase-money mortga ges given by an electric or gas public utility in connecti on with the purchase of tangible personal property wh ere the total obligation to be secured shall be payable with in a period of one year or less. However, if the Commission, a fter a hearing, finds that any electric or gas public utilit y is abusing or has abused such general rule and thereby is evading compliance with the standard established herein, t he Commission shall have power to require such electric or gas public utility to thereafter file and receive the Co mmission's approval upon all such transactions as describ ed in this Section and not exempted pursuant to the first sentence of this paragraph or to subsection (g) of Section 16-1 11 of this Act, but such general rul e shall remain in full force and effect as to all other ele ctric and gas public utilities. Every ass ignment, transfer, lease, mortgage, sale or other disposition or encumbrance of the whole or any part of the franchi ses, licenses, permits, plant, equipment, business or other pr operty of any public utility, or any merger or consolidat ion thereof, and every contract, purchase of stock, or other t ransaction referred to in this Section and not exempted in a ccordance with the provisions of the immediately preceding paragraph of this Section, made otherwise than in accordance with an order of the Commission authorizing the same, except as provided in this Section, shall be void. The provisions of thi s Section shall not apply to a ny transactions by or with a political subdivision or m unicipal corporation of this State. (F) The provisions of this Section do not apply to the purchase or sale of emission allowances created under and defined in Title IV of the federal Clean Air Act Amendments of 1990 (P.L. 101-549), as amended.(Source: P.A. 90-561, eff. 12- 16-97; 91-357, eff. 7-29-99.)

(220 ILCS 5/8-101.1 new) Sec. 8-101.1. Duties of public utilities; labor force. (a) As used i n this Section: "L abor force" means the employees hired directly by the utilit y and all employees of any and all suppliers and subcontractors of the utility tasked with the construction, maintenance and repair of such utility's infrastructure. "Public utility " means a public utility, as defined in Section 3-105 of this Act, serving more than 100,000 customers as of January 1, 2025. "Substant ial change in labor force" means either (1) a greater th an 5% reduction in the total labor force or (2) more than a 5% decrease in the ratio of labor force spending compared to capital spending. (b) A public utility shall ensure that it has the nec essary labor force in order to furnish, provide, and ma intain such service instrumentalities, equipment, and facilit ies to promote the safety, health, comfort, and convenience of its patrons, employees, and the public and to be in all respects adequate, efficient, just, a nd reasonable. (c) Unles s the Commission specifically orders and except as otherwise p rovided in this Section, no substantial change shall be made b y any public utility in its labor force unless the public utility provides notice to the Commission at least 45 days be fore the implementation of the change. A public utilit y shall include a report with its notice that provides the following: (1) a detailed analysis and explanation of how and why a chang e in a specific law, regulation, or market factor requires the public utility to make the substantial change in its labor force ; and (2) whether the substantial change in the public utility's labor force, at a minimum: (i) is in the public interest; (ii) will not endanger the quality and availability of public utility servic es; (iii) will not have a negativ e impact on the safety or reliability of public utility services ; and (iv) is designed to minimize the financial hardship on the members of its la bor force impacted by the substantial change. (220 ILCS 5/8-103B) Sec. 8-103B. Energy efficiency and demand-res ponse measures. (a) It is th e policy of the State that electric utilities are required to use cost-effective energy efficiency and demand-r esponse measures to reduce delivery load. Requiring investment in cos t-effective energy efficiency and demand-res ponse measures will reduce direct and indirect cos ts to consumers by decreasing environmental impacts and by av oiding or delaying the need for new generation, transmission, and distribution infrastructure. It serves the public interes t to allow electric utilities to recover costs for reasonably a nd prudently incurred expenditures for energy efficiency and demand-response measures. As used in this Section, "cost-effecti ve" means that the measures satisfy the total resource cost t est. The low-income measures described in subsection ( c) of this Section shall not be required to meet the total resource cost test. For purposes of this Section, the terms "energy-ef ficiency", "demand-response", "electric utility", and "total resource cost test" have the meanings set forth in the Illinois Power Agency Act. "Black, indigenous, and people of color" and "BIPOC" means people who are members of the group s described in subparagraphs (a) through (e) of par agraph (A) of subsection (1) of Secti on 2 of the Business Enterprise for Minorities, Women, and Pers ons with Disabilities Act. (a-5) This Section applies to electric utilities serving more than 500,000 retail customers in the State for those multi-year plans commencing after Decem ber 31, 2017. (b) For purposes of this S ection, through calendar year 2026, elec tric utilities subject to this Section that serve more than 3,0 00,000 retail customers in the State shall be deemed to have achieved a cumulative persisting annual savings of 6 .6% from energy efficiency measures and programs implemented du ring the period beginning January 1, 2012 and ending December 31, 2017, which percent is based on the deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs. For the purposes of t his subsection (b) and subsection (b-5), the 88,000,000 M Whs of deemed electric power and energy sales shall be reduced by the number of MWhs equal to the sum of the annual consumption of customers that have opted out of subsections ( a) through (j) of this Section under paragraph (1) of subsec tion (l) of this Section, as averaged across the calendar years 2014, 2015, and 2016. After 2017, the deemed value of cum ulative persisting annual savings from energy efficiency measu res and programs implemented during the period beginning Ja nuary 1, 2012 and ending December 31, 2017, shall be reduced ea ch year, as follows, and the applicable value shall be applied to and count toward the utility's achievement of the cumulative persisting annual savings goals set forth in sub section (b-5): (1) 5.8% dee med cumulative persisting annual savings for the year endin g December 31, 2018; (2) 5.2% dee med cumulative persisting annual savings for the year endin g December 31, 2019; (3) 4.5% dee med cumulative persisting annual savings for the year endin g December 31, 2020; (4) 4.0% dee med cumulative persisting annual savings for the year endin g December 31, 2021; (5) 3.5% dee med cumulative persisting annual savings for the year endin g December 31, 2022; (6) 3.1% dee med cumulative persisting annual savings for the year endin g December 31, 2023; (7) 2.8% dee med cumulative persisting annual savings for the year endin g December 31, 2024; (8) 2.5% deemed cumulative persistin g annual savings for the year ending December 31, 2025; and (9) 2.3% deemed cumulative persisting annual savings for t he year ending December 31, 2026. ; (10) 2.1% deemed cumulativ e persisting annual savings for the year ending December 31, 2027; (11) 1.8% deemed cumulativ e persisting annual savings for the year ending December 31, 2028; (12) 1.7% deemed cumulativ e persisting annual savings for the year ending December 31, 2029; (13) 1.5% deemed cumulativ e persisting annual savings for the year ending December 31, 2030; (14) 1.3% deemed cumulativ e persisting annual savings for the year ending December 31, 2031; (15) 1.1% deemed cumulativ e persisting annual savings for the year ending December 31, 2032; (16) 0.9% deemed cumulativ e persisting annual savings for the year ending December 31, 2033; (17) 0.7% deemed cumulativ e persisting annual savings for the year ending December 31, 2034; (18) 0.5% deemed cumulativ e persisting annual savings for the year ending December 31, 2035; (19) 0.4% deemed cumulativ e persisting annual savings for the year ending December 31, 2036; (20) 0.3% deemed cumulativ e persisting annual savings for the year ending December 31, 2037; (21) 0.2% deemed cumulativ e persisting annual savings for the year ending December 31, 2038; (22) 0.1% deemed cumulative pe rsisting annual savings for the year ending December 31, 2039; and (2 3) 0.0% deemed cumulative persisting annual saving s for the year ending December 31, 2040 and all subse quent years. For p urposes of this Section, "cumulative persisting annual savings" means the total electric energy savings in a given year fr om measures installed in that year or in previous years, bu t no earlier than January 1, 2012, that are still operational and providing savings in tha t year because the measures have not yet reached the end of their useful lives. (b-5) Beginning in 2018 and through calendar year 2026, electric util ities subject to this Section that serve more than 3,000, 000 retail customers in the State shall achieve the following cumulative persisting annual savings goals, as modified by su bsection (f) of this Section and as compared to the deemed b aseline of 88,000,000 MWhs of electric power and energy sales set forth in subsection (b), as reduced by the number of MWh s equal to the sum of the annual consumption of customers that have opted out of subsections (a) through (j) of this Section under paragraph (1) of subsection (l) of this Section as avera ged across the calendar years 2014, 2015, and 2016, through th e implementation of energy efficiency measures duri ng the applicable year and in prior years, but no earlier th an January 1, 2012: (1) 7 .8% cumulative persisting annual savings for the year ending December 31, 2018; (2) 9 .1% cumulative persisting annual savings for the year ending December 31, 2019; (3) 10 .4% cumulative persisting annual savings for the year ending December 31, 2020; (4) 11 .8% cumulative persisting annual savings for the year ending December 31, 2021; (5) 13 .1% cumulative persisting annual savings for the year ending December 31, 2022; (6) 14 .4% cumulative persisting annual savings for the year ending December 31, 2023; (7) 15 .7% cumulative persisting annual savings for the year endin g December 31, 2024; (8) 17% cumulative persistin g annual savings for the year ending December 31, 2025; and (9) 17.9% cumulative persisting annual savings for t he year ending December 31, 2026. ; (10) 18.8% cumulativ e persisting annual savings for the year ending December 31, 2027; (11) 19.7% cumulativ e persisting annual savings for the year ending December 31, 2028; (12) 20.6% cumulative pe rsisting annual savings for the year ending December 31, 2029; and (13) 21.5 % cumulative persisting annual savings for the year ending December 31, 2030. No lat er than December 31, 2021, the Illinois Commerce Commission sha ll establish additional cumulative persisting annual savings go als for the years 2031 through 2035. No later than Decembe r 31, 2024, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2036 through 2040. The Commission shall also establish ad ditional cumulative persisting annual savings goals every 5 ye ars thereafter to ensure that utilities always have goals t hat extend at least 11 years into the future. The cumulative p ersisting annual savings goals beyond the year 2030 shall i ncrease by 0.9 percentage points per year, absent a Commiss ion decision to initiate a proceeding to consider establishing goals that increase by more or less than that amount. Such a pr oceeding must be conducted in accordance with the procedur es described in subsection (f) of this Section. If such a p roceeding is initiated, the cumulative persisting annual savi ngs goals established by the Commission through that proceedin g shall reflect the Commission's best estimate of the maximum amoun t of additional savings that are forecast to be cost-eff ectively achievable unless such best estimates would result i n goals that represent less than 0.5 percentage point annual increases in total cumulative persisting annual saving s. The Commission may only establish goals that represent le ss than 0.5 percentage point annual increases in cumulative per sisting annual savings if it can demonstrate, based on clear and convincing evidence and through independent analysis, th at 0.5 percentage point increases are not cost-effecti vely achievable. The Commission shall inform its decision based on an energy e fficiency potential study that conforms to the requirements of this Sectio n. (b-10) For purposes of this S ection, through calendar year 2026, elec tric utilities subject to this Section that serve less than 3,0 00,000 retail customers but more than 500,000 retail custom ers in the State shall be deemed to have achieved a cumulative persisting annual savings of 6.6% from energy efficiency measu res and programs implemented during the period beginning Ja nuary 1, 2012 and ending December 31, 2017, which is based o n the deemed average weather normalized sales of elect ric power and energy during calendar years 2014, 2015, and 2016 of 36,900 ,000 MWhs. For the purposes of this subsection (b-10) an d subsection (b-15), the 36,900,000 MWhs of deemed elect ric power and energy sales shall be reduced by the number of MWhs equal to the sum of the annual consumption of customers that have opted out of subsections (a) through (j) of thi s Section under paragraph (1) of subsection (l) of this Sec tion, as averaged across the calendar years 2014, 2015, and 20 16. After 2017, the deemed value of cumulative persisting an nual savings from energy efficiency measures and programs imple mented during the period beginning January 1, 2012 and ending December 31, 2017, shall be reduced each year, as follow s, and the applicable value shall be applied to and coun t toward the utility's achievement of the c umulative persisting annual savings goals set forth in subs ection (b-15): (1) 5.8% dee med cumulative persisting annual savings for the year endin g December 31, 2018; (2) 5.2% dee med cumulative persisting annual savings for the year endin g December 31, 2019; (3) 4.5% dee med cumulative persisting annual savings for the year endin g December 31, 2020; (4) 4.0% dee med cumulative persisting annual savings for the year endin g December 31, 2021; (5) 3.5% dee med cumulative persisting annual savings for the year endin g December 31, 2022; (6) 3.1% dee med cumulative persisting annual savings for the year endin g December 31, 2023; (7) 2.8% dee med cumulative persisting annual savings for the year endin g December 31, 2024; (8) 2.5% deemed cumulative persistin g annual savings for the year ending December 31, 2025; and (9) 2.3% deemed cumulative persisting annual savings for th e year ending December 31, 2026. ; (10) 2.1% deemed cumulativ e persisting annual savings for the year ending December 31, 2027; (11) 1.8% deemed cumulativ e persisting annual savings for the year ending December 31, 2028; (12) 1.7% deemed cumulativ e persisting annual savings for the year ending December 31, 2029; (13) 1.5% deemed cumulativ e persisting annual savings for the year ending December 31, 2030; (14) 1.3% deemed cumulativ e persisting annual savings for the year ending December 31, 2031; (15) 1.1% deemed cumulativ e persisting annual savings for the year ending December 31, 2032; (16) 0.9% deemed cumulativ e persisting annual savings for the year ending December 31, 2033; (17) 0.7% deemed cumulativ e persisting annual savings for the year ending December 31, 2034; (18) 0.5% deemed cumulativ e persisting annual savings for the year ending December 31, 2035; (19) 0.4% deemed cumulativ e persisting annual savings for the year ending December 31, 2036; (20) 0.3% deemed cumulativ e persisting annual savings for the year ending December 31, 2037; (21) 0.2% deemed cumulativ e persisting annual savings for the year ending December 31, 2038; (22) 0.1% deemed cumulative pe rsisting annual savings for the year ending December 31, 2039; and (2 3) 0.0% deemed cumulative persisting annual saving s for the year ending December 31, 2040 and all subsequent years. (b-15) Beginning in 2018 and through calendar year 2026, electric ut ilities subject to this Section that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall achieve the following cumulative persisting annual savings goals, as modified by subsection (b-20) and sub section (f) of this Section and as compared to the deemed basel ine as reduced by the number of MWhs equal to the sum of the annual consumption of customers that have opted out of s ubsections (a) through (j) of this Section under paragraph ( 1) of subsection (l) of this Section as averaged across the calendar years 2014, 2015, and 2016, through the imp lementation of energy efficiency measures duri ng the applicable year and in prior years, but no earlier th an January 1, 2012: (1) 7 .4% cumulative persisting annual savings for the year ending December 31, 2018; (2) 8 .2% cumulative persisting annual savings for the year ending December 31, 2019; (3) 9 .0% cumulative persisting annual savings for the year ending December 31, 2020; (4) 9 .8% cumulative persisting annual savings for the year ending December 31, 2021; (5) 10 .6% cumulative persisting annual savings for the year ending December 31, 2022; (6) 11 .4% cumulative persisting annual savings for the year ending December 31, 2023; (7) 12 .2% cumulative persisting annual savings for the year endin g December 31, 2024; (8) 13% cumulative persistin g annual savings for the year ending December 31, 2025; and (9) 13.6% cumulative persisting annual savings for t he year ending December 31, 2026. ; (10) 14.2% cumulativ e persisting annual savings for the year ending December 31, 2027; (11) 14.8% cumulativ e persisting annual savings for the year ending December 31, 2028; (12) 15.4% cumulative pe rsisting annual savings for the year ending December 31, 2029; and (13) 16% cumulative persisting annual savings for the year ending December 31, 2030. No lat er than December 31, 2021, the Illinois Commerce Commission sha ll establish additional cumulative persisting annual savings go als for the years 2031 through 2035. No later than Decembe r 31, 2024, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2036 through 2040. The Commission shall also establish ad ditional cumulative persisting annual savings goals every 5 ye ars thereafter to ensure that utilities always have goals t hat extend at least 11 years into the future. The cumulative p ersisting annual savings goals beyond the year 2030 shall i ncrease by 0.6 percentage points per year, absent a Commiss ion decision to initiate a proceeding to consider establishing goals that increase by more or less than that amount. Such a pr oceeding must be conducted in accordance with the procedur es described in subsection (f) of this Section. If such a p roceeding is initiated, the cumulative persisting annual savi ngs goals established by the Commission through that proceedin g shall reflect the Commission's best estimate of the maximum amoun t of additional savings that are forecast to be cost-eff ectively achievable unless such best estimates would result i n goals that represent less than 0.4 percentage point annual increases in total cumulative persisting annual saving s. The Commission may only establish goals that represent le ss than 0.4 percentage point annual increases in cumulative per sisting annual savings if it can demonstrate, based on clear and convincing evidence and through independent analysis, th at 0.4 percentage point increases are not cost-effecti vely achievable. The Commission shall inform its decision based on an energy e fficiency potential study that conforms to the requirements of this Se ction. (b-16) In 2027 and each year thereafter, each electric utili ty subject to this Section shall achieve the following savings goals : (1) A utility that serves more than 3,000,000 retail custo mers in the State must achieve incremental annual energy s avings for customers in an amount that is equal to 2% of th e utility's average annual electricity sales from 2021 through 2023 to customers. A utility that serves less than 3,000,000 retail customers but more than 500,000 ret ail customers in the State must achieve incremental annu al energy savings for customers in an amount that is e qual to 1.4% in 2027, 1.7% in 2028, and 2% in 2029 and ever y year thereafter of the utility's average annual electri city sales from 2021 through 2023 to customers. The incre mental annual energy savings requirements set forth in thi s paragraph (1) may be reduced by 0.025 percentage points for every percentage point increase, above the 25% minimum to be targeted at low-income households as specified in pa ragraph (c) of this Section, in the portion of total efficienc y program spending that is on low-income or moderate-income efficiency programs. The incremental annua l savings requirement shall not be reduced to a leve l less than 25% less than the energy savings requirement applica ble to the calendar year, even if the sum of low-income spending and moderate-income spending is greater than 35% of total spending .

(2) A utility that serves less than 3,000,000 retail cust omers but more than 500,000 retail customers in the State must achieve an incremental annual coincident peak demand savings goal from energy efficiency measures i nstalled as a result of the utility's programs by custo mers in an amount that is equal to the energy savings g oal from paragraph (1) of this Section divided by the act ual average ratio of kilowatt-hour savings to coi ncident peak demand reduction achieved by the utility thr ough its energy efficiency programs in 2023. If the seas on in which coincident peak demands are experience d, the hours of the day that peak demands are experienc ed, and the methods by which peak demand impacts from effi ciency measures are estimated are different in th e future than when 2023 peak demand impacts were or iginally estimated, the 2023 peak demand impacts shall be recomputed using such updated peak definitions and estimati on methods for the purpose of establishing future coinci dent peak demand savings goals. To the extent that a util ity counts either improvements to the efficiency of the use of gas and other fuels or the electrification of gas and oth er fuels toward its energy savings goal, as permitted under paragraphs (b-25) and (b-27) of this Secti on, it must estimate the actual impacts on coincident pe ak demand from such measures and count them, whether po sitive or negative, toward its coincident peak demand sav ings goal. Only coincident peak demand savings from efficiency measures shall count toward this goal. To t he extent that some efficiency measures enable demand respo nse, only the peak demand savings from the energy ef ficiency upgrade shall count toward the goal. Nothing in this S ection shall limit the ability of peak demand savings fro m such enabled demand-response initiatives to count for other, non-energy efficiency performance standard performance metrics established for the utility. (3) Each utility's incremental annual energy savings, and c oincident peak demand savings if a utility serves less t han 3,000,000 retail customers but more than 500,000 retail customers in the State, must be achieved with an average savin gs life of at least 12 years. In no event can more t han one-fifth of the incremental annual savings or th e coincident peak demand savings counted toward a utili ty's annual savings goal in any given year be derived fr om efficiency measures with average savings lives of less than 5 years. Average savings lives may be shorter than the average operational lives of measures installed if the measures do not produce savings in every year in which the measures operate or if the savings that measures produce decline during the measures' operational lives. F or the purposes of this Section, "incremental annual ener gy savings" means the total electric energy sav ings from all measures installed in a calendar year that will b e realized within 12 months of each measure's installa tion; "moderate-income" means income between 80% of a rea median income and 300% of the federal poverty limit; " incremental annual coincident peak demand savings" means th e total coincident peak reduction from all ener gy efficiency measures installed in a calendar year that will be realized within 12 months of each measure's insta llation; "average savings life" means the lifetime sav ings that would be realized as a result of a utility's efficiency progr ams divided by the incremental annual savings such programs pro duce. (b-20) Each el ectric utility subject to this Section may include cost-e ffective voltage optimization measures in its plans submitted under subsections (f) and (g) of this Section, and the costs incurre d by a utility to implement the measures under a Commission-ap proved plan shall be recovered under the provisions of Article IX or Section 16-108.5 of this Act. For pur poses of this Section, the measure life of voltage optimizatio n measures shall be 15 years. The measure life period is indepe ndent of the depreciation rate of the voltage optimization assets deployed. Utilities may claim savings from vo ltage optimization on circuits for more than 15 years if they can demonstrate that they have made additional investmen ts necessary to enable voltage optimization savings to continue beyo nd 15 years. Such demonstrations must be subject to the re view of independent evaluation. Within 270 days a fter June 1, 2017 (the effective date of Public Act 99-906), an electric utility that serves less than 3,000,00 0 retail customers but more than 500,000 retail customers in t he State shall file a plan with the Commission that identif ies the cost-effective voltage optimization investment the electric utility plans to undertake through December 31, 20 24. The Commission, after notice and hearing, shall approve or approve with modification the plan within 120 days after the plan's filing and, in the order approving or approving with modification the plan, the Commission shall adjust the applica ble cumulative persisting annual savings goals set forth in subsecti on (b-15) to reflect any amount of cost-ef fective energy savings approved by the Commission that is greater than or less than the following cumulative persisting annu al savings values attributable to voltage optimization for the applicable year: (1) 0.0% of cumulative persisting annual savings for the year ending December 31, 2018; (2) 0.17% of cumulative persisting annual savings for the year ending December 31, 2019; (3) 0.17% of cumulative persisting annual savings for the year ending December 31, 2020; (4) 0.33% of cumulative persisting annual savings for the year endin g December 31, 2021; (5) 0.5% of cumulative persisting annual savings for the year ending December 31, 2022; (6) 0.67% of cumulative persisting annual savings for the year ending December 31, 2023; (7) 0.83% of cumulative persisting annual savings for the year ending De cember 31, 2024; and (8) 1.0% of cumulative persisting annual savings for the year ending December 31, 2025 and all sub sequent years. (b-25) In t he event an electric utility jointly offers an energy efficiency m easure or program with a gas utility under plans approved und er this Section and Section 8-104 of this Act, the electr ic utility may continue offering the program, including the g as energy efficiency measures, in the event the gas utilit y discontinues funding the program. In that event, the energy s avings value associated with such other fuels shall be con verted to electric energy savings on an equivalent Btu basis for the premises. However, the electric utility shall prioritize progra ms for low-income residential customers to the extent practicable. An electric utility may recover the costs of offering the gas energy efficiency measures under this subs ection (b-25). For those e nergy efficiency measures or programs that save both electricit y and other fuels but are not jointly offered with a gas utility u nder plans approved under this Section and Section 8-104 or not offered with an affiliated gas utility under paragraph (6) of subsection (f) of Section 8-104 of this Act, the ele ctric utility may count savings of fuels other than electricit y toward the achievement of its annual savings goal, and t he energy savings value associated with such other fuels shall be co nverted to electric energy savings on an equivalent Btu basis at the premises. For an e lectric utility that serves more than 3,000,000 retail cust omers in the State, on and after January 1, 2027, the electric ut ility may only count savings of other fuels under this su bsection (b-25) toward the achievement of its annual elec tric energy savings goal when such other fuel savings are from weatherization measures that reduce heat loss through the bui lding envelope or heating distribution system, including, but not limited to, air sealing and building shell measures. Th is limitation on counting other fuel savings from efficiency measures toward a utility's energy savings goal sha ll not affect the utility's ability to claim savings from electrificat ion measures installed pursuant to the requirements in sub section (b-27). In no event shall more tha n 10% of each year's applicable annual total savings requiremen t, as defined in paragraph (7.5) of subsection (g) o f this Section be met through savings of fuels other than ele ctricity. For an electric utility that serves more tha n 3,000,000 retail customers in the State, in no event shall more tha n 30% of each year's incremental annual energy savings re quirement, as defined in subsection (b-16) of this Se ction, be met through savings of fuels other than electr icity. For an electric utility that serves less than 3,000,000 r etail customers but more than 500,000 retail customers in the State, in no event shall more than 20% of each year's incremen tal annual energy savings requirement, as defined in subsection (b-16) of this Section, be met through savings of fuels other than electricity. (b-2 7) Beginning in 2022, an electric utility may offer and promo te measures that electrify space heating, water heating, coolin g, drying, cooking, industrial processes, and other building a nd industrial end uses that would otherwise be served by combustion of fossil fuel at the premises, provided that the electrification measures reduce total energy consumptio n at the premises. The electric utility may count the redu ction in energy consumption at the premises toward achievement of its annual savings goals. The reduction in energy consum ption at the premises shall be calculated as the differenc e between: (A) the reduction in Btu consumption of fossil fuel s as a result of electrification, converted to kilowatt-hour equivalents by dividing by 3,412 Btus per kilowat t hour; and (B) the increase in kilowatt hours of electrici ty consumption resulting from the displacement of fossi l fuel consumption as a result of electrification. An ele ctric utility may recover the co sts of offering and promoting electrification measures under this subsection (b-27). At least 33 % of all costs of offering and promoting electrification measures under this subsection (b-27) must be for s upporting installation of electrification measures through pr ograms exclusively targeted to low-income households. The percentage requirement may be reduced if the utility can demonstrate that it is not possible to achieve the level of low-income electrification spending, while supporting programs for non-low-income residential and business electrification, be cause of limitations regarding the number of low-income households in its service territory that would be able to meet program el igibility requirements set forth in the multi-year ener gy efficiency plan. If the 33% low-income electrification spending requirement is reduced, the utility must priori tize support of low-income electrification in housing that meets program eligibility requirements over electrifi cation spending on non-low-income residential or busines s customers. The rati o of spending on electrification measures targeted to low-income, mul tifamily buildings to spending on electrification measures targeted to low-income, single-fami ly buildings shall be designed to achieve levels of electrification savings from each building type that are approximately proportional to the magnitude o f cost-effective electrification savings potential in each building type. In no ev ent shall electrification savings counted toward each year's applicable annual total savings requirement, as defined in paragraph (7 .5) of subsection (g) of this Section, or counted toward each year's incremental annual savings, a s defined in paragraph (b-16) of this Section, be greater than: (1) 5% per year for each year from 2022 through 2025; (2) 20% 10% per year for each year from 2026 and all subsequent years through 2029; and (3) (blank) . 15% per year for 2030 and all subsequ ent years.In addition , a minimum of 25% of all electrification savings counte d toward a utility's applicable annual total savings requirement must be from elec trification of end uses in low-income housing. The limitations on electrification savings that may be coun ted toward a utility's annual savings goals are separate from and in addition to the subsection (b-25) limitations governi ng the counting of the other fuel savings resultin g from efficiency measures and programs. As part of the annual informational filing to the Commission that is required under paragraph (9) of subsection (g) of this Section, e ach utility shall identify the specific electrificatio n measures offered under this subsection (b-27); the q uantity of each electrification measure that was installed b y its customers; the average total cost, average utility co st, average reduction in fossil fuel consumption, and average increase in electricity consumption associated with each electrification measure; the portion of installations of each ele ctrification measure that were in low-income single-family housing, low-in come multifamily housing, non-low-income singl e-family housing, non-low-income multifamil y housing, commercial buildings, and industrial facilities ; and the quantity of savings associated with each measure ca tegory in each customer category that are being counted toward the uti lity's applicable annual total savings requirement or counted toward e ach year's incremental annual savings, as defined in paragraph (b-16) of this Section. Prior to installing or promoting an electrification measures measure, the utility shall provide customers a customer with estimates an estimate of the impact of the new measures measure on the customer's average monthly electric bill and total annu al energy expenses. (c) Electric utilities shall be responsible for overseeing the design, dev elopment, and filing of energy efficiency plans with the Commission and may, as part of that implementation, outsou rce various aspects of program development and implementation. A minimum of 10%, for electric utilities that serve more th an 3,000,000 retail customers in the State, and a minimu m of 7%, for electric utilities that serve less than 3,000 ,000 retail customers but more than 500,000 retail custo mers in the State, of the utility's entire portfolio funding level f or a given year shall be used to procure cost-effective energy efficiency measures from units of local govern ment, municipal corporations, school districts, publi c housing, public institutions of higher education, and commun ity college districts, provided that a minimum percentage of available funds shall be used to procure energy efficie ncy from public housing, which percentage shall be equal to public housing's share of public bu ilding energy consumption. The u tilities shall also implement energy efficiency measures target ed at low-income households, which, for purposes of this Section, shall be defined as households at or below 80% of area median income, and expenditures to implement the measur es shall be no less than 25% of total energy efficienc y program spending approved by the Commission pursuant to review of plans filed under subsection (f) of this Section $40,000, 000 per year for electric utilities that serve more than 3,0 00,000 retail customers in the State and no less than $13,0 00,000 per year for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in t he State. The ratio of spending on efficienc y programs targeted at low-income multifamily buildings to spe nding on efficiency programs targeted at low-income s ingle-family buildings shall be designed to achieve levels of savings from each building type that are approximately propor tional to the magnitude of cost-effective lifetime savings potent ial in each building type. Investment in low-incom e whole-building weatherization programs shall constitute a minimum of 80% of a utility's total budget specifically dedicated to serv ing low-income customers. The utilities shall work to bundle low-income energy efficiency offerings wi th other programs that serve low-income households to maxim ize the benefits going to these households. The utilities shall marke t and implement low-income energy efficiency programs in coordination with low-income assistance pr ograms, the Illinois Solar for All Program, and weatherization whenever practicable. The program implementer shall walk th e customer through the enrollment process for any programs for which the customer is eligible. The utilities shall also pilot targeting customers with high arrearages, high energy intensity (ratio of energy usage divided by home or unit square footage), or energy assistance programs with energy e fficiency offerings, and then track reduction in arrearages as a result of the targeting. This targeting and bundling of low-in come energy programs shall be offered to bo th low-income single-family and multifamily c ustomers (owners and residents). The utili ties shall invest in health and safety measures appropriate and necessary for comprehensively weatherizing a home or multifamil y building, and shall implement a health and safety fund of at least 15% of the total income-qualified weath erization budget that shall be used for the purpose of making grants for technical assistance, construction, re construction, improvement, or repair of buildings to facilitate their part icipation in the energy efficiency programs targeted at low-income single-family and multifamily house holds. These funds may also be used for the purpose of m aking grants for technical assistance, construction, recon struction, improvement, or repair of the following building s to facilitate their participation in the energy efficien cy programs created by this Section: (1) buildings that are ow ned or operated by registered 501(c)(3) public charities; and (2) day care centers, day care homes, or group day care homes, as defined under 89 Ill. Adm. Code Part 406, 407, or 408, respectively. Each electric utility shall assess opportunities to implement co st-effective energy efficiency measures and programs t hrough a public housing authority or authorities located in its service territory. If such opportunities are identified , the utility shall propose such measures and programs t o address the opportunities. Expenditures to address such o pportunities shall be credited toward the min imum procurement and expenditure requirements set forth in this subsection (c). Implementation o f energy efficiency measures and programs targeted at low-income households should be contracted, when it is pr acticable, to independent third parties that have demonstrated capabilities to serve such households, with a preference for not-f or-profit entities and government agencies that have existing rela tionships with or experience serving low-inc ome communities in the State. E ach electric utility shall develop and implement reporti ng procedures that address and assist in determining the amount of e nergy savings that can be applied to the low-income procu rement and expenditure requirements set forth in this subs ection (c). Each electric utility shall also track the types and quantities or volumes of insulation and air sealing materials, and their associated energy saving benefits, installed in energy efficiency program s targeted at low-income single-family and multifam ily households. The electric uti lities shall participate in a low-income energy effic iency accountability committee ("the committee"), which will direct ly inform the design, implementation, and evaluation of the l ow-income and public-housing energy efficie ncy programs. The committee shall be comprised of the elec tric utilities subject to the requirements of this Section, the gas util ities subject to the requirements of Section 8-104 of this Act, the utilities' low-income energy efficiency implementation contractors, nonprofit organizati ons, community action agencies, advocacy groups, State and l ocal governmental agencies, public-housing organizat ions, and representatives of community-based organizati ons, especially those living in or working with environmental j ustice communities and BIPOC communities. The committee shall be composed of 2 geographically differentiated subcommitte es: one for stakeholders in northern Illinois and one for stakeholders in cen tral and southern Illinois. The subcommittees shall meet together at least twice per year. There sha ll be one statewide leadership committee led by and composed o f community-based organizations that are represe ntative of BIPOC and environmental justice communities and tha t includes equitable representation from BIPOC communities. Th e leadership committee shall be composed of an equal number of representatives from the 2 subcommittees. The subcommittee s shall address specific programs and issues, with the lead ership committee convening targeted workgroups as needed. The leadership committee may elect to work with an independent facilitator to solicit and organize feedback, recommendations an d meeting participation from a wide variety of communi ty-based stakeholders. If a facilitator is used, they shall be fair and responsive to the needs of all stakeholders involved in the committee. For a utility that serves more than 3,000,000 retail customers in the State, i f a facilitator is used, they shall be retained by Commiss ion staff. All committee meetings must be accessible, with rotating locations if meetings are held in-person, virtual participation options, and material s and agendas circulated in advance. There shall also be opportunities for direct input by committee members outside of committee meetings, such as via individual m eetings, surveys, emails and calls, to ensure robust participat ion by stakeholders with limited capacity and ability to atte nd committee meetings. Committee meetings shall emphasize opportun ities to bundle and coordinate delivery of low-income energ y efficiency with other programs that serve low-income communities, such as the Illinois Solar for All Program and bill payment assistance programs. Meetings shall include educat ional opportunities for stakeholders to learn more about these additional offerings, and the committee shall a ssist in figuring out the best methods for coordinated delivery and implementation of offerings when serving low-inco me communities. The committee shall directly and equitably influ ence and inform utility low-income and public-hou sing energy efficiency programs and priorities. Par ticipating utilities shall implement recommendations from the committee whenever possible. Particip ating utilities shall track and report how input from the commi ttee has led to new approaches and changes in their energ y efficiency portfolios. This reporting shall occur at committee meetings and in quarterly energy efficiency reports to the Stakeholder Advisory Group and Illinois Commerce Commi ssion, and other relevant reporting mechanisms. Participatin g utilities shall also report on relevant equity dat a and metrics requested by the committee, such as energy bu rden data, geographic, racial, and other relevant demogra phic data on where programs are being delivered and what populations programs are serving. The Il linois Commerce Commission shall oversee and have rele vant staff participate in the committee. The committee sha ll have a budget of 0.25% of each utility's entire efficiency portfolio funding for a given year. The budget shall be overseen by t he Commission. The budget shall be used to provide grants for community-based organizations serving on the leade rship committee, stipends for community-based organizations par ticipating in the committee, grants for community-based o rganizations to do energy efficiency outreach and educa tion, and relevant meeting needs as determined by the le adership committee. The education and outreach shall include, bu t is not limited to, basic energy efficiency education , information about low-income energy e fficiency programs, and information on the committee's purpose, structure, and activities. (d ) Notwithstanding any other provision of law to the contrary, a uti lity providing approved energy efficiency measures and, if applicable, demand-response measures in the State shall be permitted to recover all reasonable and pruden tly incurred costs of those measures from all retail customers , except as provided in subsection (l) of this Section, as follows, provided that nothing in this subsection (d) permits the double recovery of suc h costs from customers: (1) The utility may recover its costs through an automatic adjustment clause tariff filed with and approved by the Commission. The tariff shall be established o utside the context of a general rate case. Each year the Commission shall initiate a review to reconcile any amo unts collected with the actual costs and to determine the required adjustment to the annual tariff factor to matc h annual expenditures. To enable the financing of th e incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,0 00 retail customers but more than 500,000 retail custom ers in the State, the utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% o f the total capital structure shall be deemed reasonable and used to set rates. (2) A utility may recover its costs through an energy effi ciency formula rate approved by the Commission under a filing under subsections (f) and (g) of this Section, which shall specify the cost components that form the b asis of the rate charged to customers with sufficie nt specificity to operate in a standardized manner and be u pdated annually with transparent information that reflec ts the utility's actual costs to be recovered during the applicable rate year, which is the period beginning with the first billing day of January and extending thr ough the last billing day of the following Decemb er. The energy efficiency formula rate shall be implemented through a tariff filed with the Commission under subsect ions (f) and (g) of this Section that is consistent wi th the provisions of this paragraph (2) and that shall be a pplicable to all delivery services customers. The Commissi on shall conduct an investigation of the tariff in a m anner consistent with the provisions of this paragraph (2), subsections (f) and (g) of this Section, and the provisions of Article IX of this Act to the extent they do not conflict with this paragraph (2). The energy ef ficiency formula rate approved by the Commission shal l remain in effect at the discretion of the utility and sh all do the following: (A) Provide for the recovery of the utilit y's actual costs incurred under this Section that are p rudently incurred and reasonable in amount consisten t with Commission practice and law. The sole fact that a cost differs from that incurred in a prior calendar year or that an investment is differen t from that made in a prior calendar year shall not imply the imprudence or unreasonableness of that cost or investment. ( B) Reflect the utility's actual year-end capita l structure for the applicable calendar year, excluding goodwill, subject to a determination of prudenc e and reasonableness consistent with Commission practic e and law. To enable the financing of the incremen tal capital expenditures, including regulatory assets, for electric utilities that serve less t han 3,000,000 retail customers but more than 500,000 re tail customers in the State, a participating electric u tility's actual year-end capital structure that i ncludes a common equity ratio, excluding goodwill, of up to and including 50% o f the total capital structure shall be deemed reasonable and used to set rates. (C) Inc lude a cost of equity that shall be e qual to the baseline cost of equity approved by the Commission for the utility's electric distribution rates eff ective during the applicable year, whether those r ates are set pursuant to Section 9-201, subparagra ph (B) of paragraph (3) of subsection (d) of Section 16-108.18, or any successor electric distribution ratemaking paradigm. , which shall be calculated as the sum of the following: (i) the average for the applicable calendar year of the monthly average yields of 30-y ear U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and (ii) 580 basis points. At such time as the Board of Governors of the Fed eral Reserve System ceases to include the mon thly average yields of 30-year U.S. Treasury b onds in its weekly H.15 Statistical Release or s uccessor publication, the monthly average yields of the U.S. Treasury bonds then having the longest durati on published by the Board of Governors in its weekly H.15 Statistical Release or successor pub lication shall instead be used for purposes of this paragraph (2). (D) Permit and set forth protocols, su bject to a determination of prudence and reasonableness consistent with Commission practice and law, for the following: (i) recovery of incentive compe nsation expense that is based on the achievement of operational metrics, including metrics related t o budget controls, outage duration and frequency, safety, customer service, efficiency and product ivity, and environmental compliance; however, t his protocol shall not apply if such expense relat ed to costs incurred under this Section is recov ered under Article IX or Section 16-108.5 of this Act; incentive compensation expens e that is based on net income or an affiliate's earnin gs per share shall not be recoverable under the energ y efficiency formula rate; (ii) recovery of pension and other post-employment benefits expense, provided that such costs are supported by an actuarial study; however, this protocol shall not apply if such expense related to costs incurred under th is Section is recovered under Article IX or Section 16-10 8.5 of this Act;

(iii) recovery of exist ing regulatory assets over the periods previously autho rized by the Commission; (iv) as desc ribed in subsection (e), amortization of costs incurred unde r this Section; and (v) p rojected, weather normalized billing determinants for the applicable rate year. (E) Provide for an annual reconciliation, as described in paragraph (3) of this subsection (d), l ess any deferred taxes related to the reconciliation, with interest at an annual rate of return equal to th e utility's weighted average cost of capital, including a revenue conversion factor calculated to recover or re fund all additional income taxes that may be payable o r receivable as a result of that return, of the energ y efficiency revenue requirement reflected in rat es for each calendar year, beginning with the calen dar year in which the utility files its energy effici ency formula rate tariff under this paragraph (2), w ith what the revenue requirement would have been had the actual cost information for the applicable calendar year been available at the filing date. Th e utility shall file, together with its tariff, the projected costs to be incurred by the utility during the rate year under the utility's multi-year plan approved under su bsections (f) and (g) of this Section, includ ing, but not limited to, the projected capital investm ent costs and projected regulatory asset balances wit h correspondingly updated depreciation and amortization reserves and expense, that shall populate the energy efficiency formula rate and set the initial ra tes under the formula. The Com mission shall review the proposed tariff in conjunction with its review of a proposed multi-year plan, as spe cified in paragraph (5) of subsection (g) of this Section. The review shall be based on the same evidentiary standar ds, including, but not limited to, those concerning the pru dence and reasonableness of the costs incurred by the util ity, the Commission applies in a hearing to review a filing for a general increase in rates under Article IX of t his Act. The initial rates shall take effect beginni ng with the January monthly billing period following the C ommission's approval. The tariff's rate design and cost allocation across cus tomer classes shall be consistent with the utility's automatic adjustment clause tariff in effect on June 1, 2017 (the effective date of Public Act 99-906); however, the Commission may revise the tariff's rate design and cost a llocation in subsequent proceedings under paragraph (3) of this subsection (d). I f the energy efficiency formula rate is terminated, the th en current rates shall remain in effect until such t ime as the energy efficiency costs are incorporated into new rates that are set under this subsection (d) or Ar ticle IX of this Act, subject to retroactiv e rate adjustment, with interest, to reconcile rates charg ed with actual costs.

(3) The provisions of this paragraph (3) shall only apply t o an electric utility that has elected to file an energy ef ficiency formula rate under paragraph (2) of this subsectio n (d). Subsequent to the Commission's issuance of an o rder approving the utility's energy efficiency formula r ate structure and protocols, and initial rates under pa ragraph (2) of this subsection (d), the utility shall f ile, on or before June 1 of each year, with the Chief C lerk of the Commission its updated cost inputs to the e nergy efficiency formula rate for the applicable rate yea r and the corresponding new charges, as well as the inf ormation described in paragraph (9) of subsection (g) of this Section. Each such filing sha ll conform to the following requirements and include the fol lowing information: (A) The inputs to the energy efficiency formula rate for the applicable rate year shall be based on the projected costs to be incurred by the utility d uring the rate year under the utility's multi-year plan approved under subsections (f) and (g) of this Section, including, but not limited to, projected capital investment costs and projecte d regulatory asset balances with correspondingly updat ed depreciation and amortization reserves and expe nse. The filing shall also include a reconciliation of the energy efficiency revenue requirement th at was in effect for the prior rate year (as set by the cost inputs for the prior rate year) with th e actual revenue requirement for the prior rate year (determined using a year-end rate base) that use s amounts reflected in the applicable FERC Form 1 that reports the actual costs for the prior rate year. Any over-c ollection or under-collection indicated by such r econciliation shall be reflected as a credit aga inst, or recovered as an additional charge to, respecti vely, with interest calculated at a rate equal to th e utility's weighted average cost of capital approved by the Commission for the prior rate year, the charges for th e applicable rate year. Such over-collection or under-collection shall be adjusted to remove any deferred taxes related to the reconciliation, for purposes of calculating interest at an annual rate of return equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, including a revenue conversion factor calcu lated to recover or refund all additional income taxes that may be payable or receivable as a result of t hat return. Each reconciliation shall be certified by t he participating utility in the same manner t hat FERC Form 1 is certified. The filing shall also in clude the charge or credit, if any, resulting from the ca lculation required by subparagraph (E) of paragraph (2) of thi s subsection (d). Notwithstanding any other provision of l aw to the contrary, the intent of the reconciliation is to ultimately reconcile both the revenue requiremen t reflected in rates for each calendar year, beginning with the calendar year in which the utility files its energy efficiency formula rate tariff under paragraph ( 2) of this subsection (d), with what the revenue requ irement determined using a year-end rate base for the applicable calendar year would have been had the actual cost information for the applicable calendar year been available at the filing date.

For purposes of this Section, "FERC F orm 1" means the Annual Report of Major Electric Uti lities, Licensees and Others that electric utilities are required to file with the Federal Energy R egulatory Commission under the Federal Power Act, Sectio ns 3, 4(a), 304 and 209, modified as necessary to b e consistent with 83 Ill. Adm. Code Part 415 as of May 1, 2011. Nothing in this Section is intended to allow costs that are not otherwise recoverable to be recoverable by virtue of inclusion in FERC Form 1. (B) The new charges shall take effect beginning on the first billing day of the following January billin g period and remain in effect through the last bill ing day of the next December billing period regar dless of whether the Commission enters upon a hearing under this paragraph (3). (C) The filing shall include releva nt and necessary data and documentation for the applicable rate year. Normalization adjustments shall not be required. Within 45 days after the utility files its annu al update of cost inputs to the energy efficiency formu la rate, the Commission shall with reasonable notice, ini tiate a proceeding concerning whether the projected cost s to be incurred by the utility and recovered duri ng the applicable rate year, and that are reflected in the in puts to the energy efficiency formula rate, are consistent with the utility's approved multi-year plan under subsections (f) and (g) of this Section and whether th e costs incurred by the utility during the prior rate year were prudent and reasonable. The Commission shall also hav e the authority to investigate the information and data described in paragraph (9) of subsection (g) of this Section, including the proposed adjustment t o the utility's return on equity component of it s weighted average cost of capital. During the course of the proceeding, each objection shall be stated with p articularity and evidence provided in support thereof, aft er which the utility shall have the opportunity to rebut the evidence. Discovery shall be allowed consistent with the Commission's Rules of Practice, which Rules of Practice shall be enforced by the Commission or the assi gned administrative law judge. The Commission shall apply the same evidentiary standards, including , but not limited to, those concerning the prudence and rea sonableness of the costs incurred by the utility, duri ng the proceeding as it would apply in a proceeding to revi ew a filing for a general increase in rates under Articl e IX of this Act. The Commission shall not, however, have the authority in a proceeding under this paragraph (3) t o consider or order any changes to the structure or protocols of the energy efficiency formula rate approve d under paragraph (2) of this subsection (d). In a proceedin g under this paragraph (3), the Commission shall enter it s order no later than the earlier of 195 days after the ut ility's filing of its annual update of cost inputs t o the energy efficiency formula rate or December 15. The u tility's proposed return on equity calculation, as de scribed in paragraphs (7) through (9) of subsection (g) of t his Section, shall be deemed the final, approved ca lculation on December 15 of the year in which it is filed unless the Commission enters an order on or before December 15, after notice and hearing, that modifies such calcula tion consistent with this Section. The Commission's determi nations of the prudence and reasonableness of the costs incurred, and determination of such return on equity cal culation, for the applicable calendar year shall be fi nal upon entry of the Commission's order and shall not be subject to reopening, reexamination, or collateral a ttack in any other Commission proceeding, case, docket, or der, rule, or regulation; however, nothing in this para graph (3) shall prohibit a party from petitioning th e Commission to rehear or appeal to the courts the or der under the provisions of this Act. (e) Beginni ng on June 1, 2017 (the effective date of Public Act 99- 906), a utility subject to the requirements of this Sect ion may elect to defer, as a regulatory asset, up to the full a mount of its expenditures incurred under this Section for each annual period, including, but not limited to, any exp enditures incurred above the funding level set by subsection (f) of this Section for a given year. The total expenditures de ferred as a regulatory asset in a given year shall be amorti zed and recovered over a period that is equal to the weighted a verage of the energy efficiency measure lives implemented for that year that are reflected in the regulatory asset. T he unamortized balance shall be recognized as of December 31 f or a given year. The utility shall also earn a return on the total of the unamortized balances of all of the energy efficien cy regulatory assets, less any deferred taxes related t o those unamortized balances, at an annual rate equal to the utility' s weighted average cost of capital that includes, based on a yea r-end capital structure, the utility's actual cost of de bt for the applicable calendar year and a cost of equity , which shall be determined as set forth in subparagraph (C) of paragraph (2) of subsection of this Section ca lculated as the sum of the (i) the average for the applicabl e calendar year of the monthly average yields of 30-y ear U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or suc cessor publication; and (ii) 580 basis points, i ncluding a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or r eceivable as a result of that return. Capital investment co sts shall be depreciated and recovered over their useful l ives consistent with generally accepted accounting princi ples. The weighted average cost of capital shall be appli ed to the capital investment cost balance, less any accumulat ed depreciation and accumulated deferred income taxes, as of December 31 for a given year. When an elec tric utility creates a regulatory asset under the provisions o f this Section, the costs are recovered over a period during which customers also receive a benefit which is in the pu blic interest. Accordingly, it is the intent of the General Ass embly that an electric utility that elects to create a regulato ry asset under the provisions of this Section shall recover all of the associated costs as set forth in this Section. After the Commission has approved the prudence and reasonable ness of the costs that comprise the regulatory asset, the elec tric utility shall be permitted to recover all such costs, and the value and recoverability through rates of the a ssociated regulatory asset shall not be limited, altered, i mpaired, or reduced. (f) Beginnin g in 2017, each electric utility shall file an energy efficiency plan with the Commission to meet the energy efficiency sta ndards for the next applicable multi-year period beginni ng January 1 of the year following the filing, according to th e schedule set forth in paragraphs (1) through (3) of this subs ection (f). If a utility does not file such a plan on or befor e the applicable filing deadline for the plan, it shall face a penalty of $100,000 per day u ntil the plan is filed. (1) No later than 30 days after June 1, 2017 (the effect ive date of Public Act 99-906), each electric utilit y shall file a 4-year energy efficiency plan commen cing on January 1, 2018 that is designed to achieve the cumulati ve persisting annual savings goals specified in paragra phs (1) through (4) of subsection (b-5) of this Section or in paragraphs (1) through (4) of subsection (b-15) of this Section, as applicable, through imple mentation of energy efficiency measures; however, the goals may be reduced if the utility's expenditures are limited pursuant to subsection (m) of this Section or, for a utility that serves less than 3,000,000 retail cu stomers, if each of the following conditions are me t: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate that achi evement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utili ty as determined by the independent evaluator for the most recent year for which savings have been evaluated preced ing the plan filing was less than the average annual amount of savings required to achieve the goals for the ap plicable 4-year plan period. Except as provided in subsection (m) of this Section, annual increases in cumul ative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative per sisting annual savings that is forecast to be cost-effectively achievable during the 4-year pl an period. The Commission shall review any proposed go al reduction as part of its review and approval of the utilit y's proposed plan. (2) No la ter than March 1, 2021, each electric utility shall file a 4-year energy efficiency plan commencing on Januar y 1, 2022 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (5) through (8) o f subsection (b-5) of this Section or in paragraphs (5) through (8) of subsection (b-15) of this Sectio n, as applicable, through implementation of energy effi ciency measures; however, the goals may be reduced if eith er (1) clear and convincing evidence demonstrate s, through independent analysis, that the expenditure limits in subsection (m) of this Section preclude full ach ievement of the goals or (2) each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonst rate by clear and convincing evidence and through ind ependent analysis that achievement of such goals is not c ost effective; and (B) the amount of energy savings achiev ed by the utility as determined by the independent evaluato r for the most recent year for which savings have been ev aluated preceding the plan filing was less than the average ann ual amount of savings required to achieve the goals f or the applicable 4-year plan period. If there is not clear an d convincing evidence that achieving the savings goals specified in paragraph (b-5) or (b-15) of this Secti on is possible both cost-effectively and wit hin the expenditure limits in subsection (m), such s avings goals shall not be reduced. Except as provided in subsection (m) of this Section, annual increases in cumul ative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative per sisting annual savings that is forecast to be cost-effectively achievable during the 4-year pl an period. The Commission shall review any proposed go al reduction as part of its review and approval of the utility's proposed p lan. (2.5) Pro visions of the multi-year plans for calendar years 2 026 through 2029 that relate to calendar year 2026 and that were filed by the electric utilities on February 28, 2025 shall remain in effect through calendar year 2026. Provisions of the plans for calendar years 2027 thro ugh 2029 shall be modified and resubmitted to the Commission by the electric utilities pursuant to paragraph (3) of this subsection (f). (3) No l ater than March 1, 2026 or the effective date of this amendatory Act of the 104th Ge neral Assembly, whichever is later 2025, each electric utility shall file a 3-year 4-year energy efficiency plan commencing on Ja nuary 1, 2027 2026 that is designed to achieve, through implementation of energy efficiency measures, lifetim e energy equal to the product of the incremental annual savin gs goals defined by paragraph (1) of subsection (b-16) and t he minimum average savings life defined by paragrap h (3) of subsection (b-16). The 3-year energ y efficiency plan of a utility that serves less than 3,0 00,000 retail customers but more than 500,000 retail cust omers in the State must also be designed to achieve lifeti me peak demand savings equal to the product of the incremental a nnual savings goals defined by paragraph (2) of subsection ( b-16) and the minimum average savings life defined b y paragraph (3) of subsection (b-16) through implemen tation of energy efficiency measures. The savings goals may be reduced if: (i) clear and convincing evidence and i ndependent analysis demonstrates that the expenditure limits in subsection (m) of this Section preclude full ac hievement of the goals, (ii) each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonst rate by clear and convincing evidence and through independe nt analysis that achievement of such goals is not cost-effective; and (B) the amount of energy savings achieved by the utility, as determined by the independent evaluator , for the most recent year for which savings have been ev aluated preceding the plan filing was less than the average annu al amount of savings required to achieve the goals f or the applicable multi-year plan period, or (iii) changes in federal law, programs, or tariffs have a significant and demonstrable impact on the cost of deli vering measures and programs. If there is not clear an d convincing evidence that achieving the savings goals speci fied in subsection (b-16) is possible both cost-effectively and within the expenditure limits in subsect ion (m), such savings goals shall not be reduced. Except as prov ided in subsection (m), annual savings goals during the a pplicable multi-year plan period shal l not be reduced to amounts that are less than the maxim um amount of annual savings that is forecasted to be cost-effectively achievable during the applicable multi- year plan period. The Commission shall review any proposed goal reduction as par t of its review and approval of the utility's proposed pl an. the cumulative persisting annual savin gs goals specified in paragraphs (9) through (12) of subsection (b-5) of this Section or in paragraphs (9) through (12) of subsection (b-15) of this Section, as appli cable, through implementation of energy efficiency m easures; however, the goals may be reduced if either (1) clear and convincing evidence demonstrates, through i ndependent analysis, that the expenditure limits in subse ction (m) of this Section preclude full achievemen t of the goals or (2) each of the following conditions are met: (A) the plan's analysis and forecasts of the util ity's ability to acquire energy savings demonstrate by clear and convincing evidence and through independent analysis that achievement of such goals is not cost effect ive; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluato r for the most recent year for which savings have been ev aluated preceding the plan filing was less than the average ann ual amount of savings required to achieve the goals f or the applicable 4-year plan period. If there is not clear and convincing evidence that achieving the savings goals specified in paragraphs (b-5) or (b-15) of this Secti on is possible both cost-effectively and wit hin the expenditure limits in subsection (m), such s avings goals shall not be reduced. Except as provided in subsection (m) of this Section, annual increases in cumul ative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative per sisting annual savings that is forecast to be cost-effectively achievable during the 4-year pl an period. The Commission shall review any proposed goal reduction a s part of its review and approval of the utility's propos ed plan. (4 ) No later than March 1, 2029, and every 4 years thereafte r, each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2030, and every 4 years ther eafter, respectively, that is designed to achieve the cumulative persisting annual savings goals established b y the Illinois Commerce Commission pursuant to direction of subsection s (b-5) and (b-15) of this Section, as applicable, through implementation of energy efficienc y measures, lifetime energy equal to the product of the incremental annual savings goals defined by paragraph (1) of subsection (b-16) and the minimum average savings life de scribed in paragraph (C) of subsection (b-16) of this Section. The 3-year energy efficiency plan of a utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State must also be designed to achieve lifetime peak demand savings equal to the product of the incremental a nnual savings goals defined by paragraph (2) of subsection ( b-16) and the minimum average savings life defined by paragraph (3) of subsection (b-16) through implementation of energy efficiency measures. However ; however , the goals may be reduced if: either (1) clear and con vincing evidence and independent analysis demonstrates that the expenditure limits in subsection (m ) of this Section preclude full achievement of the goals, or (2) each of the following conditions are met: (A) the plan's a nalysis and forecasts of the utility's ability to acquire e nergy savings demonstrate by clear and convincing evidence and th rough independent analysis that achievement of such goal s is not cost-effective; and (B) the amount of en ergy savings achieved by the utility as determined by the independent evaluator for the most recent year for wh ich savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable mult i-year 4-year plan period, or (3) changes in federal law, programs, or tariffs have a significant and demonstrable imp act on the cost of delivering measures and programs. If there is not clear and convincing evidence that achieving the savings goals specified in paragra ph (b-16) paragraphs (b-5) or (b-15) of this Section is possible both cost-effectively and within the expenditure lim its in subsection (m), such savings goals shall not be reduced. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual saving s goals during the applicable multi-year 4-year plan period shall not be reduced to am ounts that are less than the maximum amount of cumul ative persisting annual savings that is forecast to be cost-effectively achievable duri ng the applicable multi-year 4-year plan period. The Comm ission shall review any proposed go al reduction as part of its review and approval of the utility's proposed plan. Ea ch utility's plan shall set forth the utility's proposals to meet the energy efficiency standards identified in subsection (b-5), or (b-15), or (b-16), as applicable and as such sta ndards may have been modified under this subsection (f), ta king into account the unique circumstances of the utility's s ervice territory. For those plans commencing on January 1 , 2018, the Commission shall seek public comment on the util ity's plan and shall issue an order approving or disapproving ea ch plan no later than 105 days after June 1, 2017 (the effectiv e date of Public Act 99-906). For those plans commencin g after December 31, 2021, the Commission shall seek publi c comment on the utility's plan and shall issue an order app roving or disapproving each plan within 6 months after its su bmission. If the Commission disapproves a plan, the Commissio n shall, within 30 days, describe in detail the reasons for the disapproval and describe a path by which the utility may f ile a revised draft of the plan to address the Commission's c oncerns satisfactorily. If the utility does not refile with the Commission within 60 days, the utility shall be subject to penalties at a rate of $100,000 per day until the plan i s filed. This process shall continue, and penalties shall accrue, u ntil the utility has successfully filed a portfolio of energy efficiency and demand-response measures. Penalties shall be deposited into the Energy Ef ficiency Trust Fund. (g) In submitting proposed plans and funding levels under subsection (f) of this Section to meet the savings goals identified in subsection (b-5), or (b-15), or (b-16) of this Section, as applicabl e, the utility shall: (1 ) Demonstrate that its proposed energy efficiency measures will achieve the applicable requirements that are identified in subsection (b-5), or (b-15), or (b-16) of this Section, as modified by subsection (f) of this Section.

(2) (Blank). (2.5) Demonstrate consideration of program options for (A) adva ncing new building codes, appliance standards, and mun icipal regulations governing existing and new building efficiency improvements and (B) supporting efforts to improve compliance with new building codes, appliance standar ds and municipal regulations, as potentially cost-effective means of acquiring energy savings to c ount toward savings goals.

(3) Demonstrate that its overall portfolio of measures, not in cluding low-income programs described in subsection (c) of this Section, is cost-effective using th e total resource cost test or complies with paragraphs (1) thr ough (3) of subsection (f) of this Section and represents a diverse cross-section of opportunities f or customers of all rate classes, other than those custome rs described in subsection (l) of this Section, to participate in the programs. Individual measures need no t be cost effective.

(3.5) Demonstrate that the utility's plan integrates the delivery of energy efficiency programs with natural gas efficiency programs, programs promoting distributed so lar, programs promoting demand response and other effort s to address bill payment issues, including, but not limit ed to, LIHEAP and the Percentage of Income Payment Plan , to the extent such integration is practical and has the potential to enhance c ustomer engagement, minimize market confusion, or reduce administrative costs. (4) If the utility chooses, pre sent Present a third-party energy efficiency implementation program subject to the following requirements: (A) (blank); beginning with the year comme ncing January 1, 2019, electric utilities that serve mor e than 3,000,000 retail customers in the State shall f und third-party energy efficiency programs i n an amount that is no less than $25,000,000 p er year, and electric utilities that serve less than 3,000, 000 retail customers but more than 500,000 retail cust omers in the State shall fund third-party energy efficien cy programs in an amount that is no less than $8,350,000 per year; (B) during 2018, the utility shall conduct a solicitation process for purposes of requesting p roposals from third-party vendors for those thir d-party energy efficiency programs to be offered during one or more of the years commencing January 1, 20 19, January 1, 2020, and January 1, 2021; for those multi-year plans commencing on January 1, 2022 and January 1, 2026, the utility s hall conduct a solicitation process during 2021 and 2025, respecti vely, for purposes of requesting proposals from third -party vendors for those third-party energy ef ficiency programs to be offered during one or more yea rs of the respective multi-year plan period; for each solicitation process, the utility shall identify t he sector, technology, or geographical area for which it is seeking requests for proposals; the solicitation process must be either for programs that fill gaps i n the utility's program portfolio and for programs th at target low-income customers, business secto rs, building types, geographies, or other specific parts of its customer base with initiatives that would be more effective at reaching these custo mer segments than the utilities' programs filed in it s energy efficiency plans; (C) the utility shall propose the bidd er qualifications, performance measurement process, and contract structure, which must include a perform ance payment mechanism and general terms and conditions; the proposed qual ifications, process, and structure shall be subject to Commiss ion approval; and (D) the utility shall retain an independent t hird party to score the proposals received thro ugh the solicitation process described in this paragraph ( 4), rank them according to their cost per lifetime kilowa tt-hours saved, and assemble the portfolio of third-party programs. The electric utility shall recover all costs associate d with Commission-approved, third-party administered programs regardless of the success of th ose programs. (4.5) Imp lement cost-effective demand-response mea sures to reduce peak demand by 0.1% over the prior year for elig ible retail customers, as defined in Section 16-111.5 o f this Act, and for customers that elect hourly service fr om the utility pursuant to Section 16-107 of this Act , provided those customers have not been declared competitive. This requirement continues until Decembe r 31, 2026. (5) Incl ude a proposed or revised cost-recovery tariff mechanism, as provided for under subsection (d) of this Section, to fund the proposed energy efficiency and demand-response measures and to ensure the recovery of the prudently and reasonably incurred costs of Commission-approved programs. (6) Prov ide for an annual independent evaluation of the perform ance of the cost-effectiveness of the utility's portfolio o f measures, as well as a full review of the multi-year plan results of the broader net program impacts an d, to the extent practical, for adjustment of the measure s on a going-forward basis as a result of the evaluations. The resources dedica ted to evaluation shall not exceed 3% of portfolio res ources in any given year. (7) For e lectric utilities that serve more than 3,000,000 retail customers in the State: (A) Through December 31, 2026

2025, provide for an adjustment to the return on equity component of the utility's we ighted average cost of capital calculated under subsection (d) of this Section: (i) If the independent evaluator determines that the utility achieved a cumulative p ersisting annual savings that is less than the applicable annual incremental goal, then th e return on equity component shall be reduced b y a maximum of 200 basis points in the event that the utility achieved no more than 75% of such goal . If the utility achieved more than 75% of the appl icable annual incremental goal but less than 1 00% of such goal, then the return on equity component shall be reduced by 8 basis points for each percent by which the utility failed to a chieve the goal. (ii) If the independent evaluator determines that the utility achieved a cumulative p ersisting annual savings that is more than the ap plicable annual incremental goal, then the return on equity component shall be increase d by a maximum of 200 basis points in the event th at the utility achieved at least 125% of such goal. If the utility achieved more than 100% of the appl icable annual incremental goal but less than 125 % of such goal, then the return on equity componen t shall be increased by 8 basis points for each percent by which the utility achieved above the goal. If the applicable annual incremental goal wa s reduced under paragraph (1) or (2) of subsection (f) of this Section, then the follo wing adjustments shall be made to the calculations described in this item (ii): (aa) the calcu lation for determining achievement that is a t least 125% of the applicable annual incremental goal s hall use the unreduced applicable annual incremental goal to set the value; and (bb) the calculatio n for determining achievement that is less th an 125% but more than 100% of the applicabl e annual incremental goal shall use the re duced applicable annual incremental goal to set the value for 100% achievement of th e goal and shall use the unreduced goal to s et the value for 125% achievement. The 8 basis point value shall also be modified, as neces sary, so that the 200 basis points are evenly a pportioned among each percentage point value between 100% and 125% achievement. (B) (Blank). For the period January 1, 2026 thro ugh December 31, 2029 and in all subsequent 4-year periods, provide for an adjustment to the ret urn on equity component of the utility's weighted averag e cost of capital calculated under subsection (d) of this Section: (i) If the independent evaluator determines that the utility achieved a cumulative p ersisting annual savings that is less than the applicable annual incremental goal, then th e return on equity component shall be reduced b y a maximum of 200 basis points in the event that the utility achieved no more than 66% of such goal . If the utility achieved more than 66% of the appl icable annual incremental goal but less than 1 00% of such goal, then the return on equity component shall be reduced by 6 basis points for each percent by which the utility failed to achieve the goal. (ii) If the independent evaluator determines that the utility achieved a cumulative p ersisting annual savings that is more than the ap plicable annual incremental goal, then the return on equity component shall be increase d by a maximum of 200 basis points in the event th at the utility achieved at least 134% of such goal. If the utility achieved more than 100% of the appl icable annual incremental goal but less than 134 % of such goal, then the return on equity componen t shall be increased by 6 basis points for each percent by which the utility achieved above t he goal. If the applicable annual incremental goa l was reduced under paragraph (3) of subsection (f) of this Section, then the following adjustme nts shall be made to the calculations described in this item (ii): (aa) the calcu lation for determining achievement that is a t least 134% of the applicable annual incremental goal shall use the unreduced applicable annual incremental goal to set the value; and (bb) the calculatio n for determining achievement that is less th an 134% but more than 100% of the applicabl e annual incremental goal shall use the re duced applicable annual incremental goal to set the value for 100% achievement of th e goal and shall use the unreduced goal to s et the value for 134% achievement. The 6 basis point value shall also be modified, as neces sary, so that the 200 basis points are evenly apportioned amo ng each percentage point value between 100% and 134% achievement. (C) (Blank).

Notwithstanding the provisions o f subparagraphs (A) and (B) of this paragraph (7) , if the applicable annual incremental goal for an ele ctric utility is ever less than 0.6% of deemed average weather normalized sales of electric power a nd energy during calendar years 2014, 2015, and 2016, an adjustment to the return on equity component of the utility's weighted average cost of capital calcula ted under subsection (d) of this Section shall be made as follows: (i) If the independent evaluator d etermines that the utility achieved a cumulativ e persisting annual savings that is less than would have been achieved had the applicable ann ual incremental goal been achieved, then the retur n on equity component shall be reduced by a maximum of 200 basis points if the utility achiev ed no more than 75% of its applicable annual total savings requirement as defined in paragraph (7.5) of this subsection. If the utility achieved more tha n 75% of the applicable annual total savings requirement but less than 100% of such goal, then the return on equity component shall be reduced by 8 basis points for each percent by which the utility failed to achieve the goal. (ii) If the independent evaluator d etermines that the utility achieved a cumulativ e persisting annual savings that is more than would have been achieved had the applicable annua l incremental goal been achieved, then the return o n equity component shall be increased b y a maximum of 200 basis points if the utility achieved at least 125% of its applicable ann ual total savings requirement. If the utility achi eved more than 100% of the applicable annual total savings requirement but less than 125% of such goal, then the return on equity component shall be increased by 8 basis points for each percent b y which the utility achieved above the applicable annual total savings requirement. If the applicabl e annual incremental goal was reduced under paragraph (1) or (2) of subsection (f) of this Section, then the following adjustme nts shall be made to the calculations described in this item (ii): (aa) the calc ulation for determining achievement that i s at least 125% of the applicable annual total savings requirement shall use the unreduced applicable annual incremental goal to set the value; and (bb) the calc ulation for determining achievement that i s less than 125% but more than 100% of the app licable annual total savings requirement sh all use the reduced applicable annual incremen tal goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 8 basis point value shall also be modified, as n ecessary, so that the 200 basis points are evenly apportioned amo ng each percentage point value between 100% and 125 % achievement.

(7.5) For purposes of this Section, the term "applic able annual incremental goal" means the difference betwee n the cumulative persisting annual savings goal for the calendar year that is the subject of the independent evalua tor's determination and the cumulative persisting annual saving s goal for the immediately preceding calendar year, as such go als are defined in subsections (b-5) and (b-15) of this Section and as these goals may have been modified as provided for under subsection (b-20) and paragraphs (1) and (2) throu gh (3) of subsection (f) of this Section. Unde r subsections (b), (b-5), (b-10), and (b-15) of this Section, a utility must first replace ene rgy savings from measures that have expired before a ny progress towards achievement of its applicable annual i ncremental goal may be counted. Savings may expire bec ause measures installed in previous years have reached the end of their lives, because measures installed in pr evious years are producing lower savings in the curren t year than in the previous year, or for other reasons i dentified by independent evaluators. Notwithstanding anyth ing else set forth in this Section, the difference b etween the actual annual incremental savings achieved in any given year, including the replacement of ener gy savings that have expired, and the applicable annual in cremental goal shall not affect adjustments to the return on equity for subsequent calendar years unde r this subsection (g). In this Section, "applicable annual total savings requirem ent" means the total amount of new annual savings that th e utility must achieve in any given year to achieve the ap plicable annual incremental goal. This is equal to the ap plicable annual incremental goal plus the total new annual savings that are r equired to replace savings that expired in or at the e nd of the previous year. (8) For electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State: (A) Through December 31, 2 026 2025, the applicable annual incremental goal shall be compare d to the annual incremental savings as determined by the indep endent evaluator. (i) The return on equity com ponent shall be reduced by 8 basis points for each percent by whi ch the utility did not achieve 84.4% of the applicable annual i ncremental goal. (ii) The return on equity componen t shall be increased by 8 basis points for each percen t by which the utility exceeded 100% of the applicable annual inc remental goal. (iii) The return on equity component shall not be increased or decreas ed if the annual incremental savings as determine d by the independent evaluator is greater than 84.4% of the applicable annual incremental goal and less than 100% of the applicable annual in cremental goal. (iv) The return on equi ty component shall not be increased or decrease d by an amount greater than 200 basis points pursuant to this subparagraph (A). (B) (Blank). For the period of January 1, 2026 throug h December 31, 2029 and in all subsequent 4-year periods, the applicable annual incremental goal shall be compared to the annu al incremental savings as determined by the independent evaluator. (i) The return on equity co mponent shall be reduced by 6 basis points for each percent by which the utili ty did not achieve 100% of the applicable annual incremental goal. (ii) The return on equity componen t shall be increased by 6 basis points for each percent by which th e utility exceeded 100% of the applicable annual incremental goal. (iii) The return on equi ty component shall not be increased or decreased by an amoun t greater than 200 basis points pursuant to this subparagraph (B).

(C) (Bl ank). Notwithstanding provisions in subparagraphs (A) and (B) of paragraph (7) of this subsection, if the applicable annual incrementa l goal for an electric utility is ever less than 0.6% of deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015 and 2016, an adjustment to the return on equity compo nent of the utility's weighted average cost of capital calcula ted under subsection (d) of this Section shall be made as follows: (i) The return on equity co mponent shall be reduced by 8 basis points for each percent by which the utility did no t achieve 100% of the applicable annual total savings requirement. (ii) The return on equity componen t shall be increased by 8 basis points for each percent by which the utility exceeded 100% of the applicable annual total savings requirement. (iii) The return on equi ty component shall not be increased or decreased by an amount greater than 200 basis points pursuant to this subparagraph (C). (D) (Blank). If the applicable annual incremental goal was reduced under paragraph (1), (2), (3) , or (4) of subsection (f) of this Section, then the following adjustments shall be made to the calculations d escribed in subparagraphs (A), (B), and (C) of this paragraph (8):

(i) The calculation fo r determining achievement that is at least 1 25% or 134%, as applicable, of the applica ble annual incremental goal or the applicable an nual total savings requirement, as applicable, shall use the unreduced applicable annual incremental goal to set the value. (ii) For the period through Dec ember 31, 2025, the calculation for determ ining achievement that is less than 125% but mor e than 100% of the applicable annual incremen tal goal or the applicable annual total savings re quirement, as applicable, shall use the re duced applicable annual incremental goal to set the value for 100% achievement of the goal a nd shall use the unreduced goal to set the val ue for 125% achievement. The 8 basis poin t value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned am ong each percentage point value between 100% and 125% achievement.

(iii) For the period of Januar y 1, 2026 through December 31, 2029 and all sub sequent 4-year periods, the calculation for determining achievement that is less than 125% o r 134%, as applicable, but more than 100% of the applicable annual incremental goal or the applicab le annual total savings requirement, as applicable , shall use the reduced applicable annual incremen tal goal to set the value for 100% achievement of the goa l and shall use the unreduced goal to set the value fo r 125% achievement. The 6 basis-point va lue or 8 basis-point value, as appl icable, shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% or between 100% and 134% achievement, as applicable. (8. 5) Beginning January 1, 2027, a utility that serv es greater than 500,000 retail customers in the State shall have the utility's return on equity modified for performance on t he utility's energy savings and peak demand savings goals as follows: (A) The return on equity for a utility that serves m ore than 3,000,000 retail customers in the State may be adjusted up or down by a maximum of 200 basis p oints for its performance relative to its incre mental annual energy savings goal. The return on equ ity for a utility that serves less than 3,000,000 ret ail customers but more than 500,000 retail customers in the State may be adjusted up or down by a maximum of 100 basis points for its performance relative to its incremental annual energy savings goal and a maxim um of 100 basis points for its performance re lative to its incremental annual coincident peak demand savings goal. (B) A utility's performance on its savings goals shall be established by comparing the actual lifetime energy, and coincident peak demand savings i f a utility serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State , achieved from efficiency measures installed in a g iven year to the product of the incremental annual goals established in paragraphs (1) and (2) of subsection (b -16) and the minimum average savings lives established in paragraph (3) of subsection (b-1 6), as modified, if applicable, by the Commissio n under paragraph (4) of subsection (f) of this Se ction. For the purposes of this paragraph (8.5) , "lifetime savings" means the total incremental savi ngs that installed efficiency measures are projected t o produce, relative to what would have occurred a bsent to the utility's efficiency programs, over the u seful lives of the measures. Performance on the ener gy savings goal, and coincident peak demand savings i f a utility serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State , shall be assessed separately, such that it is possibl e to earn penalties on both, earn bonuses on both, or earn a bonus for performance on one goal and a penalty on the other. (C) No bonus shall be earned if a utility does no t achieve greater than 100% of an approved goal. The maximum bonus for a goal shall be earned if the util ity achieves 125% of the unmodified goal. For a utili ty that serves less than 3,000,000 retail custom ers but more than 500,000 retail customers in the S tate, the bonus earned for achieving more than 100% of an approved goal but less than 125% of the unmodifi ed goal shall be linearly interpolated. For a ut ility with more than 3,000,000 retail customers, the maximum bonus for a goal shall be earned if the util ity achieves 125% of the unmodified goal. For a uti lity with more than 3,000,000 retail customers, the bonu s earned for achieving more than 100% of an approved goal but less than 125% of the unmodified goal shall be linearly interpolate d.

(D) For utilities with greater than 3 ,000,000 retail customers, the return on equity shall b e unmodified due to performance on an individual goa l only if the utility achieves exactly 100% of the goal . For utilities with more than 500,000 but fewer tha n 3,000,000 retail customers, the return on equit y shall be unmodified for achieving between 85% and 100% of the goal. (E) Penalties may be earned for falling sh ort of goals, with the magnitude of any penalty being a funct ion of both the size of the utility and whether goals established in subsection (b-16) are modified by the Commissi on under paragraph (4) of subsection (f) of this Section, as foll ows:

(i) If the savings goals sp ecified in subsection (b-16) of this Section are unmodified, a utility with more than 3,000,00 0 retail customers shall earn the maximum penal ty allocated to a goal for achieving 75% or l ess of the goal. The penalty for achieving greater th an 75% but less than 100% of the goal shall be linearly interpolat ed. (ii) If the savings goals specifie d in subsection (b-16) of this Section are u nmodified, a utility with more than 500,000 but few er than 3,000,000 retail customers shall earn the m aximum penalty allocated to a goal for achieving at least 33.3 percentage points less than the bott om end of the deadband specified in subparagraph (D) of this paragraph (8.5). The penalty for ach ieving less than the bottom end of the deadband and greater than 33.3 percentage points les s than the bottom end of the deadband shall be linearly interpolated.

(iii) If either the energy or peak de mand savings goals specified in subsection (b-16) are reduced under paragraph (3) or (4) of sub section (f) of this Section, the maximum penalty a llocated to a goal shall be earned if the utilit y achieves 80% or less of the modified goal. The penalty for achieving more than 80% b ut less than 100% of a modified goal shall be linearly inte rpolated. ( 9) The utility shall submit the energy savings data to the independent evaluator no later than 30 days after the close o f the plan year. The independent evaluator shall determine the cumu lative persisting annual savings and annual increm ental savings for a given plan year, as well as a n estimate of job impacts and other macroeconomic impacts of the efficiency programs for that year, no later than 120 days after the close of the plan year. The utility shall s ubmit an informational filing to the Commission no later than 160 days after the close of the plan year tha t attaches the independent evaluator's final report ide ntifying the cumulative persisting annual savings for the year and calculates, under paragraph (7) or (8) of this subsection (g), as applicable, any resulting chang e to the utility's return on equity component of the weighted average cost of capital applicable to the next pl an year beginning with the January monthly billing period and extending through the December monthly billing period. However, if the utility recovers the costs incurr ed under this Section under paragraphs (2) and (3) of sub section (d) of this Section, then the utility shall not be required to submit such informational filing, and shal l instead submit the information that would otherwise be i ncluded in the informational filing as part of its filing under par agraph (3) of such subsection (d) that is due on or before Ju ne 1 of each year. For those utilities that must submit the informati onal filing, the Commission may, on its own motion or by petition, initiate an investigation of such filing, pro vided, however, that the utility's proposed return on equity calculation shall be deemed the final, approved ca lculation on December 15 of the year in which it is filed unless the Commission enters an order on or before December 15, after n otice and hearing, that modifies such calculation consis tent with this Section.

The adjustments to the return on equity component described in paragraphs (7) and (8) of this subsection (g) shall be applied as described in such paragraphs through a separate tariff mechanism, whic h shall be filed by the utility under subsections (f) and (g ) of this Section. (9.5) The utility must demonstrate how it will ensu re that program implementation contractors and energy ef ficiency installation vendors will promote workforce eq uity and quality jobs. For all construction, installation, or other re lated services procured under this Section, an electric utility must: (A) award a bid preference of 2% to a contractor if the contractor certifies under oath that the contractor's primar y place of business is located within the utility's service area; and (B) award a bid preference of 2% to a contractor if the contractor certifies under oath that at least 85% of the workforce to be utilized for such construction, installat ion, or other related services reside in the utility's servic e area. (9.6) Utilities shall collect data necessary to ensure compliance with paragraph (9.5) no less than quarterly and shall communicate progress toward compliance with p aragraph (9.5) to program implementation contractors an d energy efficiency installation vendors no less than quar terly. Utilities shall work with relevant vendors, provi ding education, training, and other resources needed t o ensure compliance and, where necessary, adjusting or terminating work with vendors that canno t assist with compliance. (10) Utilities required to implement efficiency programs under subsections (b -5), and (b-10), and (b-16) shall report annually to the Illinois Commerce Commission and the General Assembly on how hiring, contracting, job training, and other practices related to its energy ef ficiency programs enhance the diversity of vendors worki ng on such programs. These reports must include data on vendor and employee diversity, including data on the implementat ion of paragraphs (9.5) and (9.6) and the proportion of total program dollars awarded to firms that me et the criteria of subparagraphs (A) and (B) of paragrap h (9.5). If the utility is not meeting the re quirements of paragraphs (9.5) and (9.6), the utility sha ll submit a plan to adjust their activities s o that they meet the requirements of paragrap hs (9.5) and (9.6) within the following year. (h) N o more than 4% of energy efficiency and demand-response p rogram revenue may be allocated for research, development, or pilot deployment of new equipment or measures. Electri c utilities shall work with interested stakeholders to formu late a plan for how these funds should be spent, incorporate statewi de approaches for these allocations, and file a 4-yea r plan that demonstrates that collaboration. If a utility files a request for modified annual energy savings goals with the Commission, the n a utility shall forgo spending portfolio dollars on resea rch and development proposals. (i) Whe n practicable, electric utilities shall incorporate advanced metering infrastructure data into the planning, implementation , and evaluation of energy efficiency measures an d programs, subject to the data privacy and confidentialit y protections of applicable law. (j) The indepen dent evaluator shall follow the guidelines and use the savings set forth in Commission-approved energy efficiency policy manuals and technical reference manuals, as each may be updated from time to time. Until such time as measure life values for energy efficiency measures implemented for low-income house holds under subsection (c) of this Section are incorporated into s uch Commission-approved manuals, the low-i ncome measures shall have the same measure life values that are established for sa me measures implemented in households that are not low-income households. (k) N otwithstanding any provision of law to the contrary, an elect ric utility subject to the requirements of this Section may file a tariff cancelling an automatic adjustment clause tariff in ef fect under this Section or Section 8-103, which shall t ake effect no later than one business day after the date such tariff is filed. Thereafter, the utility shall be author ized to defer and recover its expenditures incurred under thi s Section through a new tariff authorized under subsection (d) of this Section or in the utility's next rate case under Artic le IX or Section 16-108.5 of this Act, with interest at an annual rate equal to the utility's weighted average cost of capital as approved by the Commission in such cas e. If the utility elects to file a new tariff under subsection ( d) of this Section, the utility may file the tariff within 10 days aft er June 1, 2017 (the effective date of Public Act 99- 906), and the cost inputs to such tariff shall be based on the projected costs to be incurred by the utility during the calen dar year in which the new tariff is filed and that were no t recovered under the tariff that was cancelled as provide d for in this subsection. Such costs shall include those incurred or to be incurred by the utility under its multi-year p lan approved under subsections (f) and (g) of this Section, in cluding, but not limited to, projected capital investment costs and projected regulatory asset balances with correspondingly updated depreciation and amortization reserves and expense. The Commission shall, after notice and hearing, approve, or approve with modification, such tariff and cost in puts no later than 75 days after the utility filed the tariff, provided that such approval, or approval with modifi cation, shall be consistent with the provisions of this Sect ion to the extent they do not conflict with this subsection ( k). The tariff approved by the Commission shall take effect n o later than 5 days after the Commission enters its or der approving the tariff. No la ter than 60 days after the effective date of the tari ff cancelling the utility's automatic adjustment clause tariff, the utility shall file a reconciliation that reconciles the moneys collected under its automatic adjustment clause tari ff with the costs incurred during the period beginning June 1, 2016 and ending on the date that the electric utility's automatic adj ustment clause tariff was cancelled. In the event the reconciliation reflects an under-collection , the utility shall recover the costs as specified in this subsect ion (k). If the reconciliation reflects an over-collection, the utility shall apply the a mount of such over-collection as a one-time credit to retail customers' bills. (l) For the c alendar years covered by a multi-year plan commencing after December 31, 2017, subsections (a) through (j) of this Sec tion do not apply to eligible large private energy customers that have c hosen to opt out of multi-year plans consistent wit h this subsection (1). ( 1) For purposes of this subsection (l), "eligible large private energy customer" means any retail customers, ex cept for federal, State, municipal, and other public cu stomers, of an electric utility that serves more than 3 ,000,000 retail customers, except for federal, State, muni cipal and other public customers, in the State and whose t otal highest 30 minute demand was more than 10,000 kilowat ts, or any retail customers of an electric utility that ser ves less than 3,000,000 retail customers but more than 50 0,000 retail customers in the State and whose total highest 15 minute demand was more than 10,000 kilowatts. For purpo ses of this subsection (l), "retail customer" has the meani ng set forth in Section 16-102 of this Act. However, for a business entity with multiple sites located in the State, where at least one of those sites qualifies as a n eligible large private energy customer, then any o f that business entity's sites, properly identifie d on a form for notice, shall be considered eligible large private energy customers for the purposes of this s ubsection (l). A determination of whether this subsection is applicable to a customer shall be made for each multi-year plan beginning after December 31, 2017. The crit eria for determining whether this subsection (l) is ap plicable to a retail customer shall be based on the 12 consecutive billing p eriods prior to the start of the first year of each suc h multi-year plan.

(2) Within 45 days after September 15, 2021 (the effecti ve date of Public Act 102-662), the Commission s hall prescribe the form for notice required for opting out of energy efficiency programs. The notice must be submitte d to the retail electric utility 12 months before the ne xt energy efficiency planning cycle. However, within 120 days after the Commission's initial issuance of the form for notice, eligible large private energy customers may submit a form for notice to an electric utility. The form for notice f or opting out of energy efficiency programs shall include all of the following: (A) a statement indicating that the customer has el ected to opt out; (B) the account numbers for the customer accounts to which t he opt out shall apply; (C) the mailing a ddress associated with the customer accounts identified under s ubparagraph (B); (D) an American Society of Heating, Refrigerati ng, and Air-Conditioning Engineers (ASHRAE) level 2 or high er audit report conducted by an independent thi rd-party expert identifying cost-effective energy efficiency project opportunities that could be inv ested in over the next 10 years. A retail customer with specialize d processes may utilize a self-audit process in lie u of the ASHRAE audit; (E) a description of the customer's plans to reallocate the funds toward internal energy effic iency efforts identified in the subparagraph (D) repo rt, including, but not limited to: (i) strategic energ y management or other programs, including descr iptions of targeted buildings, equipment and operati ons; (ii) eligible energy efficiency measures; and (ii i) expected energy savings, itemized by technology. If the subparagraph (D) audit report identifies t hat the customer currently utilizes the best available energy efficient technology, equipment, programs, a nd operations, the customer may provide a statement th at more efficient technology, equipment, programs, and operations a re not reasonably available as a means of satisfying this subp aragraph (E); and (F) the effective date of the opt out, which will be the next January 1 following notice of the opt out.

(3) Upon receipt of a properly and timely noticed request for opt out submitted by an eligible large private ene rgy customer, the retail electric utility shall grant the request, file the request with the Commission and, beginni ng January 1 of the following year, the opted out customer shall no longer be assessed the costs of the plan and shall be prohibited from participating in that 4-year plan c ycle to give the retail utility the certainty to desig n program plan proposals. (4) Upon a customer's election to opt out u nder paragraphs (1) and (2) of this subsection (l) and comm encing on the effective date of said opt out, the accoun t properly identified in the customer's notice under para graph (2) shall not be subject to any cost recovery and sha ll not be eligible to participate in, or directly bene fit from, compliance with energy efficienc y cumulative persisting savings requirements under subsecti ons (a) through (j). (5) A utility' s cumulative persisting annual savings targets will exc lude any opted out load. (6) The request to opt out is only valid for the re quested plan cycle. An eligible large private energy cus tomer must also request to opt out for future energy plan cy cles, otherwise the customer will be included in the futu re energy plan cycle. (m) Notwit hstanding the requirements of this Section, as part of a proceeding t o approve a multi-year plan under subsections (f) and ( g) of this Section if the multi-year plan has been de signed to maximize savings, but does not meet the cost cap l imitations of this Section, the Commission shall reduce t he amount of energy efficiency measures implemented for an y single year, and whose costs are recovered under subsection (d ) of this Section, by an amount necessary to limit the estimated average net increase due to the cost of the measu res to no more than (1) 3.5% for each of the 4 y ears beginning January 1, 2018, (2) (blank), (3) 4% for each of the 4 years beginning January 1, 202 2, (3.5) 4.25% for 2026, (4) 4.25%

for electric utilities that serve more than 3,000,000 retail customers in the State, and 4.21% for 2 027, 5.25% for 2028, and 6.06% for 2029 for electric utilities with less than 3,000,000 retail custo mers but more than 500,000 retail customers in the State, for the 3 4 years beginning January 1, 2027 2026 , and (5) the percentage specified in paragraph (4) applicable to 2029 4.25% plus an inc rease sufficient to account for the rate of inflation between January 1, 2027 2026 and January 1 of the first year of each subsequent 4-year plan cycle, of the average amount paid per kilowatthour by residential eligible retail customers during calendar year 2015 for plans in effect through 2026 and during calendar year 2023 for plans commencing in 2027 and thereafter. An electric utility may plan to spend up to 10% more in any year during an applicable multi-year plan perio d, including any transition period authorized under para graph (2.5) of subsection (f), to cost-effectively achiev e additional savings so long as the average over the applicable mul ti-year plan period, which shall include any tra nsition period, does not exceed the percentages def ined in items (1) through (5). To determine the total amount that may be spent by an electric utility in any single year, t he applicable percentage of the average amount paid per kilow atthour shall be multiplied by the total amount of energy delivered by s uch electric utility in the calendar year 2015 for plans in effect through 2026 and during calendar year 2023 for plans commencing in 2027 and thereafter, adjusted to reflect the proportion of the utility's load attributable to customers that have opted out of subsections (a) through (j ) of this Section under subsection (l) of this Section. F or purposes of this subsection (m), the amount paid p er kilowatthour includes, without limitation, estimated amounts pa id for supply, transmission, distribution, surcharges, and ad d-on taxes. For purposes of this Section, "eligible retai l customers" shall have the meaning set forth in Section 16-111.5 of this Act. Once the Commission has approved a plan under subsections (f) a nd (g) of this Section, no subsequent rate impact deter minations shall be made. (n ) A utility shall take advantage of the efficiencies ava ilable through existing Illinois Home Weatherization Assistan ce Program infrastructure and services, such as enrollment, mar keting, quality assurance and implementation, which can reduce the ne ed for similar services at a lower cost than utility-o nly programs, subject to capacity constraints at community a ction agencies, for both single-family and multifa mily weatherization services, to the extent Illinois Home Weat herization Assistance Program community action agencies provide multifamily services. A utility's plan shall demonstrate t hat in formulating annual weatherization budgets, it has soug ht input and coordination with community action agencies regard ing agencies' capacity to expand and maximize Illinois Home Weather ization Assistance Program delivery using the ratepayer dollars collected under this Section. (Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6- 30-23; 103-613, eff. 7-1-24.) (220 ILCS 5/8-4

06) (from Ch. 111 2/3, par. 8-406) Sec. 8-406. Certificate of public conveni ence and necessity. (a) N o public utility not owning any city or village franchise no r engaged in performing any public service or in furnish ing any product or commodity within this State as of July 1, 1921 and not possessing a certificate of public co nvenience and necessity from the Illinois Commerce Commission, th e State Public Utilities Commission, or the Public Util ities Commission, at the time Public Act 84-617 goes into effect (January 1, 1986), shall transact any busin ess in this State until it shall have obtained a certi ficate from the Commission that public convenience and necessi ty require the transaction of such business. A certificate of public convenience and necessity requiring the transa ction of public utility business in any area of this State sha ll include authorization to the public utility receiving the certificate of public convenience and necessity to construct such plant, equipment, property, or facility as is provided f or under the terms and conditions of its tariff and as is necessary to provide utility service and carry ou t the transaction of public utility business by the public utility in the designated area. (b) No pu blic utility shall begin the construction of any new plant, equipment, property, or facility which is not in substi tution of any existing plant, equipment, property, or facility, or any extension or alteration thereof or in addition th ereto, unless and until it shall have obtained from the Commis sion a certificate that public convenience and necessity re quire such construction. Whenever after a hearing the Commiss ion determines that any new construction or the transaction of any business by a public utility will promote the public c onvenience and is necessary thereto, it shall have the p ower to issue certificates of public convenience and necessity. The Commission shall determine that proposed constructi on will promote the public convenience and necessity only if the utility demonstrates: (1) that the proposed construction is neces sary to provide adequate, reliable, and efficient service to its customers and is the least-cost means of satisf ying the service needs of its customers or that the propo sed construction will promote the development of an effectively competitive electricity market that operates efficiently, is equitable to all customers, and is the least-cost least cost means of satisfying those objectives; (2) that the utility is capable of efficiently managing and supervisin g the construction process and has taken sufficient action t o ensure adequate and efficient construction and supervi sion thereof; and (3) that the utility is capable of f inancing the proposed constru ction without significant adverse financial consequences for the utility or its c ustomers. (b-5) As used in this sub section (b-5): "Qualifying direct current applicant" means an entity that seeks to pr ovide direct current bulk transmission service for the purpose of transporting electric energy i n interstate commerce. "Qualifying direct current project" means a high voltage direct current electric service line that crosses at least one Illinois b order, the Illinois portion of which is physically located with in the region of the Midcontinent Independent System Op erator, Inc., or its successor organization, and runs thr ough the counties of Pike, Scott, Greene, Macoupin, Mon tgomery, Christian, Shelby, Cumberland, and Clark, i s capable of transmitting electricity at voltages of 345 kilov olts or above, and may also include associated interconn ected alternating current interconnection facilities in this State that are part of the proposed project a nd reasonably necessary to connect the project with other portions of the grid. Notwithstanding any other provision of this Act, a quali fying direct current applicant that does not own, control, oper ate, or manage, within this State, any plant, equipment, or property used or to be used for the transmission of electricity at the time of its application or of the Commission 's order may file an application on or before December 31, 202 3 with the Commission pursuant to this Section or Section 8-406.1 for, and the Commission may grant, a certificate of p ublic convenience and necessity to construct, operate, and m aintain a qualifying direct current project. The qualifying direct current applicant may also include in the application reque sts for authority under Section 8-503. The Commission shall grant the application for a certificate of public convenien ce and necessity and requests for authority under Section 8-503 if it finds that the qualifying direct current applicant and the proposed qualifying direct current proje ct satisfy the requirements of this subsection and otherwise satisfy the criteria of this Section or Section 8-406.1 and t he criteria of Section 8-503, as applicable to the application and to the extent such criteria are not super seded by the provisions of this subsection. The Commissi on's order on the application for the certificate of public convenience and necessity shall also include the Commission's fi ndings and determinations on the request or requests for aut hority pursuant to Section 8-503. Prior to filing its applicati on under either this Section or Section 8-406.1, the q ualifying direct current applicant shall conduct 3 p ublic meetings in accordance with subsection (h) of this Sect ion. If the qualifying direct current applicant demonstrates in its application that the proposed qualifying direct current pr oject is designed to deliver electricity to a point or points on the electric transmission grid in either or both the PJM Interconnection, LLC or the Midcontinent In dependent System Operator, Inc., or their respective succe ssor organizations, the proposed qualifying direct current pro ject shall be deemed to be, and the Commission shall find it to be, for public use. If the qualifying direct current appl icant further demonstrates in its application that the propo sed transmission project has a capacity of 1,000 megawatts or larger and a voltage level of 345 kilovolts or greater, the pr oposed transmission project shall be deemed to satisfy, and th e Commission shall find that it satisfies, the criteria stated in i tem (1) of subsection (b) of this Section or in parag raph (1) of subsection (f) of Section 8-406.1, as appli cable to the application, without the taking of additional evid ence on these criteria. Prior to the transfer of functi onal control of any transmission assets to a regional transmiss ion organization, a qualifying direct current applicant shall request Commission approval to join a regional transmission organization i n an application filed pursuant to this subsection (b-5) or separately pursuant to Section 7-102 of this Act. The Commission may grant permission to a qualifyin g direct current applicant to join a regional transmission organization if it finds that the membership, and associated transfer of functional control of transmission assets, benefits Illinois customers in light of the attendant costs and is o therwise in the public interest. Nothing in this subsect ion (b-5) requires a qualifying direct current applican t to join a regional transmission organization. Nothing in t his subsection (b-5) requires the owner or operator of a high voltage direct current transmission line that is not a qualifying direct current project to obtain a certificate of public c onvenience and necessity to the extent it is not otherwise required by this Section 8-406 or any other provision of this Act. ( c) As used in this subsection (c): "Decom missioning" has the meaning given to that term in subsectio n (a) of Section 8-508.1. "Nuclear power re actor" has the meaning given to that term in Section 8 of the Nucle ar Safety Law of 2004. After th e effective date of this amendatory Act of the 103rd General Assembly, no construction shall commence on any new nuclear power reactor with a nameplate capacity of more than 300 mega watts of electricity to be located within this State, a nd no certificate of public convenience and necessity or other authorization shall be issued therefor by the Commission, until the Illinois Emergency Management Agency and Office of Homelan d Security, in consultation with the Illinois Environmental Protection Agency and the Illinois Department of Natural Reso urces, finds that the United States Government, through it s authorized agency, has identified and approved a demons trable technology or means for the disposal of high level nuclear waste, or until such construction has been specifically approved by a statute enacted by the General Assembly. Beginning January 1, 2026, construction may commence on a new nuclear power reactor with a nameplate capacity of 300 megawatts of electricity or less within this State if the entity constructi ng the new nuclear power reactor has obtained all permits, licenses, permissions, or approvals governing the construction, operation, and funding of decommissioning of such nuclear pow er reactors required by: (1) this Act; (2) any rules adopted by the Illinois Emergency Management Agency and Office o f Homeland Security under the authority of this Act; ( 3) any applicable federal statutes, including, but not limited to, the Atomic Energy Act of 1954, the Energy Reorganization Ac t of 1974, the Low-Level Radioactive Waste Policy Amendm ents Act of 1985, and the Energy Policy Act of 1992; (4) any r egulations promulgated or enforced by the U.S. Nuclear Regulato ry Commission, including, but not limited to, those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of the Cod e of Federal Regulations, as from time to time amended; and (5 ) any other federal or State statute, rule, or regulation go verning the permitting, licensing, operation, or decommissio ning of such nuclear power reactors. None of the rules deve loped by the Illinois Emergency Management Agency and Office of Homeland Security or any other State agency, board, or commission pursuant to this Act shall be construed to super sede the authority of the U.S. Nuclear Regulatory Commission. T he changes made by this amendatory Act of the 103rd General A ssembly shall not apply to the uprate, renewal, or subsequent r enewal of any license for an existing nuclear power reactor that began op eration prior to the effective date of this amendatory Act of the 103rd General Assembly. None of the changes made in this amendatory Act of the 103rd General Assembly are intended to authorize the construct ion of nuclear power plants powered by nuclear power reactors that are not either: (1) small modular nuclear reactors; or (2) nuclear power reactors licensed by the U.S. Nuclear Regulatory Com mission to operate in this State prior to the effective date of this amendatory Act of the 103 rd General Assembly. (d) In making its determination under subsection (b) of this Section, the Commission shall attach primary weight to the cost or co st savings to the customers of the utility. The Commiss ion may consider any or all factors which will or may affect such cost or cost savings, includin g the public utility's engineering judgment regarding the m aterials used for construction. (e) The Commission may issue a temporary certificate which shall r emain in force not to exceed one year in cases of emergency, to assure maintenance of adequate service or to serve particular customers, without notice or hearing, pending the determina tion of an application for a certificate, and may by regu lation exempt from the requirements of this Section temporary acts or opera tions for which the issuance of a certificate will not be required in the public interest. A public utility shall not be required to obtain but may apply for and obtain a certificate of public convenience and necessity pursu ant to this Section with respect to any matter as to whic h it has received the authorization or order of the Com mission under the Electric Supplier Act, and any such authoriza tion or order granted a public utility by the Commission under t hat Act shall as between public utilities be deemed to be, and shall have except as provided in that Act the same force and eff ect as, a certificate of public convenience and necessit y issued pursuant to this Section. No el ectric cooperative shall be made or shall become a party to o r shall be entitled to be heard or to otherwise appear or par ticipate in any proceeding initiated under this Section for auth orization of power plant constru ction and as to matters as to which a remedy is availabl e under the Electric Supplier Act. (f) Su ch certificates may be altered or modified by the Commissi on, upon its own motion or upon application by the person or c orporation affected. Unless exercised within a period of 2 y ears from the grant thereof, authority conferred by a certificate of convenience and necessity issued by the C ommission shall be null and void. No certific ate of public convenience and necessity s hall be construed as granting a monopoly or an exclusive privilege, immunity or franchise. (g) A pu blic utility that undertakes any of the actions described in items (1 ) through (3) of this subsection (g) or that has obtained app roval pursuant to Section 8-406.1 of this Act shall not be required to comply with the requirements of this Section to t he extent such requirements otherwise would apply. For p urposes of this Section and Section 8-406.1 of this Act, "high voltage electric service line" means an electric line hav ing a design voltage of 100,000 or more. For purposes of this subsection (g), a public utility may do any of the following: (1) replace or upgrade any existing high vo ltage electric service line and related facilities, no twithstanding its length; (2) relocate any existing high voltage electric se rvice line and related facilities, notwithstanding its length, to accommodate co nstruction or expansion of a roadway or other transportation infrastructure; or (3) construct a high voltage electric service line and r elated facilities that is constructed solely to serve a single customer's premises or to provide a generator int erconnection to the public utility's transmission system an d that will pass under or over the premises owned by the customer or generator to be served or under or over premises for which the customer or generator has secured the nec essary right-of-way right of way. (h) A public u tility seeking to construct a high-voltage electric service line and related facilities (Project) must show that the utility has held a minimum of 2 pre-filing public meetings to rece ive public comment concerning the Project in each county wher e the Project is to be located, no earlier than 6 months prio r to filing an application for a certificate of public conv enience and necessity from the Commission. Notice of the public meeting shall be published in a newspaper of general circulati on within the affected county once a week for 3 consecut ive weeks, beginning no earlier than one month prior to the f irst public meeting. If the Project traverses 2 contiguous cou nties and where in one county the transmission line mileage and number of landowners over whose property the proposed rout e traverses is one-fifth or less of the transmission line mi leage and number of such landowners of the other county, t hen the utility may combine the 2 pre-filing meeti ngs in the county with the greater transmission line mileage and a ffected landowners. All other requirements regarding pre-filing meetings shall apply in both counties. Notice of the public meeting, including a description of the Project, mus t be provided in writing to the clerk of each county where the P roject is to be located. A representative of the Commission shall be invited to each pre-fil ing public meeting. (h-5) A public u tility seeking to construct a high-voltage electric s ervice line and related facilities must also show that the Project has complied with training and competence requirements under subs ection (b) of Section 15 of the Electric Transmission Systems Construction Standards Act. (i) For applic ations filed after August 18, 2015 (the effective date o f Public Act 99-399), the Commission shall, by certified mail, notify each owner of record of land, as identified in the records o f the relevant county tax assessor, included in the right-of-way over which the utility seeks in its application to construct a high-voltage electric line of the time and place scheduled for the initial hearing on the public utility 's application. The utility shall reim burse the Commission for the cost of the postage and supplies incurred for mailing the notice.(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21; 102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff. 6-1 -24; 103-1066, eff. 2-20-25.) (220 ILCS 5/8-512) Sec . 8-512. Re newable energy access plan. (a) It is the policy of this State to promote cost-effective transmission system development that ensures reliability of t he electric transmission system, lowers carbon emissions, mini mizes long-term costs for consumers, and sup ports the electric policy goals of this State. The General Assembly finds that: (1 ) Transmission planning, primarily for reliability purp oses, but also for economic and public policy reasons is cond ucted by regional transmission organizations in which t ransmission-owning Illinois utilities and other stak eholders are members. (2 ) Order No. 1000 of the Federal Energy Regulatory Com mission requires regional transmission organizations to pla n for transmission system needs in light of State public policies and to accept input from states during the transmission syste m planning processes. (3) The State of Illinois does not currently have a comp rehensive power and environmental policy planning process to identify transmission infrastructure needs that can serve as a vital input into the regional and interregional transmission organization pl anning processes conducted under Order No. 1000 and other la ws and regulations. (4) This State is an electricity generation and power transmi ssion hub, and can leverage that position to invest in infr astructure that enables new and existing Ill inois generators to meet the public policy goals of the State o f Illinois and of interconnected states while cost-effectively sup porting tens of thousands of jobs in the renewable ener gy sector in this State. ( 5) The nation has a need to readily access this State's low-cost, clean electric power, and this State also desi res access to clean energy resources in other states to dev elop and support its low-carbon economy and keep electricity prices low in Illinois and inte rconnected States. (6) Existing transmission infrastructure may constrain the S tate's achievement of 100% renewable energy by 2050, the accelerated adoption of electric vehicles in a just and eq uitable way, and electrification of additional sectors of t he Illinois economy. ( 7) Transmission system congestion within this State and th e regional transmission organizations serving this Stat e limits the ability of this State's existing and new e lectric generation facilities that do not emit carbon dio xide, including renewable energy resources and zero emiss ion facilities, to serve the public policy g oals of this State and other states, which constrains inves tment in this State.

(8) Investment in infrastructure to support existing and new electric generation facilities that do not emit carbon dioxide, including renewable energy resources and ze ro emission facilities, stimulates significant economic d evelopment and job growth in this St ate, as well as creates environmental and public health benefits in this State. (9 ) Creating a forward-looking plan for this State's electric tran smission infrastructure, as opposed to relying on case-by -case development and repeated marginal upgrades, will achieve a lower-cost system for Illinois' el ectricity customers. A forward-looking plan can also help integrate and achieve a comprehen sive set of objectives and multiple state, regional, and n ational policy goals. (10 ) Alternatives to overhead electric transmission lines can achieve cost-effective resolution of system im pacts and warrant investigation of the circumstances under which those alternatives should be considered and approv ed. The alternatives are likely to be beneficial as investment in electric transmission infr astructure moves forward. (11) Because transmission planning is conducted primari ly by the regional transmission organizations, the Commiss ion should be advocating for the State's interests at the regional transmission organizations to ensure tha t such planning facilitates the State's policies and goals, including overall consumer savings, power system reli ability, economic development, environmental improvement, and c arbon reduction. (12) Advanced transmission technologies have an i mportant role to play in meeting the State's clean ene rgy goals. For the purposes of this Section, "advanced tr ansmission technology" is hardware or software that provides cost-effective increases to the capacity, efficiency, or reliability of existing transmission infras tructure, and includes, but is not limited to: (i) technology that dynamically adjusts the rated capacity of transmissi on lines based on real-time conditions; (ii) advance d power flow controls used to actively control the flow of electricity across transmission lines to optimize usage or relieve congestion; (iii) software or hardware used to identify optimal transmission grid configurations or ena ble routing power flows around congestion points; and (i v) advanced transmission line conductors that have a d irect current electrical resistance at least 10% l ower than existing conductors of a similar diameter on the transmission system. (b) Consiste nt with the findings identified in subsection (a), the Commission shall open an investigation to develop a nd adopt an initial a renewable energy access plan no later than December 31 , 2022. To assist and support the Commission in the developmen t of the plan, the Commission shall retain the services of te chnical and policy experts with relevant fields of expertise, solic it technical and policy analysis from the public, and provide for a 120-day open public comment period after publicati on of a draft report, which shall be published no later than 90 days after the comment period ends. The plan shall, at a mi nimum, do the following: (1) designate renewable energy access plan zones t hroughout this State in areas in which renewable ener gy resources and suitable land areas are su fficient for developing generating capacity from renewable energy technologies; (2) develop a plan to achieve transmission capacity nec essary to deliver the electric output from renewable energy technologies in the renewable energy access plan zon es to customers in Illinois and other st ates in a manner that is most beneficial and cost-effective to customers; (3) use this State's position as an electricity generation and power transm ission hub to create new investment in this State's renewable energy resources; (4) consider programs, policies, and electric transmi ssion projects that can be adopted within this State that p romote the cost-effective delivery of power from re newable energy resources interconnected to the bulk electr ic system to meet the renewable portfolio standard targe ts under subsection (c) of Section 1-75 of the Illinois Power Agency Act; (5) consider proposals to improve regional transmission organizations' regional and interregiona l system planning processes, especially proposals that reduce costs and emissions, create jobs, and increase State and regional power system reliability to prevent high-cost outages that can endanger lives, and analyze of how th ose proposals would improve reliabili ty and cost-effective delivery of electricity in Illin ois and the region; (6) make findings and policy recommendations based on technical and policy analysis regarding locations of renewable en ergy access plan zones and the transmission system developments need ed to cost-effectively achieve the public policy goal s identified herein; (6.5) mak e findings and policy recommendations based on analy sis regarding the impact of converting non-powered dams to hydropower dams relative to the alternative renewable ene rgy resources; and (7) present the Commission's conclusions and proposed recomme ndations based on its analysis and use the findings and policy recommendations to determine actions that the Commission should take. (c) No later than December 31, 2025 or 180 days after the effective date of this amendatory Act of the 104th General Assembly, whichever is later, and every other year thereafter, the Commission shall open an investigation to develop and adopt a an updated renewable energ y access plan update that consi ders electric transmission projects, transmission policies, transmission alternatives, advanced transmission technologies, oth er ways to expand capacity on existing or future transmission, and transmission headroom and, at a minimum , : ev aluates the implementation and effectiveness of the renewa ble energy access plan, recommends improvements to the rene wable energy access plan, and provides changes to transmission capacity necessary to de liver electric output from the renewable energy access plan zones. (1) evaluates the implementation and effectiveness of the renewable energy access pla n; (2) recommends improvements to the renewable energy access plan;

(3) includes updated inputs and assumptions developed under the integrated resource plan developed an d approved pursuant to Section 16-201 and Section 16-202; (4) requests utilities and other p arties to specifically identify all elements of the existing transmission system where advanced transm ission technologies are likely to achieve enhanced sys tem resilience or reliability, reduce potential siting conflicts or land impacts from the development of new transmission lines, promote the cost-effective delivery of pow er from renewable energy resources interconnected to the bulk electric system, enable the interconnection of renewable energy resources, or reduce curtailment of re newable energy resources. The plan must identify all eleme nts of the existing transmission system which h ave experienced capacity constraints or congestion w ithin the prior 2 years and explain whether any advanced transmission tech nology could reduce or resolve the capacity constraint or congestion;

(5) includes an evaluation of identified and propos ed transmission projects, including proposed advanced tr ansmission technology projects, based on independent ana lysis of costs and benefits, including customer bill impa cts over the life of the project and achievement of S tate clean energy goals. Projects shall be evaluated in coordination with other propos als, and may include a combined evaluation of portfolios of pro jects; (6) develops a recommended list of transmission proj ects and advanced transmission technology projects that achieve the clean energy public policy objecti ves of the State. Nothing in this Section shall limit the recommended list of transmission projects to those ini tially proposed. However, no transmission or advanced transmission technology project can be included in the recommended list unless evaluate d; and (7) considers additional mechanisms designed to capture the potential value of geographically d iverse resources that proposed interregional transmission projects may provide. The Comm ission may evaluate options for implementation of the recommend ed list of transmission projects and advanced transmission te chnology projects that achieve the clean energy public policy objectives of the State, including through the use of a state agreement approach or a similar structure ma de available through the relevant regional t ransmission organizations, and approves final recommendations on imp lementation. The Commissio n may invite parties to identify transmission projects, includin g any associated network upgrades, necessary to facilitate achievement of the goals of the plan and the most recen tly approved integrated resource plan. Proposals for projects s hall include a description of each project; a proposed target date for completion; an estimated timeline for develop ment; the energy, capacity, and generation profile of rene wable generation and energy storage enabled by the project; anticipated new loads served by the project; the proposed te chnology used, including the use of any advanced transmissi on technologies; and the status of any permits or approvals nec essary. For projects with a target completion date of withi n 5 years from the date of proposal, the proposal must also include an estimated cost of the project and the propos ed routing corridor. The Commission s hall aim to complete the updated plan investigation within 12 months of opening. (d) Each tran smission-owning State utility serving more than 20 0,000 customers in this State may prepare a plan for integratin g advanced transmission technologies into the utility's existing transmission system. The plan must identify all ele ments of the existing transmission system where advanced transmiss ion technologies are likely to achieve any of the following purposes: (1) enhance system resilience or reliability;

(2) reduce potential siting conf licts or land impacts from the development of new transmission lines; (3) p romote the cost-effective delivery of power from re newable energy resources interconnected to the bulk electr ic system to meet the renewable portfolio standard targets under s ubsection (c) of Section 1-75 of the Illinois Power Agency A ct; ( 4) enable the interconnection of renewable energy resources to me et the renewable portfolio standard targets under subs ection (c) of Section 1-75 of the Illinois Power Agency Act; or (5) reduce curtailment of renewable or zero-carbon resources. The plan must identify all elements of the existing transm ission system which have experienced capacity constraints or congestion within the prior 2 years and explain whet her any advanced transmission technology could reduce or resolv e the capacity constraint or congestion. Each transmission-owning State utility may submit an advanced transmission t echnology integration plan to the Commission for consideration as part of the Commission's updated renewable energy a ccess plan investigation under subsection (c). In the Commissio n's updated renewable energy access plan, the Commission may e valuate, request modifications for, change the timelines of implementation fo r, and determine the next steps for each advanced transmission integrat ion plan. (e) Each transmission-owning State utility serving more than 200,000 customers in this State may conduct a comprehensi ve Transmission Headroom Study that shall identify, at a minim um, the points of interconnection with unused, existing tran smission headroom on the State system, including availabl e capacity behind existing, underutilized points of intercon nection, and the amount of available headroom in megawatts at each identified point of interconnection. Each transmission- owning State utility may submit a Transmission Headroo m Study to the Commission for consideration as part of the Commi ssion's updated renewable energy access plan investigation unde r subsection (c). (f) The C ommission shall approve an updated renewable energy access plan if it finds that, at a minimum, the evidence in the investi gation meets the criteria outlined in subsection (c) and demonstrates that the up dated plan will support the clean energy public policy objectives of the State. ( g) The Commission shall notify the applicable regional tra nsmission organizations and utilities of any final re commendations to support the clean energy public policy ob jectives of the State. (h) Nothing in this Section alters the rights of transmiss ion utilities (i) under rates on file with the Federal E nergy Regulatory Commission or the Illinois Commerc e Commission, (ii) under orders and determinations of the F ederal Energy Regulatory Commission or a re gional transmission organization, or (iii) under applicable State laws and policies.(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.) (220 ILCS 5/8-513 new) Sec. 8-513. Thermal Energy Network Pilot Program.

(a) The Commission shall coordinate with the Illinois Finance Author ity, in its role as Climate Bank for the State, to leverage an y available federal funding to support thermal energy network pilot projects through the provision of grants or to provide o r leverage financing. If that federal funding is not av ailable or not sufficient to meet program objectives, th e Commission shall authorize the allocation of up to $20,000,0 00 to support the thermal energy network pilot projects, to be provided to the Illinois Finance Authority to distri bute to projects as a grant or to provide or leverage fin ancing. The Illinois Finance Authority shall submit projects th at have already been approved by the Illinois Finance Authority to the Commission for review and approval in a form and mann er determined by the Commission. The Commission shall approv e projects that it deems to be just, reasonable, and in the pub lic interest. Any allocation of funding shall provide for the Illinois Finance Authority to use a portion of such allocated funds to support its reasonable administrative costs in administering the program un der this Section. (b) A n electric utility shall be entitled to recover, through tari ffed charges approved by the Commission, all of the costs assoc iated with projects authorized for funding by the Commission pur suant to this Section and shall be recovered as part of the utility's costs incurred under Section 45 of the Ele ctric Vehicle Act. If any authorized funds have not been reco vered by the utility as of January 1, 2029, the Environ mental Protection Agency shall allocate the remaining funds to the Illinois Finance Authority as part of its beneficia l electrification programs described in Section 45 of the Electric V ehicle Act. (c) As part of any pilot project proposed pursuant to this Section, the Com mission is authorized to approve any specific customer r ebates and incentives and any project-specific tariff s and rules. The Commission may create a standard proposed ra te structure or minimum requirements for a rate structu re to be required of all thermal energy network pilot proje cts. The Commission may approve the proposed rate structu re of a thermal energy network pilot project if the projected heating and cooling costs for end users is not gre ater than the projected heating and cooling costs the end users would have incurred if the end users had not partic ipated in the program. In its approval process, the Commis sion shall take into account scenarios where pilot projects enhance comfort and safety for customers through expanded access to affordable heatin g and cooling. (d) A pproved thermal energy network pilot projects shall report t o the Commission, on a quarterly basis and until completi on of the thermal energy network pilot project, the status of each thermal energy network pilot project. The Commission shal l post and make publicly available the repo rts on its website. The reports shall include, but not be limited to: (1) the stage of development of each pilot project; (2) the barriers to development; (3) the number of customers served; (4) the costs of the pilot proj ect; (5) the number of jobs retained or created by the pilot project ; (6) energy savings and fue l savings from the project and energy consumption by the project; a nd (7 ) other information the Commission deems to be in the public interest or considers l ikely to prove useful or relevant to the rulemaking described in subse ction (i). (e) Any ent ity operating a Commission-approved thermal energy net work pilot project shall demonstrate that it has entered i nto a labor peace agreement with a bona fide labor organ ization that is actively engaged in representing its employees . The labor peace agreement shall apply to the employees neces sary for the ongoing maintenance and operation of the t hermal energy network. The existence of a labor peace agree ment shall be an ongoing material condition o f an entity's authorization to maintain and operate the thermal ene rgy networks. (f) Any contractor or subcontractor that performs work on a thermal energy network pilot project under this Section shall be a responsi ble bidder, as described in Section 30-22 of the Illinoi s Procurement Code, and shall certify that not less than prevai ling wage, as determined under the Prevailing Wage Act, was o r will be paid to the employees who are engaged in constructi on activities associated with the pilot thermal energy netwo rk system. The contractor or subcontractor shall submit eviden ce to the Commission that it complied with the requirements of this subsection (f). For any approved thermal energy network p ilot project, the contractor or subcontractor shall submit evi dence that the contractor or subcontractor has entered in to a fully executed project labor agreement for the thermal energy network system prior to the initiation of construction activities. (220 ILCS 5/9-229) Sec. 9-229. Consideration of attorney and expert compensation as an expense and intervenor comp ensation fund. (a) The Com mission shall specifically assess the justness and reasonabl eness of any amount expended by a public utility to compe nsate attorneys or technical experts to prepare and litigate a general rate case filing. This issue shall be expressly ad dressed in the Commission's final order. (b) The State of Illinois shall create a Consumer Intervenor Compensation Fund subject to th e following: (1) Provision of compensation for consumer interest representatives Co nsumer Interest Representatives that intervene in Illinois Commerce Commission proceedings will increase public engagement, encourage additional transparency, expand the information available to the Commission, and improve decision-making. (2) As used in this Section, "consu mer Consumer interest re presentative" means: (A) a residential utility customer or group of res idential utility customers represented by a not-for-profit group or organization regist ered with the Illinois Attorney General under the Solicitation for Chari ty Act; (B) representatives of not-for-profit groups or organizations whose membership is limited to residential utility custom ers; or

(C) representatives of not-for-profit gr oups or organizations whose membership includ es Illinois residents and that address the community, economic, environmental, or social welfare of Illinois residents, except govern ment agencies or intervenors specifically authorized by Illinoi s law to participate in Commission proceedings on behalf of Illinois consumers. (3) A consumer interest representative is eligible to receive compensation from the Consu mer Intervenor Compensation Fund consumer intervenor compensation fund i f its participation included lay or expert testimony or legal brie fing and argument concerning the expenses, investments, rate d esign, rate impact, development of an integrated resource plan pursuant to Section 16-201 and any related proceedings, or other matters affecting the pricing, rates, costs or other charges associated wit h utility service and , the Commission does not find the participation t o be immaterial adopts a material r ecommendation related to a significant issue in the docket, and particip ation caused a significant financial hardship to the participant; however, no consumer int erest representative shall be eligible to receive an a ward pursuant to this Section if the consumer interest rep resentative receives any compensation, funding, or donations, di rectly or indirectly, from parties that have a fi nancial interest in the outcome of the proceeding. Funding from residential ratepayers shall not be conside red funding from a party with a financial interest unle ss determined to be by the Commission. The Commission sha ll determine participation by the consumer interest representative to be material if recommendations made by the consumer interest representative are: (A) relevant to issues in the proceeding on which the Commission makes a finding; (B) supported by facts, such as s tudies, methods, or calculations, or by legal or policy an alysis; and

(C) offered by the consumer intere st representative into evidence in the record of tha t proceeding, or for legal or policy analysis, are filed in the d ocket of that proceeding, through briefing, motion, or other method. (4) Within 30 days after September 15, 2021 (the effective da te of Public Act 102-662), each utility that files a r equest for an increase in rates under Article IX or Artic le XVI shall deposit an amount equal to one half of th e rate case attorney and expert expense allowed by the Comm ission, but not to exceed $500,000, into the fund within 3 5 days of the date of the Commission's final Order in the rate c ase or 20 days after the denial of rehearing under Sect ion 10-113 of this Act, whichever is later. The Co nsumer Intervenor Compensation Fund shall be used to pro vide payment to consumer interest representatives as describ ed in this Section. (5) An electric public utility with 3,000,000 or more retail customers shall contribute $450,000 to the Con sumer Intervenor Compensation Fund within 60 days after Sep tember 15, 2021 (the effective date of Public Act 102-662). A combined electric and gas public utility s erving fewer than 3,000,000 but more than 500,000 retail customers shall contribute $225,000 to the Con sumer Intervenor Compensation Fund within 60 days after Sept ember 15, 2021 (the effective date of Public Act 102-662). A gas public utility with 1,500,000 or more retai l customers that is not a combined electric and ga s public utility shall contribute $225,000 to the Con sumer Intervenor Compensation Fund within 60 days after Septemb er 15, 2021 (the effective date of Public Act 102- 662). A gas public utility with fewer than 1,500,000 re tail customers but more than 300,000 retail customer s that is not a combined electric and gas public utility s hall contribute $80,000 to the Consumer Intervenor Compensation Fund within 60 days after September 15, 2021 (the effect ive date of Public Act 102-662). A gas public u tility with fewer than 300,000 retail customers that is not a combined electric and gas public utility shall contribute $20,000 to the Consumer Intervenor Compensation Fund w ithin 60 days after September 15, 2021 (the effective dat e of Public Act 102-662). A combined electric and gas public utility serving fewer than 500,000 retail customers shall contribute $20,000 to the Con sumer Intervenor Compensation Fund within 60 days after Septe mber 15, 2021 (the effective date of Public Act 102-662). A water or sewer public utility serving more th an 100,000 retail customers shall contribute $80,000 , and a water or sewer public utility serving few er than 100,000 but more than 10,000 retail customers shall contribute $20,000. (6)(A) Prior to the entry of a final order Final Order in a docketed case, the Commission Administrator shall provide a payment to a consumer interest representat ive that demonstrates through a verified application for f unding that the consumer interest representative's participa tion or intervention without an award of fees or costs imposes a significan t financial cost for the consumer interest represent ative hardship based on a schedule to be dev eloped by the Commission. The Administrator may require verification of costs expected to be incurred, inc luding statements of expected hours spent, as a condition to paying t he consumer interest representative prior to the entry of a final order Final Order in a dockete d case. The upfront payment prior to the entr y of a final order in the relevant docketed case sha ll be subject to the reconciliation process described in su bparagraph (C) of this paragraph. For purposes of upfront payments provided for under this subparagraph, and provided the testimony or legal argument was offered into e vidence or filed in the docket, a decision by the Commis sion prior to entry of a final order that a consumer int erest representative's evidence or legal argu ment is relevant to issues in the proceeding under subparag raph (A) of paragraph (3) shall not be subject to recon sideration. Any compensation awarded shall be subject to review and reconciliation under subparagraph (C) of th is paragraph. Payments made after the issuance of a final or der in the relevant docketed case do not require the reconciliation. (B) If the Commission doe s not find the participation to be immaterial

adopts a material recommendation related to a significant issue in the docket and participation caused a financial hardship to the participant, then the consume r interest representative shall be allowed payment fo r some or all of the consumer interest representati ve's reasonable attorney's or advocate's fees, rea sonable expert witness fees, and other reasonable costs of preparation for and participation in a hearing or proceeding. Expenses related to travel or meals shall not be compensa ble. Expenses incurred by participation in worksh ops or other informal processes outside a docketed proceedi ng shall not be compensable. Attorneys and expert witnes ses who represent or testify for more than one party in the same docketed proceeding and perform essent ially the same work on behalf of the parties shall not be compensated more than once for those same services rendered in that pro ceeding. (C) The consumer interest representative shall submit an itemized request for compensation to the Consumer I ntervenor Compensation Fund, including the advocate's or attorney's reasonable fee rate, the number of hours expended, reasonable expert and expert witness fees, and other re asonable costs for the preparation for and participation in the hearing and briefing within 30 days after

of the Commission's final order or the Commi ssion's after denial or decision on rehea ring, if any, whichever is later. If compensation is provided prior to the entry of a final order in a docketed case, such compensation shall be adjusted following the final order to reconcile the dif ference between actual eligible expenses incurred and th e amount of compensation provided prior to the ent ry of the final order. The reconciliation adjustment shall ensure that the total compensation awarded to the applic ant is no more and no less than the actual eligible expen ses incurred. Payments made after the issuance of a final or der in the relevant docketed case do not require the reconciliation . (7) Adm inistration of the Fund. (A) The Consumer Intervenor Compensation Fund is created as a special fund in the State treasury. All disb ursements from the Consumer Intervenor Compensation Fun d shall be made only upon warrants of the Comptro ller drawn upon the Treasurer as custodian of the Fund up on vouchers signed by the Executive Director of the Commi ssion or by the person or persons designated by the Directo r for that purpose. The Comptroller is authorized to draw the warrant upon vouchers so signed. The Treasurer shall accept all warrants so signed and shall be release d from liability for all payments made on those warra nts. The Consumer Intervenor Compensation Fund sha ll be administered by an Administrator that is a p erson or entity that is independent of the Commission. T he administrator will be responsible for the prude nt management of the Consumer Intervenor Compensation Fund and for recommendations for the award of consumer intervenor compensation from the Consumer Intervenor Compensation Fund. The Commission shall issue a request for qualifica tions for a third-party program administrator to adminis ter the Consumer Intervenor Compensation Fund. The third -party administrator shall be chosen through a co mpetitive bid process based on selection criteria and req uirements developed by the Commission. The Illinois Procur ement Code does not apply to the hiring or payment of the A dministrator. All Administrator costs may be paid fo r using monies from the Consumer Intervenor Compensation Fund, but the Program Adm inistrator shall strive to minimize costs in the implementa tion of the program. ( B) The computation of compensation awarded from the fund sh all take into consideration the market rates paid to person s of comparable training and experience who offer similar se rvices, but may not exceed the comparable market rate for services paid by the public utility as part of its rate case expense. (C) (1) Recommendations on the award of compensation by the administrator shall include consideration of whether the participation was m aterial Commission adopted a mater ial recommendation related to a significant iss ue in the docket and whether participation caused a financial hardship to the partici pant and the payment of compensation is fair, just and rea sonable. (2 ) Recommendations on the award of compensation by the administra tor shall be submitted to the Commission for approval w ithin 30 days after when the application for funding is submitted to the administrator. Un less the Commission initiates an investigation within 60 45 days after an application for funding is submitted to the admin istrator, the Commission shall within 90 days after t he application is submitted to the administrato r, or as soon as practicable thereafter, award funding to the applicant. Notice of the administrator's award recommendation the notice to the Commission, the award of compensation shall b e allowed 45 days after notice to the Commission. Such not ice shall be given by filing with th e Commission on the Commission's e-docket system, and keeping open for public inspection the award for compensat ion proposed by the Administrator. The Commission shall have power, and it is hereby given authority, either upon complaint or upon its own initiative without compl aint, at once, and if it so orders, without answer or other formal pleadings, but upon re asonable notice, to enter upon a hearing concerning the propriety of the award. (3) A consumer interest representative who performe d work or otherwise incurred expenses in an eligible proce eding before the Commission prior to the effective date of this amendatory Act of the 104th General Assembly and after September 15, 2021 (the effective date of Public Act 102 -662) and who, due to a denied application or ot herwise, was not awarded compensation for the entirety of the incurred expenses from the Consumer Intervenor Comp ensation Fund may seek compensation from the Consumer Inte rvenor Compensation Fund pursuant to this Section. Nothi ng in this Section shall prohibit retroactive awards to eligible participants for work performed or expenses incur red in eligible proceedings prior to the effective date of this amendatory Act of the 104th General Assembly and after S eptember 15, 2021 (the effective date of Public Act 102-662). The retroactive awards shall not includ e additional costs directly or indirectly incurred due to the prior denial of an application for an eligible pr oceeding. Applications for a retroactive award shall be subject to the revised eligibility standards enacted pursuant to this amendatory Act of the 104th General Assem bly. The applications may be submitted at any time within one calendar year after the effective date of this amendatory Act of t he 104th General Assemb ly. (c) The Commission may adopt rules to implement this Section.(Source: P.A. 102-662, eff. 9- 15-21; 103-605, eff. 7-1-24.) (220 ILCS 5/16-107.5) Se c. 16-107.5. Net electri city metering. (a) Th e General Assembly finds and declares that a program t o provide net electricity metering, as defined in this Sectio n, for eligible customers can encourage private investment in renewable energy resources, stimulate economic growth, e nhance the continued diversification of Illinois' energy resou rce mix, and protect the Illinois environment. Further, to achieve the goals of this Ac t that robust options for customer-site distributed generation and storage continue to thrive in Illinois, the General Assembly finds that a predicta ble transition must be ensured for customers between full net metering at the retail el ectricity rate to the distribution generation rebate described in Section 16-107.6. (b) As used in this Section: , (i) "Community commun ity renewable generation project" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act. ; (ii) "Eligible eligible customer" means a retail cu stomer that owns, hosts, or operates, including any third-p arty owned systems, a solar, wind, or other eligible renewable elect rical generating facility or an eligible storag e device that is located on the customer's premis es or customer's side of the billing meter and is intended primarily to offset the customer's own current o r future electrical requirements. ; (iii) "Electricity electricity provider" means an electric utility or alte rnative retail electric supplier. ; (iv) "Eligible eligible renewable electrical generating facility" means a generator, which may inclu de the colocation c o-location of an energy storage system, that is interconnected under rules adopted by the Commission and is powered by solar electric energy, win d, dedicated crops grown for electricity generation, agric ultural residues, untreated and unadulterated wood was te, livestock manure, anaerobic digestion of livestock or food processing waste, fuel cells or microturbines powered by renewabl e fuels, or hydroelectric energy. ; (v) "Net net electricity metering" (or "net metering ") means the measurement, during the billing period app licable to an eligible customer, of the net amount of el ectricity supplied by an electricity provider to the customer or provided to the electricity provid er by the customer or subscriber. ; (vi) "Subscriber sub scriber" shall have the meaning as set forth in Section 1-10 of the Illinois Power Agency Act. ; (vii) "Subscription subscription" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act. ; (viii) "Energy energy storage system" means c ommercially available technology that is capable of absorbing energy and storing it for a period of time for use at a later time, including, but not li mited to, electrochemical, thermal, and electromechanical technologies, and may be interc onnected behind the customer's meter or interco nnected behind its own meter. ; and (ix) "Future future electrical requirements" means model ed electrical requirements upon occupation of a new or vacant property, and other reasonable expectations of future electrical use, as well as, for occupied properti es, a reasonable approximation of the annual load of 2 el ectric vehicles and, for non-electric heatin g customers, a reasonable approximation of the incremen tal electric load associated with fuel switching. The approximations shall be applied to the appropriate net metering tariff and do not need to be unique to ea ch individual eligible customer. The utility shall submit these approximations to the Commission for review, modification, and approval. (x) "Vehicle storage system" means a vehicle that when connec ted to an electric utility's distribution system is c apable of being an energy storage system, as define d in Section 16-107.6. (c) A net metering facility shall be equipped with metering equipmen t that can measure the flow of electricity in both direction s at the same rate. (1) For eligible customers whose electric service has not been decl ared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour bas is and electric supply service is not provided based on hour ly pricing, this shall typically be accomplished through use of a single, bi-directional meter. If the eligib le customer's existing electric revenue meter does not mee t this requirement, the electricity provider shall arran ge for the local electric utility or a meter service provid er to install and maintain a new revenue meter at the electrici ty provider's expense, which may be the smart meter described by subsection (b) of Section 16-108.5 of this Act. (2) For eligible customers whose electric service has not been decl ared competitive pursuant to Section 16-113 of t his Act as of July 1, 2011 and whose electric delivery serv ice is provided and measured on a kilowatt demand bas is and electric supply service is not provided based on h ourly pricing, this shall typically be accomplish ed through use of a dual channel meter capable of measur ing the flow of electricity both into and out of the cust omer's facility at the same rate and ratio. If such cu stomer's existing electric revenue meter does not meet thi s requirement, then the electricity provider shall arran ge for the local electric utility or a meter service provid er to install and maintain a new revenue meter at the electrici ty provider's expense, which may be the smart meter described by subsection (b) of Section 16-108.5 of this Act. (3 ) For all other eligible customers, until such time as the loc al electric utility installs a smart meter, as described by subsection (b) of Section 16-108.5 of this Act , the electricity provider may arrange for the local elec tric utility or a meter service provider to install and maintain metering equipment capable of measuring the flow o f electricity both into and out of the customer's facili ty at the same rate and ratio, typically through th e use of a dual channel meter. If the eligible customer's existing electric revenue meter does not meet this re quirement, then the costs of installing such equipment s hall be paid for by the customer. (d) An el ectricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eli gible customers whose electric service has not been declared com petitive pursuant to Section 16-113 of this Act as of July 1, 2 011 and whose electric delivery service is provided and measur ed on a kilowatt-hour basis and electric supply service is not provided based on hourly pricing in th e following manner: (1) If the amount of electricity used by the cu stomer during the billing period exceeds the amount of elec tricity produced by the customer, the electricity pr ovider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e -5) of this Section. (2) If the amount of electricity produced by a c ustomer during the billing period exceeds the amount of e lectricity used by the customer during that billing period, t he electricity provider supplying that customer shall app ly a 1:1 kilowatt-hour credit to a subsequent bi ll for service to the customer for the net electr icity supplied to the electricity provider. The electricity pr ovider shall continue to carry over any e xcess kilowatt-hour credits earned and apply those credi ts to subsequent billing periods to offset any cust omer-generator consumption in those billin g periods until all credits are used or until the end of the annualized period. (3) At the end of the year or annualized over the p eriod that service is supplied by means of net metering, o r in the event that the retail customer terminates servic e with the electricity provider prior to the end of the ye ar or the annualized period, any remaining credits in the custom er's account shall expire. (d-5) An el ectricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eli gible customers whose electric service has not been declared com petitive pursuant to Section 16-113 of this Act as of July 1, 2 011 and whose electric delivery service is provided an d measured on a kilowatt-hour basis and electric supply service is provided ba sed on hourly pricing or time-of-use rates in th e following manner: (1) If the amoun t of electricity used by the customer during any hou rly period or time-of-use period exceeds the am ount of electricity produced by the customer, the electrici ty provider shall charge the customer for the net electri city supplied to and used by the customer according to t he terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was no t a net metering customer. (2) If the amount of electricity produced by a customer durin g any hourly period or time-of-use period exceeds the amount of electricity used by the customer durin g that hourly period or time-of-use period, the ene rgy provider shall apply a credit for the net kilowatt-hours produced in such period. The credit shall consis t of an energy credit and a delivery service credit. The en ergy credit shall be valued at the same price per kilowatt-hour as the electric service provider would charge for kilowatt-hour energy sales during that same hourly period or time-of-use period. The delivery credit shall be equal to the n et kilowatt-hours produced in such hourly period or time-of-use period times a credit that reflects all kilowatt-hour based charges in the customer's electric servic e rate, excluding energy charges. (e) An el ectricity provider shall measure and charge or credit for the net electricity supplied to eligible customers whose electric s ervice has not been declared competitive pursuant to Section 1 6-113 of this Act as of July 1, 2011 and whose elec tric delivery service is provided and measured on a kilowatt demand basis and electric supply service is not provided based on hourly pricing in th e following manner: (1) If the amount of electricity used by the custome r during the billing period exceeds the amount of electrici ty produced by the customer, then the electricity pr ovider shall charge the customer for the net electricity su pplied to and used by the customer as provided in su bsection (e-5) of this Section. The customer shall re main responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electri city used by the customer. (2) If the amount of electricity produced by a c ustomer during the billing period exceeds the amount of electricity used by the customer during that billing per iod, then the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit that reflects the k ilowatt-hour based charges in the customer's el ectric service rate to a subsequent bill for service to the customer for the net electricity supplied to the electr icity provider. The electricity provider shall contin ue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billin g periods until all credits are used or until the end of the annualized period. (3) At the end of the year or annualized over the p eriod that service is supplied by means of net metering, o r in the event that the retail customer terminates servic e with the electricity provider prior to the end of the ye ar or the annualized period, any remaining credits in the c ustomer's account shall expire. (e-5) An electricity provider shall provide electric service to eligi ble customers who utilize net metering at non-disc riminatory rates that are identical, with respect to rate struct ure, retail rate components, and any monthly charges, to th e rates that the customer would be charged if not a net met ering customer. An electricity provider shall not charge net me tering customers any fee or charge or require additio nal equipment, insurance, or any other requirements not specifi cally authorized by interconnection standards authorized by th e Commission, unless the fee, charge, or other requirement wo uld apply to other similarly situated customers who are not ne t metering customers. The customer will remain responsib le for all taxes, fees, and utility delivery charges that woul d otherwise be applicable to the net amount of electr icity used by the customer. Subsections (c) through (e) of this Sec tion shall not be construed to prevent an arms-length agr eement between an electricity provider and an eligible customer that sets forth different prices, terms, a nd conditions for the provision of net metering service, including, but not limited to , the provision of the appropriate metering equipment fo r non-residential customers. (f) Notwithst anding the requirements of subsections (c) through (e-5) of thi s Section, an electricity provider must require dual-channel metering for customers operating eligible renewable ele ctrical generating facilities to whom the provisions of neithe r subsection (d), (d-5), nor (e) of this Section apply. In such cases, electricity charges and credits shall be determined as follows: (1) The electricity provider shall assess an d the customer remains responsible for all taxes, fees, and util ity delivery charges that would otherwise be applicable to the gross amount of kilo watt-hours supplied to the eligible customer by the electricity provider. (2) Each month that service is supplied by means of dual-channel metering, the electricity provider sha ll compensate the eligible customer for any excess kilowatt -hour credits at the electricity provider's avoided cost of electricity supply over the monthly period or as otherwis e specified by the terms of a power-purchase agreement negotiated between the customer and electricity provider. (3) For all eligible net metering customers taking service from an el ectricity provider under contracts or tariffs employing h ourly or time-of-use rates, any monthly consu mption of electricity shall be calculated according to t he terms of the contract or tariff to which the same custo mer would be assigned to or be eligible for if the customer was n ot a net metering customer. When those same customer-generators a re net generators during any discrete hourly or time-of-use period, the net kilowatt-hou rs produced shall be valued at the same price per kilowatt-hour as the electric service provider would cha rge for retail kilowatt-hour sales during that same time-of-use period.

(g) For purposes of federal and State laws providing renewable energy credits or greenhouse gas credits, the eligible custom er shall be treated as owning and having title to the renewable energy attributes, renewable energy credits, and greenhous e gas emission credits related to any electricity produced by the qualified generating unit. The electricity provider ma y not condition participation in a net metering program on th e signing over of a customer's renewable energy credits; provid ed, however, this subsection (g) shall not be construed to pre vent an arms-length agreement between an electricit y provider and an eligible customer that sets forth t he ownership or title of the credits. (h) Within 120 days after the effective date of this amenda tory Act of the 95th General Assembly, the Commission sh all establish standards for net metering and, if the Com mission has not already acted on its own initiat ive, standards for the interconnection of eligible rene wable generating equipment to the utility system. The interconn ection standards shall address any procedural barriers, delays, and administrative costs associated with the interconnection of customer-generation while ensuring the safety and reliability of the units and the electric utility system. The Commission shall consider the Institute of Electrical a nd Electronics Engineers (IEEE) Standard 1547 and the issues of (i) reasonable and fair fees and costs, (ii) clear timelin es for major milestones in the interconnection process , (iii) nondiscriminatory term s of agreement, and (iv) any best practices for interconnection of distr ibuted generation. (h-5) Within 90 days after the effective date of this am endatory Act of the 102nd General Assembly, the Commission shall: ( 1) establish an Interconnection Working Group. The work ing group shall include representatives from electric utilities, developers of renewable electric g enerating facilities, other industries that regularly app ly for interconnection with the electric utilities, r epresentatives of distributed generation customers, the Commission Staff, and such other stakeholders with a su bstantial interest in the topics addressed by the Interconnection Working Group. The Intercon nection Working Group shall address at least the following issues: (A) cost and best available technology for interconnection and metering , including the standardization and publication of standard costs;

(B) transparency, accuracy and use of the distribution interconnection queue and hosting capacity maps; (C) distribution system upgrade cost avoidance through use of advanced inverter functions; (D) predictabi lity of the queue management process and enforcement of timelines; (E) benef its and challenges associated with group studies and cost sharing;

(F) minimum requirements for a pplication to the interconnection process and throug hout the interconnection process to avoid queue clogging beha vior;

(G) process and customer service for interconnecting customer s adopting distributed energy resources, including energy storage; (H) options fo r metering distributed energy resources, including energy storage; (I) interconnection of new technologies, including smart inverters and energy storage; (J) collect, share, and examine data on L evel 1 interconnection costs, including cost and type of upgrades required for interconnection, and use this data to inform the final standardized cost of Level 1 interconnection; and (K) such other technical, policy, and tariff issues related to and affecting interconnection performance and cus tomer service as determined by the Interconnection Working Group. The Commission may create subcommittees of the Intercon nection Working Group to focus on specific issues of importance, as appropriate. The Interconnection Worki ng Group shall report to the Commission on recommended improvements to interconnection rules and tariffs and pol icies as determined by the Interconnection Working Group at least every 6 months. Such reports shall include conse nsus recommendations of the Interconnection Working Group and, if applicable, additional recommendations for wh ich consensus was not reached. The Commission shall use the report from the Interconnection Working Group to determine whether processes should be commenced to formally codify or implement the recommendations; (2) cr eate or contract for an Ombudsman to resolve interconnecti on disputes through non-binding arbitration. The Ombudsman may be paid in full or in part through fees levied on the initiators of the dispute; and (3) determine a single standardized cost for Level 1 interconnections, which s hall not exceed $200. (i ) All electricity providers shall begin to offer net meter ing no later than April 1, 2008. (j) An electric ity provider shall provide net metering to eligible customers according to subsections (d), (d-5), and (e). Eligibl e renewable electrical generating facilities for which eligible customers registered for net metering before January 1, 202 5 shall continue to receive net metering services according to subsections (d), (d-5), and (e) of this Section for the lifetime of the system, regardless of whether those retail cust omers change electricity providers or whether the retail custo mer benefiting from the system changes. On and after Ja nuary 1, 2025, any eligible customer that applies for net metering a nd previously would have qualified under subsections (d), (d -5), or (e) shall only be eligible for net metering as described in subsection (n). (k) Ea ch electricity provider shall maintain records and report annually to the Commission the total number of net metering c ustomers served by the provider, as well as the type, capaci ty, and energy sources of the generating systems used by the n et metering customers. Nothing in this Section shall limit t he ability of an electricity provider to request the redaction o f information deemed by the Commission to be confid ential business information. (l)(1 ) Notwithstanding the definition of "eligible customer" in ite m (ii) of subsection (b) of this Section, each electricity pr ovider shall allow net metering as set forth in this su bsection (l) and for the following projects, provided that only electric utilities serving more than 200,000 customers as of January 1, 2021 shall provide net metering for projects that are eligible for subparagraph (C) of this paragraph (1) and have energized after the effective date of this amendatory Act of the 102n d General Assembly: (A ) properties owned or leased by multiple customers that contribute to the operation of an eligible renewable elect rical generating facility through an ownership or leasehold interest o f at least 200 watts in such facility, such as a community-owned wind project, a community-owned biomass pro ject, a community-owned solar project, or a com munity methane digester processing livestock waste from multiple sources, prov ided that the facility is also located within the util ity's service territory; (B) individual units, apartments, or properties loc ated in a single building that are owned or leased by multi ple customers and collectively served by a common elig ible renewable electrical generating facility, such as an office or apartment building, a shopping center or strip mall served by photovoltaic pan els on the roof; and

(C) subscriptions to community renewable generation projects, including community renewable generation proje cts on the customer's side of the b illing meter of a host facility and partially used f or the customer's own load. In ad dition, the nameplate capacity of the eligible renewab le electric generating facility that serves the demand of the p roperties, units, or apartments identified in paragraphs (1) and (2) of this subsection (l) shall not exceed 5,000 kilowatts in nameplate capacity in total. Any eligible renewa ble electrical generating facility or community renewable gener ation project that is powered by photovoltaic electric energy and installed after the effective date of this amendatory Act of the 99th General Assembly must be installed by a qualified pers on in compliance with the requirements of Section 16-12 8A of the Public Utilities Act and any rules or r egulations adopted thereunder. (2) Notwithstanding anything to the contrary, an electricity pr ovider shall provide credits for the electricity produced by th e projects described in paragraph (1) of this subsection (l). The electricity provider shall provide credits that includ e at least energy supply, capacity, transmission, and, if app licable, the purchased energy adjustment on the subscriber's m onthly bill equal to the subscriber's share of the productio n of electricity from the project, as determined b y paragraph (3) of this subsection (l). For customers with transmiss ion or capacity charges not charged on a kilowatt-hour basis, t he electricity provider shall prepare a reasonable approximat ion of the kilowatt-hour equivalent value and provide tha t value as a monetary credit. The electricity provi der shall submit these approximation methodologies to the Commi ssion for review, modification, and approval. Notwithstanding anything to the contrary, customers on payment plans or participa ting in budget billing programs shall have credit s applied on a monthly basis.

(3) Notwithstanding anything to the contrary and regardless of whether a subscriber to an eligible community renewable gene ration project receives power and energy service from t he electric utility or an alternative retail electric suppli er, for projects eligible under paragraph (C) of subparagr aph (1) of this subsection (l), electric utilities se rving more than 200,000 customers as of January 1, 2021 sh all provide the monetary credits to a subscriber's subsequ ent bill for the electricity produced by community renewable g eneration projects. The electric utility shall provide monetary credits to a subscriber's subsequent bill at the utility's total price to compare equal to the subscriber's share of th e production of electricity from the project, as determined by paragraph (5) of this subsection (l). For the purp oses of this subsection, "total price to compare" means the ra te or rates published by the Illinois Commerce Commission fo r energy supply for eligible customers receiving supply s ervice from the electric utility, and shall include en ergy, capacity, transmission, and the purchased energy adjustm ent. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs s hall have credits applied on a monthly basis. Any applicab le credit or reduction in load obligation from the production of the community renewable generating projects receiving a credit under this subsection shall be credited to the e lectric utility to offset the cost of providing the credit. To the extent that the credit or load obligation reduction does not completely offset the cost of providing the credit to subscribers of community renewable generation projects as describe d in this subsection, the electric utility may recover the remaining costs through its Multi-Year Rate Plan. All electric utilities serving 200,000 or fewer custo mers as of January 1, 2021 shall only provide the monet ary credits to a subscriber's subsequent bill for the electri city produced by community renewable generation project s if the subscriber receives power and energy service from th e electric utility. Alternative retail electric suppliers pr oviding power and energy service to a subscriber located within the service territory of an electric utility not subject to Sections 16-108.18 and 16-118 shall provide the monetar y credits to the subscriber's subsequen t bill for the electricity produced by community renewabl e generation projects. (4) If requ ested by the owner or operator of a community renewable generati ng project, an electric utility serving more than 200,000 cust omers as of January 1, 2021 shall enter into a net crediting agreement with the owner or operator to include a subscrib er's subscription fee on the subscriber's monthly electric bil l and provide the subscriber with a net credit equivalent to the total bill credit value for that generation period minus t he subscription fee, provided the subscription fee is structure d as a fixed percentage of bill credit value. The net crediting agreement shall set forth payment terms from the electric utility to the owner or operator of the community renewab le generating project, and the electric utility may charge a net crediting fee to the owner o r operator of a community renewable generating project that may not exceed 1% 2% of the subscription fee b ill credit value. Notwithstanding anything to the c ontrary, an electric utility serving 200,000 customers or fewer as of January 1, 2021 shall not be obligated to enter into a net crediting agreement with the owner or operator of a comm unity renewable generating project. An electric utili ty shall use the same net crediting format for subscribers o n payment plans and subscribers participating in budget bill ing programs. For the purposes of this paragraph (4), "net cr editing" means a program offered by an electric utility under which the electric utility, upon authorization by or on beh alf of a subscriber, remits the cash value of the subscripti on fee to the owner or operator of the community renewable gene ration facility without regard to whether the subscriber h as paid the subscriber's monthly electric bill and places t he cash value of the remaining bill credit on the subsc riber's bill. ( 5) For the purposes of facilitating net metering, the owner or operator of the eligible renewable electrical generating faci lity or community renewable generation project shall be resp onsible for determining the amount of the credit that eac h customer or subscriber participating in a project under this subsection (l) is to receive in th e following manner: (A) The owner or operator shall, on a monthly basis, provide to the electric utility the kilowatthours of gener ation attributable to each of the utility's retail custom ers and subscribers participating in projects under th is subsection (l) in accordance with the customer's or s ubscriber's share of the eligible renewable electric gene rating facility's or community renewable generation p roject's output of power and energy for such month. The ow ner or operator shall electronically transmit such calculat ions and associated documentation to the electric utilit y, in a format or method set forth in the applicabl e tariff, on a monthly basis so that the electric utility can reflect the monetary credits on customers' and subscri bers' electric utility bills. The electric utility shal l be permitted to revise its tariffs to implement the pro visions of this amendatory Act of the 102nd General Assemb ly. The owner or operator shall separately provide the elec tric utility with the documentation detailing the calcul ations supporting the credit in the manner set forth in the applicable tariff. (B) For those participating customers and subscribers who recei ve their energy supply from an alternative retail el ectric supplier, the electric utility shall remit to the applicable alternative retail electric supplier t he information provided under subparagraph (A) of thi s paragraph (3) for such customers and subscribers in a manner set forth in such alternative retail electric sup plier's net metering program, or as otherwise agreed betw een the utility and the alternative retail electric suppl ier. The alternative retail electric supplier shall t hen submit to the utility the amount of the charges for pow er and energy to be applied to such customers and subscribers, including the amount of the credit associated w ith net metering. (C) A participating customer or subscriber may provide authori zation as required by applicable law that directs the ele ctric utility to submit information to the owner or op erator of the eligible renewable electrical generatin g facility or community renewable generation project to which the customer or subscriber has an ownership or l easehold interest or a subscription. Such information shall be limited to the components of the net metering credit c alculated under this subsection (l), including the bill credit rate, total kilowatthours, and total monetary cr edit value applied to the customer's or subscriber's bill fo r the monthly billing period. (l-5) Within 90 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric utility subject t o this Section shall file a tariff or tariffs to implement the provisions of subsection (l) of this Section, which shal l, consistent with the provisions of subsection (l), describe the terms and conditions under which owners or operators of q ualifying properties, units, or apartments may participate i n net metering. The Commission shall approve, or approve with m odification, the tariff withi n 120 days after the effective date of this amendatory Act of the 102nd G eneral Assembly. (l-10) Each e lectricity provider shall allow net metering as set forth in this subsection for an energy storage system or vehicle s torage system energized after the effective date of this amendatory Act of the 104 th General Assembly with a nameplate capacity of not more th an 5,000 kilowatts. An energy storage system or vehicle storage system eligible for net metering under this subsection may be interconnected behind the meter of a retail customer o r at the distribution system level of an electric utility as follow s: (A) if the energy storage system or vehicle storage system is interconnected behind the meter of a retail cu stomer, in order to receive net metering under this s ubsection, the eligible customer behind whose meter t he energy storage system is interconnected must receive servi ce from an electricity provider under an hourly supply tariff, a time -of-use supply tariff, or a time-o f-use contract with an alternative retail electric supplier; or ( B) if the energy storage system or vehicle storage system is interconnected at the distribution system level of an electric utility and not behind the meter of a retail cus tomer, the energy storage system or vehicle storage system must receive service from an electricity provider as a r etail customer under an hourly supply tariff authorize d by Section 16-107, a supply tariff or contract on substantially similar terms and conditions with an alternative retail elec tric supplier, a time-of-use supply tariff, or a time-of-use supply contract with an alternative retail elect ric supplier. If the ene rgy storage system or vehicle storage system is interconnecte d behind the meter of an eligible customer, the eligible customer shall receive net metering based on hourly or time-of-u se rates in accordance with the terms of subsection (d- 5) or (f) or paragraph (2) of subsection (n) of thi s Section, as applicable to the eligible customer. If the energ y storage system or vehicle storage system is interconnected at the distribution system level of an electric utility and not b ehind the meter of a retail customer, then the energy storage system or vehicle storage system shal l receive net metering pursuant to the terms of subsectio n (f) of this Section. (m) Nothing in this Section shall affect the right of an electricity pro vider to continue to provide, or the right of a retail customer to continue to receive service pursuant to a contract for ele ctric service between the electricity provider and the re tail customer in accordance with the prices, terms, and cond itions provided for in that contract. Either the electricity provider or th e customer may require compliance with the prices, terms, and conditions of the contract. (n) On and after January 1, 2025, the net metering services descr ibed in subsections (d), (d-5), and (e) of this Section shall no longer be offered, except as to those eligible re newable electrical generating facilities for which retail cust omers are receiving net metering service under these subsecti ons at the time the net metering services under those s ubsections are no longer offered; those systems shall continue to receive net metering services described in subsect ions (d), (d-5), and (e) of this Section for the lifeti me of the system, regardless of if those retail customers change electricity providers or whether the retail customer b enefiting from the system changes. The electric utility servin g more than 200,000 customers as of January 1, 2021 is res ponsible for ensuring the billing credits continue without la pse for the lifetime of systems, as required in subsection (o). Those retail customers that begin taking net metering servic e after the date that net metering services are no longer offered under such subsections shall be subject to the provision s set forth in the following paragraphs (1) through (3) of th is subsection (n):

(1) An electricity provider shall charge or credit fo r the net electricity supplied to eligible customers or provided by eligible customers whose electric supply service is not provided based on hourly pricing in the following manner: (A) If the amount of electricity used by the customer during the monthly billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net kilowatt-hour based electricity c harges reflected in the customer's electric service rate supplied t o and used by the customer as provided in paragraph (3) of this subsection (n). (B) If the amount of electricity produced by a c ustomer during the monthly billing period exce eds the amount of electricity used by the customer during that billing period, then the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour energy or monetary credit kilowatt-hour su pply charges to the customer's subsequent bill. The customer shall choose between 1:1 kilowatt-hour or monetary credit at the time of application. For the purposes of this subsection, "kilowatt-hour supply ch arges" means the kilowatt-hour equivalent va lues for energy, capacity, transmission, and the purc hased energy adjustment, if applicable. Notwithstanding anything to the contrary, customers on payment plan s or participating in budget billing programs sha ll have credits applied on a monthly basis. The electricit y provider shall continue to carry over any excess kilo watt-hour or monetary energy credits earned an d apply those credits to subsequent billing periods. For customers with transmission or capacity charges not charged on a kilowatt-hour basis, the electricity pr ovider shall prepare a reasonable approximation of th e kilowatt-hour equivalent value and provide tha t value as a monetary credit. The electricity provider shall submit these approx imation methodologies to the Commission for review, mo dification, and approval.

(C) (Blank).

(2) An electricity provider shall charge or credit fo r the net electricity supplied to eligible customer s or provided by eligible customers whose elect ric supply service is provided based on hourly pricing in the following manner: (A) If the amount of electricity used b y the customer during any hourly period exceeds the amo unt of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied t o and used by the customer as provided in paragraph (3) of this subsection (n). (B) If the amount of electricity produced by a customer during any hourly period exceeds the amount of electricity used by the customer during that hourly pe riod, the energy provider shall calculate an energ y credit for the net kilowatt-hours produced in s uch period, and shall apply that credit as a monetary credit to the customer's subsequent bill. The value o f the energy credit shall be calculated using the same pric e per kilowatt-hour as the electric service prov ider would charge for kilowatt-hour energy sal es during that same hourly period and shall also includ e values for capacity and transmission. For customers with transmission or capacity charges not char ged on a kilowatt-hour basis, the electricity provider shall prepare a reasonable approximation of the kilo watt-hour equivalent value and provide tha t value as a monetary credit. The electricity provi der shall submit these approximation methodologies to t he Commission for review, modification, and appro val. Notwithstanding anything to the contrary, cu stomers on payment plans or participa ting in budget billing programs shall have credits applie d on a monthly basis.

(3) An electricity provider shall provide electric service to el igible customers who utilize net metering at non-disc riminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly char ges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall ch arge the customer for the net electricity supplied to a nd used by the customer according to the terms of the cont ract or tariff to which the same customer would be as signed or be eligible for if the customer was not a net met ering customer. An electricity provider shall not charge ne t metering customers any fee or charge or require additio nal equipment, insurance, or any other requirements not s pecifically authorized by interconnection standards author ized by the Commission, unless the fee, charge, or other re quirement would apply to other similarly situated cus tomers who are not net metering customers. The customer remains r esponsible for the gross amount of delivery services charge s, supply-related charges that are kilowatt based, and all taxes and fees related to such charges. The cust omer also remains responsible for all taxes and fees that would otherwise be applicable to the net amount of elect ricity used by the customer. Paragraphs (1) and (2) of this sub section (n) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, term s, and conditions for the provision of net metering service, including, but not limited to, the provision of th e appropriate metering equipment for non-resi dential customers. Nothing in this paragraph (3) shall be interpreted to mandate that a utility that is only required to p rovide delivery services to a given customer must al so sell electricity to such customer. (o) Within 90 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric utility subje ct to this Section shall file a tariff, which shall, consistent with the provisions of this Section, propose the te rms and conditions under which a customer may participate in net metering. The tariff for electric utilities ser ving more than 200,000 customers as of January 1, 2021 shall also provide a streamlined and transparent bill credit ing system for net metering to be managed by the electric util ities. The terms and conditions shall include, but are no t limited to, that an electric utility shall manage and ma intain billing of net metering credits and charges regard less of if the eligible customer takes net metering under an electric utility or alternative retail electric supplier. The electric utility serving more than 200,000 customers as of January 1, 2021 shall process and approve all net meter ing applications, even if an eligible customer is served by an alternative retail electric supplier; and the utility sha ll forward application approval to the appropriate alternati ve retail electric supplier. Eligibility for net meteri ng shall remain with the owner of the utility billing ad dress such that, if an eligible renewable electrical generati ng facility changes ownership, the net metering eligibilit y transfers to the new owner. The electric utility serving m ore than 200,000 customers as of January 1, 2021 shall manage net metering billing for eligible customers to ensure full crediting occurs on electricity bills, including, but not limit ed to, ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if a n eligible customer switches from an electric utility to a lternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a va lid billing address. All transfers referenced in the prec eding sentence shall include transfer of all banked credit s. All electric utilities serving 200,000 or fewer custome rs as of January 1, 2021 shall manage net metering billing for eligible customers receiving power and energy service fro m the electric utility to ensure full crediting occurs on el ectricity bills, ensuring net metering crediting begins upon co mmercial operation date, net metering billing transfers imme diately if an eligible customer switches from an electr ic utility to alternative retail electric supplier or vic e versa, and net metering billing transfers between owner ship of a valid billing address. Alternative retail electric s uppliers providing power and energy service to eligible cu stomers located within the service territory of an electric uti lity serving 200,000 or fewer customers as of January 1, 2021 shall manage net metering billing for eligible customer s to ensure full crediting occurs on electricity bills, includ ing, but not limited to, ensuring net metering crediting begins upon commercial operation date, net metering billing tr ansfers immediately if an eligible customer switches from a n electric utility to alternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a valid billing address. (S ource: P.A. 102-662, eff. 9-15-21.) (220 ILCS 5/16-107.6) Sec. 16-107.6. Distributed generation and st orage rebate. (a) In this Section: "Additive services" means the services that distributed energy resources provide to the energy system and soc iety that are described in Section 16-107.9 not (1) already included in the base rebat es for system-wide grid services; or (2) otherwise alread y compensated. Additive services may reflect, but shall not be lim ited to, any geographic, time-based, performance-based, and other benefits of distributed energy resources, as well as the present and future technological cap abilities of distributed energy resources and presen t and future grid needs. " Distributed energy resource" means a wide range of technol ogies that are located on the customer side of the customer's e lectric meter, including, but not limited to, dis tributed generation, energy storage, electric vehicle s, and demand response technologies. "Energ y storage system" means commercially available technology tha t is capable of absorbing energy and storing i t for a period of time for use at a later time, including, but not limited to, electrochemical, thermal, and electromec hanical technologies, and may be interconnected behind the customer's m eter or interconnected behind its own meter. "Energy s torage system" also includes electric vehicle storage systems connected to the di stribution grid and capable of discharging to the dis tribution grid. "Smart inver ter" means a device that converts direct current into alternating current and meets the IEEE 1547-2018 equipment standards. Until devices that meet the IEEE 1547-2018 st andard are available, devices that meet the UL 1741 SA standard are acceptable. "Subscriber" ha s the meaning set forth in Section 1-10 of the Illinois P ower Agency Act. "Subsc ription" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act. "System-wide grid services" means the benefits that a distributed ene rgy resource provides to the distribution grid for a period of no less than 25 years. System-wide grid se rvices do not vary by location, time, or the performance characte ristics of the distributed energy resource. System-wid e grid services include, but are not limited to, avoided or deferred distribution capacity costs, resilience and reli ability benefits, avoided or deferred distribution operation and maintenance cos ts, distribution voltage and power quality benefits, and li ne loss reductions. "Threshol d date" means the date 2 years after the effective date of this amendatory Act of the 10 4th General Assembly December 31, 2024 or the date on which the utility's tariff or tariffs authorized by Section 16-107.9 setting the new compensa tion values established under subsection (e) take effect, whichever is later. (b) An electric utility that serves more than 200,000 cus tomers in the State shall file a petition with the Commis sion requesting approval of the utility's tariff to provide a reba te to the owner or operator of distributed generation , including third-party owned systems, that meets the following criteria: (1) has a nameplate generating capacity no greater than 5,000 kilowatts and is primarily used to offset a customer 's electricity load; (2) is loca ted on the customer's side of the billing meter and f or the customer's own use; (3) is interconnected to electric distrib ution facilities owned by the electric utility under rules adopted by the Commission by means of one or more inverters or smart inverters requi red by this Section, as applicable. For pur poses of this Section, "distributed generation" shall satisfy the definition of distributed renewable energy generation device set forth in Section 1-10 of the Illinois Power Agen cy Act to the extent such definition is consistent with t he requirements of this Section. In addit ion, any new photovoltaic distributed generation that is installed af ter June 1, 2017 (the effective date of Public Act 99-906) must be installed by a qualified person, as def ined by subsection (i) of Section 1-56 of the Illi nois Power Agency Act. The tariff shall include a base rebate that compensates distributed generati on for the system-wide grid services associated with distributed g eneration and, after the proceeding described in subsection (e) of this Section, an addit ional payment or payments for any the additive services identified by the Commission under Section 1 6-107.9. The distributed generati on and storage tariff shall provide that the smart inverter or smart inverters associated with the distributed generation shall provide autonomous response to grid conditio ns through its default settings as approved by the Commissio n. Default settings may not be changed after the execution of t he interconnection agreement except by mutual agreement betwe en the utility and the owner or operator of the distributed gen eration. Nothing in this Section shall negate or s upersede Institute of Electrical and Electronics Engineers e quipment standards or other similar standards or requirements. The tariff shall not limit the ability of the smart i nverter or smart inverters or other distributed energy resour ce to provide wholesale market products such as regulati on, demand response, or other services, or limit the abi lity of the owner of the smart inverter or the other distributed energy r esource to receive compensation for providing those wholesal e market products or services. (b-5) Within 30 days after the effective date of this amendatory A ct of the 102nd General Assembly, each electric public utility with 3,000,000 or more retail customers shall file a tariff with the Commission that further compensates any retail customer that installs or has installed photovoltaic fac ilities paired with energy storage facilities on or adjacen t to its premises for the benefits the facilities provide to the distribution grid. The tariff shall provide that, i n addition to the other rebates identified in this Sectio n, the electric utility shall rebate to such retai l customer (i) the previously incurred and future costs of installing interconnection facilities and related infrast ructure to enable full participation in the PJM Interconn ection, LLC or its successor organization frequency regulati on market; and (ii) all wholesale demand charges incurred aft er the effective date of this amendatory Act of the 102nd Ge neral Assembly. The Commission shall appr ove, or approve with modification, the tariff within 120 days afte r the utility's filing. To be eligibl e for a rebate described in this subsection (b-5 ), the owner or operator of the distributed generation shall p rovide proof of participation in the frequency regulation market . Upon providing proof of participation, the retail customer sh all be entitled to a rebate equal to the cost of the interconnection facilities paid to ComEd, regardless of whet her the retail customer would have incurred the intercon nection costs in the absence of participating in the frequ ency regulation market, plus the cost of software, telecommu nications hardware, and telemetry paid to enable communic ation with PJM for purposes of participating in the frequency regulation market. A utility providing rebates described in thi s subsection (b-5) shall be entitled to recover the costs of the rebates as provided for in subsection (h) of this Sectio n. To the extent the electric utility's tariff shall be modifi ed to comply with this subsection (b-5), it shall file a revised tariff with the Commission within 120 days after t he effective date of this amendatory Act of the 104th Genera l Assembly, and the Commission shall approve, or approve with modification, the tariff within 240 days after the utili ty's filing. (c) The proposed tariff authorized by subsection (b) of this Section shall include the following participation terms for rebates to be applied under this Section for distributed gene ration that satisfies the criteria set forth in subsection (b) of this Section: (1) The owner or opera tor of distributed generation or distributed storage that services customers not eligible for net meteri ng under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act ma y apply for a rebate as provided for in this Section. The Until the threshold date, the value of the rebate shall be $250 per kilowatt of na meplate generating capacity, measured as nominal DC p ower output, of that customer's distributed generation. To the ext ent the distributed generation also has an associated energy storage, then until the threshold date for systems o ther than community renewable generation projects paired with an energy storage syst em, the energy storage system shall be separately compensated wi th a base rebate of $250 per kil owatt-hour of nameplate capacity. To the extent that a community renewable generation proje ct is paired with an energy storage system, the energy storage system sh all be separately compensated with a rebate of $250 per ki lowatt-hour of nameplate capacity. Any distributed g eneration device that is compensated for storage in this subsection (1) after the effective date of this amendatory Act of the 104th Ge neral Assembly before the threshold date shall participate in one or more programs authorized by paragraph (1) of subsection (e). Compensation determined through the Multi-Year Integrated G rid Planning process that are designed to meet peak reduction and flex ibility. After the threshold date, the value of the base rebate and additional compensation for any additive services shall be as deter mined by the Commission in the proceeding described in Section 16-107.9 subsection (e) of this Section, provided that the value of the base rebate for system-wide grid services shall not be lo wer than $250 per kilowatt of nameplate generating capacity of distribute d generation or community renewable generation project. To the extent that an electric utili ty's tariffs are inconsistent with the requirements of this paragraph (1) as modified by this amendatory Act of the 10 4th General Assembly, the electric utility shall, within 60 days after the effective date of this amendatory Act of the 104th General Assembly, file modi fied tariffs consistent with the requirements of this para graph (1). ( 2) The owner or operator of distributed generation that, befor e the threshold date, would have been eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act and that has not previously received a distri buted generation rebate, may apply for a rebate as provided for in this Section. Until December 31, 2029 the threshold date, the value of the base reb ate shall be $300 per kilowatt of nameplate generating capacity, m easured as nominal DC power output, of the distributed generation. On or after January 1, 2030, the value of the base rebate shall be $250 per kilowatt of nameplate gen erating capacity, measured as nominal DC power outpu t, of the distributed generation. The own er or operator of distributed generation that, before the threshold da te, is eligible for net metering under subsection (d), (d -5), or (e) of Section 16-107.5 of this Act may apply for a base rebate for an associated energy s torage device behind the same retail customer meter as the distributed generation, regardless of whether the distributed generation applies for a reb ate for the distributed generation device. An T he energy storage system, whether or not paired with distributed generation, shall be separ ately compensated at a base payment of $300 per kilowatt-hour of nameplate capacity until the threshold date. Any distributed generation device that is compensated for storage in this subsection (2) has the option to before the threshold date shall par ticipate in either an a peak time rebate program, hourly pr icing program, or time-of-use rate program and any distributed generati on device that is compensated for storage in this subsect ion (2) after the effective date of this amendatory Act o f the 104th General Assembly shall participate in a scheduled dispatch program set forth in paragraph (1) of subsection (e) when it becomes available of fered by the applicable electric utility. Compensation After the threshold date, the v alue of the base rebate and additional compensation fo r any additive services or other programs shall be as determined by the Commi ssion in the proceeding described in Section 16-107.9 subsection (e) of this Sec tion, provided that, prior to December 31, 2029, the va lue of the base rebate for system-wide services shall not be lower than $300 per kilowatt of nameplate generati ng capacity of distributed generation, after which it sha ll not be lower than $250 per kilowatt of nameplate capac ity. The eligibility of energy storage devices that ar e interconnected behind the same retail customer meter as the distributed generation shall not be limited to energy storage device s interconnected after the effective date of this ame ndatory Act of the 103rd General Assembly. T o the extent that an electric utility's tariffs are inconsistent with the requirements of this paragraph (2) as modified by this amendatory Act of the 104th General Assembly this amendatory Act of the 103rd General Assemb ly, such electric utility shall, within 60 30 days, file modified tariffs consistent with the requirements of this paragraph (2). (3) Upon approval of a rebate application submitted under this subsection (c), the retail customer shall no longer be entitled to receive any delivery service credits for the excess electricity generated by its facility and shall be su bject to the provisions of subsection (n) of Section 16-107.5 of this Act unless the owner or operator receives a rebate o nly for an energy storage device and not for the distrib uted generation device. (4) To be eligible for a rebate described in this sub section (c), the owner or operator of the distributed generation must have a smart inverter installed and in operation on the dist ributed generation. (5) The owner or operator of any distributed gen eration or distributed storage system whose electric service h as not been declared competitive under Section 16- 113 as of July 1, 2011 or the owner or operator of a comm unity renewable generation project participating i n the Adjustable Block Program as a community-dri ven community solar project as defined in item (v) of subparagrap h (1) of paragraph (K) of subsection (c) of Section 1-75 of the Illinois Power Agency Act and that has an i nterconnection agreement dated after the effective date of this amendatory Act of the 104th General Assembly shall be eligible for an additional payment or payments to the app licable rebate under paragraphs (1) or (2) of this subsecti on (c) in an amount set by tariff and approved by the Commis sion if located in an equity investment eligible c ommunity, as defined in Section 1-10 of the Illinois Po wer Agency Act, at the time the interconnection agre ement is signed. ( d) The Commission shall review the proposed tariff authorize d by subsection (b) of this Section and may make changes to t he tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, su bject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after th e utility files its tariff. Upon the effective date of this am endatory Act of the 102nd General Assembly, an electr ic utility shall file a petition with the Commission to amend and update any existing tariffs to comply with subsections (b) and (c). (e) By no later than June 30, 2026 June 30, 2023, the Commission shall establish a scheduled dispatch virtual power plant progr am in which customers that own or operate an energy storage sys tem that receive a rebate for the distributed storage portion under paragraphs (1 ) and (2) of subsection (c) are required to participate

open an independent, statewide investiga tion into the value of, and compensation for, distributed energy resources. The Commission shall conduct the investigatio n, but may arrange for experts or consultants independent of the utilities and selected by the Commission to assist with the investigation. The cost of the investigation sha ll be shared by the utilities filing tariffs under subsection (b) of this Section but ma y be recovered as an expense through normal ratemaking procedures. (1) The scheduled dispatch virtual power plant program sh all require an enrollment period of 5 years and requi re each participating system to commit to dispatch each wee kday during the months of June, July, August, and September from 4 p.m. to 6 p.m. for systems interconnected behind th e meter of a retail customer and from 4 p.m. to 7 p.m. for s ystems interconnected on the distribution system of an elec tric utility and not behind the meter of a retail customer. Upon petition by the applicable electric utility or on its own motion, the Commission may approve different dis patch schedules provided that dispatch events do not excee d 80 days and shall not exceed 2 hours for systems in terconnected behind the meter of a retail customer or 3 hour s for systems interconnected on the distribution system of an electric utili ty and not behind the meter of a retail customer. The Commission shall ensure that the investigation includes, at minimum, diverse sets of stakeholders; a review of best practices in calcula ting the value of distributed energy resource benefits; a review of the full value of the distributed energy resour ces and the manner in which each component of that va lue is or is not otherwise compensated; and assessmen ts of how the value of distributed energy resources may ev olve based on the present and future technological capabilities of distrib uted energy resources and based on present and future grid needs. (2) T he scheduled dispatch virtual power plant program shall be open to all customer classes with eligible energy stora ge systems and shall measure performance based on combined expo rt of paired resources if the eligible device is inver ter-based renewables paired with storage through a t least December 31, 2030 and until such time as the Commission approves and the utility implements a tariff under subs ection (d) of Section 16-107.9 of this Act, at which time such customers shall be transitioned to that tariff in a manner prescribed in the tariff. The scheduled dispatch virtual power plant program shall be required for all community renewable generation projects paired with an energy storage sys tem without regard to the threshold date. The Commission's final order concluding this in vestigation shall establish an annual process and formula for the compensation of distributed generation and energy storage systems, and an initial set of inputs for that form ula. The Commission's final order concluding this inves tigation shall establish base rebates that compensate distribu ted generation, community renewable generation projects an d energy storage systems for the system-wide grid s ervices that they provide. Those base rebate values sha ll be consistent across the state, and shall not vary by customer, customer class, customer location, or any ot her variable. With respect to rebates for distributed gen eration or community renewable generation project s, that rebate shall not be lower than $250 per kilowatt o f nameplate generating capacity of the distributed generat ion or community renewable generation project. The Comm ission's final order concluding this proceeding shall al so direct the utilities to update the formula, on an annual ba sis, with inputs derived from their integrated grid plans developed pursuant to Section 16-105.17. The b ase rebate shall be updated annually based on the annual u pdates to the formula inputs, but, with respect to re bates for distributed generation or community ren ewable generation projects, shall be no lower than $250 p er kilowatt of nameplate generating capacity of the distributed generation or community renewable generation project. (3)

Compensation shall be set by the Commissi on but shall not be less than $10 per kilowatt of averag e dispatch during identified hours, paid to enrolled customers or project owners at end of program year. For di stributed generation interconnected to an electric uti lity's distribution system and not behind the meter of a retail customer, dispatch to determine compensation shall be measured at point of interconnection. For di stributed generation and storage interconnected behind th e meter of a retail customer, dispatch to determine compensation shall be measured at the inverter connected to the storage device. The Commission shall al so determine, as a part of its investigation under this sub section, whether distributed energy resourc es can provide any additive services. Those additive services may include services that are provided through utility-controlled responses to grid conditions. If the Comm ission determines that distributed energy resources can p rovide additive grid services, the Commission shall determi ne the terms and conditions for the operation and comp ensation of those services. That compensation shall be abo ve and beyond the base rebate that the distributed en ergy generation, community renewable generation project an d energy storage system receives. Compensation for additive services may vary by location, time, performance characteristics, technology types, or other variables. (4) No later than June 1, 2026, each public utility s hall file an initial scheduled dispatch virtual power plant tariff. The Commission shall approve, or approve with m odifications, the initial scheduled dispatch virtual power plant tariff for ea ch utility not later than June 30, 2026. The Commission shall ensure that compensation for di stributed energy resources, including base rebates and any payments for additive services, shall reflect all reasonably known and measurable values of the dist ributed generation over its full expected useful life. Comp ensation for additive services shall reflect, but shall not be limited to, any geographic, time-bas ed, performance-based, and other benefits of distribu ted generation, as well as the present and future technological capabilities of distributed energy resources and present and future grid needs. (5) The Commission, by its own motion or by petition b y an electric utility, may establish other additive services prog rams in addition to the virtual power plant program under Section 16-107.9. Nothing in this Section is inte nded to preempt or delay the implementation of other uti lity programs for devices that are not a part of the scheduled dispatch virtual power plant program that the Commission o r utility may propose or require. The Commission shall consider the electric utility's integrated grid plan developed pursuant to Secti on 16-105.17 of this Act to help identify the value of distributed energy resources for the purp ose of calculating the compensation described in this subsection. (6) No later than December 31, 2028, the uti lities shall file with the Commission a report that includes information on the following: (A) the number of participants in the scheduled dispatch program; (B) imp acts to energy supply prices and wholesale market activiti es; (C) impacts on distribution system investments and planning ; and (D) any potential pathways by which the virtual powe r plan program described in Section 16-107.9 ma y be designed to capture wholesale market value through par ticipation in the wholesale market and apply that wholesale market revenue to re duce utility distribution or electric supply rates for cu stomers. The Commission sh all determine additional compensation for distributed ener gy resources that creates savings and value on the distri bution system by being co-located or in close proximity to e lectric vehicle charging infrastructure in use by medium-duty and heavy-duty vehicles, primarily serving environmental justice communities, as outlined in the utility integrated grid planning process under Section 16-105.17 of this Act. No later than 60 days after the Commission enters its final order un der this subsection (e), each utility shall file its updated ta riff or tariffs in compliance with the order, including new tariff s for the recovery of costs incurred under this subsection ( e) that shall provide for volumetric-based cost recovery, and the Commission shall approve, or approve with modification, the tariff or tariffs within 240 days after the utili ty's filing. ( f) Notwithstanding any provision of this Act to the contrary, the ow ner or operator of a community renewable generation project as defined i n Section 1-10 of the Illinois Power Agency Act whether or not a paired energy storage system or the owner or ope rator of an energy storage system that is eligible for net metering unde r subsection (l-10) of Section 16-107.5 shall also be eligible to apply for the rebate described in this S ection. The owner or operator of the community renewable gen eration project whether or not a paired energy storage system or the owner or operator of an energy storage system that is eligib le for net metering under subsection (l-10) of Section 1 6-107.5 may apply for a rebate only if the owner or oper ator, or previous owner or operator, of the community renewa ble generation project whether or not a paired energy storage system or the owner or operator of an energy storage system that is eligible for net metering under subsection (l-10) of Section 16-107.5 has not already submitted an ap plication, and, regardless of whether the subscriber is a residential or non-residential customer, may be all owed the amount identified in paragraph (1) of subsection (c) applicable on the date that the application i s submitted. (g) The owner of a distribu ted storage system, whether or not paired with distributed generation, the distributed generation or community rene wable generation project may apply for the reb ate or rebates approved under this Section at the time of exec ution of an interconnection agreement with the distribution utility a nd shall receive the value available at that time of executio n of the interconnection agreement, provided the project reaches mechanical completion within 24 months afte r execution of the interconnection agreement. If the project has not reached mechanical completion within 24 months after execution, the owner may reapply for the rebate or rebates a pproved under this Section available at the time of application and shal l receive the value available at the time of application. The utility shall issue the rebate no later than 60 days after the project is energized. In the event the ap plication is incomplete or the utility is otherwise unable to calculate the payment based on the information provided by t he owner, the utility shall issue the payment no later than 60 d ays after the application is complete or all requested information is received. (h) An electric utility shall recover from its retail customers all of the costs of the re bates made under a tariff or tariffs approved under subsection (d) of this Section, including, but not limited to, the value of the rebates and all costs incurred by the utility to comply with and implement subsections (b), (b-5), and (c), and ( e) of this Section, but not including costs incurred by the utility to comply with and implement subsect ion (e) of this Section, consistent with the following provisions: ( 1) The utility shall defer the full amount of its costs as a regu latory asset. The total costs deferred as a regulatory asse t shall be amortized over a 15-year period. The unam ortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the t otal of the unamortized balance of the regulatory assets, l ess any deferred taxes related to the unamortized balance, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end capit al structure, the utility's actual cost of debt for the applicable calendar year and a cost of equity, which shall be equal to the baseline cost of equity approved by the Commission for the utility's electric distribution r ates case effective during the applicable year, whether those rates are set pursuant to Section 9-201, subparagra ph (B) of paragraph (3) of subsection (d) of Section 16-108.18, or an y successor electric distribution ratemaking paradigm calculated as the sum of (i) the average for the applicable calendar year of the monthly average yiel ds of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve Sy stem in its weekly H.15 Statistical Release or successor p ublication; and (ii) 580 basis points, including a revenue conversion factor calculated to recover or refund all additional income t axes that may be payable or receivable as a result of that return.

When an electric utility creates a regulatory asset unde r the provisions of this paragraph (1) of subsection (h), the costs are recovered over a period during which cus tomers also receive a benefit, which is in the public inte rest. Accordingly, it is the intent of the General Assem bly that an electric utility that elects to create a regul atory asset under the provisions of this paragraph (1) s hall recover all of the associated costs, including, but n ot limited to, its cost of capital as set forth in this par agraph (1). After the Commission has approved the prudence and reasonableness of the costs that compris e the regulatory asset, the electric utility shall be perm itted to recover all such costs, and the value and recovera bility through rates of the associated regulatory a sset shall not be limited, altered, impaired, or reduced . To enable the financing of the incremental capital expen ditures, including regulatory assets, for electric utilit ies that serve less than 3,000,000 retail customers but more tha n 500,000 retail customers in the State, the utility's a ctual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% o f the total capital structure shall be deemed reasonable an d used to set rates.

(2) The utility, at its election, may recover all of the costs as part of a filing for a general increase in rates under Article IX of this Act, as part of an annual filing to update a performance-based formula r ate under Section 16-108.18 subsection (d) of Section 16-108.5 of this Act , or through an automatic adjustment clause t ariff, provided that nothing in this paragraph (2) permits the double recovery of such costs from customers. If the utility elects to recover the costs it incurs under subsections (b), (b-5), and (c), and (e) through an au tomatic adjustment clause tariff, the utility may file it s proposed tariff together with the tariff it fi les under subsection (b) of this Section or at a later time. The proposed tariff shall provide for an annual reco nciliation, less any deferred taxes related to the reconcil iation, with interest at an annual rate of return equal to the utility's weighted average cost of capital a s calculated under paragraph (1) of this subsection (h), i ncluding a revenue conversion factor calculated to recove r or refund all additional income taxes that may be payab le or receivable as a result of that return, of the revenue requirement reflected in rates for each calendar ye ar, beginning with the calendar year in which the utili ty files its automatic adjustment clause tariff under th is subsection (h), with what the revenue requirement w ould have been had the actual cost information for the app licable calendar year been available at the filing date. The Commission shall review the proposed tariff and ma y make changes to the tariff that are consistent with t his Section and with the Commission's authority under Art icle IX of this Act, subject to notice and hearing. Follo wing notice and hearing, the Commission shall issue an ord er approving, or approving with modification, such tariff no later than 240 days after the utility files its tari ff. (i) (Blank). An electric utility shall recover from its retail custome rs, on a volumetric basis, all of the costs of the rebate s made under a tariff or tariffs placed into effect under subse ction (e) of this Section, including, but not limited to, t he value of the rebates and all costs incurred by the utility to comply with and implement subsect ion (e) of this Section, consistent with the following provisions: (1) The utility may defer a portion of its costs as a reg ulatory asset. The Commission shall determine the por tion that may be appropriately deferred as a regulatory ass et. Factors that the Commission shall consider in determ ining the portion of costs that shall be deferred a s a regulatory asset include, but are not limited to: (i ) whether and the extent to which a cost effectively defer red or avoided other distribution system operating costs o r capital expenditures; (ii) the extent to which a cost provides environmental benefits; (iii) the extent to which a cost improves system reliability or resilience; (iv) th e electric utility's distribution system plan developed pur suant to Section 16-105.17 of this Act; (v ) the extent to which a cost advances equity principles ; and (vi) such other factors as the Commission deem s appropriate. The remainder of costs shall be deemed an operating expense and shall be recoverable if found prudent and reasonable by the Commission. Th e total costs deferred as a regulatory asset shall be amor tized over a 15-year period. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the una mortized balance of the regulatory assets, less any defer red taxes related to the unamortized balance, at an annual r ate equal to the utility's weighted average cost of c apital that includes, based on a year-end capital str ucture, the utility's actual cost of debt for the app licable calendar year and a cost of equity, which shall be calculated as the sum of: (I) the average for the applicabl e calendar year of the monthly average yields of 30-y ear U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 St atistical Release or successor publication; and (II) 5 80 basis points, including a revenue conversion factor calcu lated to recover or refund all additional income t axes that may be payable or receivable as a result of that return. (2) The utility may recover all of the costs through an auto matic adjustment clause tariff, on a volumetric basis. The utility may file its proposed cost-recovery tariff to gether with the tariff it files under subsection (e) of this Section or at a later time. The proposed ta riff shall provide for an annual reconciliation, l ess any deferred taxes related to the reconciliation, wit h interest at an annual rate of return equal to the util ity's weighted average cost of capital as calculated under paragraph (1) of this subsection (i), including a revenue conversion factor calculated to recover or ref und all additional income taxes that may be payable or receivable as a result of that return, of the revenue requirement reflected in rates for each calendar year, b eginning with the calendar year in which the utility fil es its automatic adjustment clause tariff under th is subsection (i), with what the revenue requirement w ould have been had the actual cost information for the app licable calendar year been available at the filing date. The Commission shall review the proposed tariff and ma y make changes to the tariff that are consistent with t his Section and with the Commission's authority under Art icle IX of this Act, subject to notice and hearing. Follo wing notice and hearing, the Commission shall issue an ord er approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff. (j) No late r than 90 days after the Commission enters an order, or ord er on rehearing, whichever is later, approving an electric ut ility's proposed tariff under this Section, th e electric utility shall provide notice of the availability of r ebates under this Section. (k) No later than January 1, 2030, the utilities shall file with the Commission a report that i ncludes: (1) the number and geographic dis tribution of participants receiving rebates pursuant to this Sect ion; (2) impacts to energy supply prices and wholesale market activiti es; (3) impacts on distribution system investments and pla nning; and (4) any other values deemed relevant by the Commission. (l) Upon p etition by the applicable electric utility or on its own motion , the Commission may adjust rebate levels for new customers an d make other appropriate changes to the rebate program in a man ner that is consistent with the State's clean energy goals and the public interest. (Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27 -22; 103-1066, eff. 2-20-25.) (220 ILCS 5/16-107.8 new) Sec. 16-107.8. Time-of-use pricing. (a) The General Asse mbly finds that market-based time-of-use r ates and pricing plans can reduce costs and help the State achieve its energy policy goals by improving load shape, enc ouraging energy conservation, and shifting usage away from periods where fossil fuels are used. By providing consumers information relating the costs of service to the time of energy usag e, time-of-use rates can help consumers reduce energy bills by using electricity w hen it is less costly. (b ) An electric utility shall offer at least one market-ba sed rate option for eligible retail customers, including, but not li mited to, customers participating in net electricity met ering under the terms of Section 16-107.5, who choose to take power and energy supply service from the utility. The provisions o f Section 16-107.5 notwithstanding, energy credits for net-metering customers shall be valued at the same price per kilowatt-hour as the price per kilowatt-hour that the electric service provider would charge for kilowatt-hour energy sal es during the same hourly time-of-use period. The u tility shall file its time-of-use rate tariff no l ater than 120 days after the effective date of this amendatory Act of the 104th General Assembly. The tariff or tariffs shall be subject to the following requirements:

(1) If more than one tariff is proposed, at least one tariff shall include at least the following 3 time blocks:

(A) a peak time block of consecutive hours best reflecting the average consec utive highest system power and energy use per hour in a calendar day; (B) an off-peak time block, which reflects th e next highest system power and energy demands in a calendar day; and (C) a super-off -peak time block, defined as all other hours in a calendar day. Time blocks shall reflect the hour and weekday for which the costs of services o utlined in paragraphs (2) and (3) of this subsection (b) are charged. (2) The tariff or tariffs shall describe the methodol ogy for determining the prices for each time block using the applicable average zonal and capacity prices of the PJ M Interconnection, LLC (PJM) and the Midcontinent Independent System Operator (MISO) and describe the manner in which customer s who elect time-of-use pricing will be provided wi th the time blocks, associated block pricing, and day-ahead energy prices. Costs for electric capacity shall be determined in a manner that rec overs the capacity obligation costs incurred by the electric utility.

(3) T he time-of-use rate shall include t he costs of transmission services and the charges for ne twork integration transmission service, transmission enha ncement, and locational reliability, as these terms a re defined in the PJM and MISO Open Access Transmission Tar iffs and manuals. If the Open Access Transmission Tariff o r the manuals subsequently rename those terms, the services ref lected under those terms shall continue to be included in the time-of-use rate described in this paragraph (3) . (4) Adjustments to the charges set by the tariff may b e made on a monthly basis and adjustments to the time blocks may be made on an annual basis. A utility sha ll submit to the Commission, through a supplemental informa tion sheet, a tariff schedule. Customers shall be provided at l east 2 weeks advance notice of any changes to charges or time blocks.

(5) A purchased energy adjustment shall be calculated t o fully recover costs to supply power and energy. A utility shall procure power and energy in the applicable d ay-ahead market. (c ) The Commission shall approve or approve with modifications th e tariff or tariffs after notice and he aring. A proceeding under this subsection (c) may not exceed 240 d ays in length. (d) An electric utility shall submit an annual report to th e Commission no later than April 1 of each year that desc ribes the operation and results of the rate option, including information concerning the number and types of customers using the rate option, changes in customers' energy use patterns, an assessment of the value of the rate option to both partic ipants and nonparticipants, and recommendations concerning modification of the rate option and the tariff or tariffs filed under this Sectio n. The report shall be made available to the public on the Com mission's website. (e) Once a tariff or tariffs has been in effect, the Commi ssion may, upon complaint, petition, or its own initiative, open a proceeding to investigate whether changes or modificati ons, consistent with the requirements of this Section, to the tariff or tariffs, rate option administration, or any other rate option element is necessary to achieve the goals described in subsection (a). Such a proceeding may no t last more than 180 days from the date upon which the investi gation was opened. (f) A n electric utility shall be entitled to recover prudent and reasonable c osts incurred in complying with this Section from its eligible re tail customers. (g) An el ectric utility's tariff or tariffs filed under this Section shall be subject to the provis ions of Article IX as long as such provisions do not conflict wi th this Section. (h) This Section does not apply to an electric utility that pro vides service to 100,000 or fewer customers. (220 ILCS 5/16-107.9 new) Sec. 16-107.9. Virtual power plant program. (a) As used in this S ection: "Aggregato r" means a third-party entity that participates in t he program, other than the electric utility or its affiliate, that (i) represents and aggregates the load of participating c ustomers who collectively have the ability to deploy 100 kilow atts or more of deployment of eligible de vices and (ii) is responsible for performance of the aggregation in the progra m. "Battery" means a behind-the-meter energy storage device and associated equipment that operate together to fulfill program requirements.

"Commission" means the Illinois Commerce Commission. "Customer" means an active electric service account holder of a utility. "Direct pa rticipant" means a customer that enrolls in the program directly w ith the utility, rather than participating in the program through an aggregator. "D istributed energy resource" has the meaning set forth in Section 1 6-107.6. "Distribut ed energy resources management system" means a platform tha t may be used by distribution system operators or utilities to integra te grid resources, such as distributed energy resources, into system op erations. "Eligible dev ice" means a customer or third party-owned distributed e nergy resource that satisfies the requirements for participa tion in the program as specified in the relevant program ri der. "Eligible device" also means any device that can be co ntrolled to respond to pricing, provide services, including decrea se peak electricity demand or shift demand from pea k to off-peak periods, or inject power to the grid. "Eligible devi ce" includes, but is not limited to, behind-the-me ter energy storage systems, smart thermostats, electric vehicle batteries, including fleets, and dist ributed renewable energy devices paired with one or more energy storage systems. "Emerge ncy event" means an event called by the utility with fewer tha n 24 hours notice. "Energy storag e system" has the meaning set forth in subsection (a) of Section 16 -107.6. "Enro lled customer" means a customer that part icipates in the program through either an aggregator or as a dire ct participant. "Enrolled device" me ans an enrolled customer's eligible device, as specified in t he relevant tariff. "Enter prise distributed energy resources management system" means a p latform operated by the electric utility that interfaces wit h a grid-edge distributed energy resources management system to integrate distributed energy resources into utility electric system opera tions. "Grid-ed ge distributed energy resources management system" means a platform owned by a party other than the electric utility that may be used to integrate distributed ener gy resources. "Grid even t" means a grid condition for which the utility schedules or remotely dispatches enrolled device s to respond to, as specified in the grid service opportunities for each tariff. "Grid servic e" means a capacity, energy, or ancillary service that supports gr id operations. "Participatin g customer" means an aggregator or a direct retail customer, as defined in Section 16-102, with one or m ore eligible devices. "Performance payment" means a payment made to the participant based on the performance of an enrolled device providing a grid service duri ng a grid event. "Perfor mance payment rate" means the compensation rate p aid to participants for providing a particular grid service during a grid event. "Smart inverter" has the meaning set forth in subsection (a) of Section 16-107.6. "Upfront payment" means a one-time payment made a t the time of enrollment. "Virtua l power plant" means an aggregation of behind-the-meter distributed energy resources operated in coordination to provide one or more grid services. (b) The General Assembly finds that : (1) virtual power plants are dynamic load manage ment and energy supply resources that can support grid operations, red uce ratepayer costs, and achieve other important public policy goal s;

(2) virtual power plants can reduce deman d for grid supplied electricity during peak periods, shif t electricity consumption out of peak periods, make rene wable energy generated during off-peak periods avai lable for use during peak periods, supply energy to th e grid at desired times, provide frequency regulation, volt age support, and other ancillary services, reduce strai n on the distribution system, manage localized peaks, improv e system resiliency and reliability, and provide other grid services ; (3) virtual power plants can facilitate and optimize the utilization of electrical generation from wind and solar energy to help utilities inc rease hosting capacity and integrate more renewable energy r esources; (4) virtual power plants can reduce costs to ratep ayers by utilizing customer-sited resources to provide grid services, avoiding or reducing reliance on fossi l-fuel fired peaker plants, avoiding or deferrin g the need to construct new and more costly grid scale reso urces, optimizing the use of existing assets, and avoiding or deferring dist ribution and transmission system upgrades and other grid inves tments; (5) virtual power plants can promote equity by re ducing costs for all ratepayers, expanding access to distribu ted energy resources among low-income and moder ate-income customers through improved distributed energy re source finance ability, and providing other important co-benefits, including reduction in emissions of gr eenhouse gases and other pollutants, especially in environmental justice and oth er disadvantaged communities that host fossil fuel generation plants ; (6) the United States Department of Energy estimates th at the United States could deploy 80 to 160 gigawatts of virtual power plants by 2030, a tripling of current level s, to support the rapid electrification of vehicles an d homes and provide on the order of $10,000,000,000 in ratepayer savings annually. The deployment of virtual power plants can prov ide energy cost savings and other benefits to the people of Illinois ; (7 ) there are significant barriers to deployment and oper ation of virtual power plants, including the need f or statutory and regulatory guidance and support, greater consistency in virtual power plant programs across regu latory jurisdictions, and for utility commitments to incorporate the use of virtual power plants into system operations and long-term resource planning ; (8) it i s in the public interest to advance customer choice and leverage the expertise of private, non-utility entities to advance inno vation and implement cost-effective clean energy solutions; a nd (9) t he policy of Illinois shall be to maximize the use of virtua l power plants comprised of customer-owned and third party-owned distributed energy resources to delive r system services and other benefits through utility adm inistered virtual power plant programs in acco rdance with the provisions of this amendatory Act of the 104th Gene ral Assembly. (c) No later than December 31, 2028, the Commission shall approve at least one virtual power plant tariff for each electric util ity serving more than 300,000 customers in the State as of January 1, 2023. Each utility shall file a tariff or tariffs fo r approval no later than December 31, 2027 to allow retai l customers in the electric utility's service areas to particip ate in a virtual power plant program proposal consistent with the provisions of this Section. The Commission sh all provide opportunities for stakeholders to provide input on the virtual power plant programs proposed for implem entation by each utility, which the Commission shall take into consideration in its review of each utility's filing. No later than one year after the utility's filing, the Comm ission shall approve or modify and approve each utility's v irtual power plant program proposal for immediate implementation by the utility. (d) The v irtual power plant program filed under subsection (c) shall be developed for implementation through a tariff offering with standard terms and conditions for participation. The virt ual power plant program tariff shall allow for customers wi th battery storage, non-battery storage and electric veh icle technologies to enroll the devices in the program through aggregators or dir ectly with the utility. The virtual power plant program tariff shall: (1) provide a mechanism to incorporate existing program s, such as smart thermostat demand-response o r electric vehicle charging programs currently off ered by the utility, under the virtual power plant program frame work; (2) provide grid services opportunities for each e ligible technology that customers and aggregators may provi de, which shall include, at minimum, reducing t he utility's applicable capacity and transmission obligations and capturing daily wholesa le energy arbitrage opportunities through provision of grid servi ces; (3) provide additional functions and grid se rvice opportunities that the Commission determines are supportive o f efficient planning and operation of the electrical grid, including : (A) minimizing the use of fossil fuels at peak times; (B) local peak demand reductions; (C) location al value; (D) the avoidance or deferral of local transmission or distribution upgrades or capacity expansion; (E) voltage support and other ancillary services; and (F) emergency grid ser vices; ( 4) provide operational parameters, which shall include, at a minimum: (A) minimum and maximum numbers of grid events for which the utility may require dispatch from the enrolled distributed energy resources; (B) months of the year that grid events may occur;

(C) days of the week that grid events may occur; (D) times of day that grid events may occur; (E) maximum duration of grid events; and (F) minimum day-ahead advance notification re quirement of grid events, except for emergency events, as applicable; (5) include provisions for aggregators to participate in th e virtual power plant program, participate in the utility's distributed energy resource management syste m as available, automatically enroll and manage their custo mers' participation, receive dispatch signals and othe r communications from the utility, deliver performance meas urement and verification data to the utility, and re ceive virtual power plant program payments directly from the utili ty; (6) include provisions that provide a standardized p rocess for any eligible aggregator to enroll in t he program and authorize the eligible aggregators to manage individual customer dev ice participation without additional authorizations from the util ity; (7) include provisions that allow a participating customer with multiple eligible devices to enroll the technologies either directly without an aggregator or t hrough one or more aggregators in applicable programs under the tariff approved under this Section , provided that no particular device is accounted for more th an once; (8) include provisions for direct participant cus tomers to participate with the utility's distribute d energy resource management system as available, receive dispatch signals and other communications from the ut ility, deliver performance measurement and verification dat a to the utility, and receive virtual power pla nt program payments directly from the utility. Any provis ions implementing this subpart that necessitate the in stallation of equipment to enable direct participatio n via the utility shall apply to customers who elect to par ticipate as a direct participant and shall not be require d of customers who participate via an aggregator or to customers who do not participate in the virtual power plant pr ogram;

(9) provide for measurement and verification of battery non -battery, and electric vehicle technologies performance directly at the device without the requirement for the installation of an additional mete r; (1 0) include upfront payment or performance payment compensation m echanisms for the peak reduction service, as well as for non-battery and electric vehicle technologies as the Commission deems appropriate. The performa nce payment shall be based on the average capacity p rovided during grid events. The Commission shall approv e additional compensation mechanisms as it determines approp riate for other grid services provided under the battery, n on-battery and electric vehicle riders. The virtual powe r plant program shall not assess penalties for non- performance; provided, however, that the Commission may approve reasonable m echanisms to disenroll customers for continued non-performance; (11) enable low-to-moderate income customers, community-driven community solar projects, and customers whose elect ric service has not been declared competitive pursuan t to Section 16-113 as of July 1, 2011 loca ted in equity investment eligible investment communities to receive a higher upfront enrollment payment. The Commi ssion shall coordinate with State energy officials and departments to make funding from federal programs and such other sources as may be available for use in providi ng higher upfront payments to customers classes as may be approved by the Commission in accordance with this subs ection; (12) provide that the performance payment rate applicab le at the time of enrollment shall be for 5 years, aft er which time the participant may reenroll at the then app licable performance payment rate for an additional 5-year ter m; (13) p rovide for a transition of customers from the scheduled dispatch program descri bed in Section 16-107.6 to the virtual power plant program; and

(14) allow enrolled customers to participate in other a pplicable interconnection tariffs and grid service programs out side the virtual power plant program, so long as it does not result in double-counting of benefits for the same gr id services. (e) The Co mmission may adopt other reasonable requirements for particip ation consistent with this subsection, prov ided that collateral from an aggregator shall not be required for par ticipation. (f) The u tility may contract with a third party-owned distribut ed energy resource management system provider to assist with program implementation; however, implementation shall not be delayed due to the lack of utility-owned distributed ener gy resource management system capabilities or thi rd party-owned distributed energy resource management system c apabilities. (g) The util ity shall not send or receive dispatch signals directly t o or from any participating customer represented by an aggregat or for an event under the virtual power plant program described in this Section. (h) Participa ting aggregators shall have capabilities to receive event signals from utilities or ut ility-contracted distributed energy resources management system providers. (i) U tilities shall recover reasonably and prudently incurred costs to facilitate the virtual power plant program approved unde r subsection (c), including, but not limited to, distribu ted energy resource management systems provider and other service contract costs, operations and maintenance expenses, information technology costs, and other costs, expenses, a nd investments that the Commission finds necessary and pruden t for the development and implementation of the program. The utility shall recover the cost of virtual power plant progr am upfront payments and performance payments and such other payments made to participant s through the tariff filed pursuant to subsection (h) of Section 16-107.6. (j) No la ter than January 31 of each year, each util ity shall file an annual report that includes, but is not limited to:

(1) the total capacity enrolled in each program rider d eveloped in accordance with the requirements of Section , broken down by technology type, customer class, and aggregator and direct participant status for each grid service opportunity offered in the prior calendar year ; (2) recommendati ons to increase participation in the virtual power plant program; and (3) any other information that the Co mmission may require. (k) Each utility shall amend existing tariffs and procedu res that limit the ability of customers to participate in providing grid services under the program, such as limitations on charging energy storage devices with grid energy or exporting energy to the grid from battery discharge. (l) The tariffs approved by the Commission sh all not reflect any additional charges, fees, or insurance requiremen ts imposed on those owning or operating demand-response techno logies beyond those imposed on similarly si tuated customers that do not own or operate demand-resp onse technologies. (m) As a condition of participating in the programs described in this Section, prior to enrollment of a cu stomer by an aggregator, the aggregator shall disclose the following: (1) the payments, expressed as an amount or a formula, to be provided to the cus tomer; (2) between the aggregat or and customer, who is responsible for paying penalties or fee s; and (3) between the aggregator and customer, who is responsible for posting collatera l, if required. Any tari ff authorized by this Section shall incorporate the requi rements under this subsection and shall require the electric u tility to establish a complaint and Commission notificat ion process and, on order of the Commission, suspend any aggregator repeatedly or egregiously violating such requirements. (220 ILCS 5/16-108) Sec. 16-108. Recove ry of costs associated with the provision of delivery a nd other services. (a) An el ectric utility shall file a delivery services tariff with the Commission at least 210 days prior to the date that it is req uired to begin offering such services pursuant to this Act. A n electric utility shall provide the components of delivery s ervices that are subject to the jurisdiction of the Federal Energy Regulatory Commission at the same prices, terms and conditions set forth in its applicable tariff as appro ved or allowed into effect by that Commission. The Commissio n shall otherwise have the authority pursuant to Article IX to review, approve, and modify the prices, terms and conditio ns of those components of delivery services not subject to the jurisdiction of the Federal Energy Regulatory Commission, inclu ding the authority to determine the extent to which such deli very services should be offered on an unbundled basis. In makin g any such determination the Commission shall consider, at a m inimum, the effect of additional unbundling on (i) the objec tive of just and reasonable rates, (ii) electric utility employees, and (iii) the development of competitive markets for e lectric energy services in Illinois. (b) Th e Commission shall enter an order approving, or approving as modified, the delivery services tariff no later than 30 d ays prior to the date on which the electric utility must commence offeri ng such services. The Commission may subsequently mo dify such tariff pursuant to this Act. (c ) The electric utility's tariffs shall define the classes of i ts customers for purposes of delivery services charges. Del ivery services shall be priced and made available to all retai l customers electing delivery services in each such class on a nondiscriminatory basis regardless of whether the retail custo mer chooses the electric utility, an affiliate of the electric utility, or another entity as its supplier of electric power an d energy. Charges for delivery services shall be cost based, and shall allow the electric utility to recover the costs of p roviding delivery services through its charges to its delivery service customers that use the facilities and services asso ciated with such costs. Such costs shall include the costs of owning, operating and maintaining transmission and distrib ution facilities. The Commission shall also be authorized t o consider whether, and if so to what extent, the followi ng costs are appropriately included in the electric utility's delivery services rates: (i) the costs of that portion of g eneration facilities used for the production and absorption of reactive power in order that retail customers locate d in the electric utility's service area can receive electric power and energy from suppliers other than the elec tric utility, and (ii) the costs associated with the use a nd redispatch of generation facilities to mitigate constraints on the transmission or distribution system in order tha t retail customers located in the electric utility's servic e area can receive electric power and energy from suppliers o ther than the electric utility. Nothing in this subsection s hall be construed as directing the Commission to allocate any of the costs described in (i) or (ii) that are found to be appropriately included in the electric utility's delivery services rat es to any particular customer group or geographic area in setting delivery services rates. (d) The Commission shall establish charges, terms and conditions for d elivery services that are just and reasonable and shall take into account customer impacts when establishing such charges. In establishing charges, terms and conditions for delivery services, the Commission shall take into account voltage level differences. A retail customer shall have the option to reque st to purchase electric service at any delivery service voltag e reasonably and technically feasible from the electric fa cilities serving that customer's premises provided that there a re no significant adverse impacts upon system reliability or sy stem efficiency. A retail customer shall also have the option to request to purchase electric service at any point of de livery that is reasonably and technically feasible provided t hat there are no significant adverse im pacts on system reliability or efficiency. Such re quests shall not be unreasonably denied. (e) Electric utilities shall recover the costs of installing , operating or maintaining facilities for the particular bene fit of one or more delivery services customers, including with out limitation any costs incurred in complying with a cust omer's request to be served at a different voltage level, directly from the retail customer or customers for whose be nefit the costs were incurred, to the extent such costs are not recovered through the charges referred to in subsectio ns (c) and (d) of this Section. (f) An electric utility shall be entitled but not required to implement t ransition charges in conjunction with the offering of delive ry services pursuant to Section 16-104. If an electric ut ility implements transition charges, it shall implement such charges for all delivery services customers and for all c ustomers described in subsection (h), but shall not implement tra nsition charges for power and energy that a retail customer tak es from cogeneration or self-generation facilities located on th at retail customer's premises, if such facilities meet the foll owing criteria: (i) the cogeneration or self-generation facili ties serve a single retail customer and are located o n that retail customer's premises (for purposes of this sub paragraph and subparagraph (ii), an industrial or m anufacturing retail customer and a third party contract or that is served by such industrial or manufacturing cust omer through such retail customer's own electrical di stribution facilities under the circumstances described in su bsection (vi) of the definition of "alternative retail electric supplier" set forth in Section 16-102, shall be considered a single ret ail customer); ( ii) the cogeneration or self-generation facilities ei ther (A) are sized pursuant to generally accepted engi neering standards for the retail customer's electrical l oad at that premises (taking into account standby or other reliability considerations related to that retail customer's operations at that site) or (B) if the facil ity is a cogeneration facility located on the retail custo mer's premises, the retail customer is the thermal host for that facility and the facility has been designed to meet that retail customer's thermal energy requirements resulting in electrical output beyond that retail cus tomer's electrical demand at that premises, comply wit h the operating and efficiency standards applicable to " qualifying facilities" specified in title 18 Code of Federal Regulations Sect ion 292.205 as in effect on the effective date of this amendatory Act of 1999; (iii) the retail customer on whose premises the faci lities are located either has an exclusive right to receive , and corresponding obligation to pay for, all of the elect rical capacity of the facility, or in the case of a co generation facility that has been designed to meet the ret ail customer's thermal energy requirements at that premises, an identified amount of th e electrical capacity of the facility, over a minimum 5-year period; and

(iv) if the cogeneration facility is sized for the r etail customer's thermal load at that premises but exc eeds the electrical load, any sales of excess power or ene rgy are made only at wholesale, are subject to th e jurisdiction of the Federal Energy Regulatory Commission, and are not for the purpose of circumventin g the provisions of this subsection (f).If a gener ation facility located at a retail customer's premises does n ot meet the above criteria, an electric utility implementing t ransition charges shall implement a transition charge until Dece mber 31, 2006 for any power and energy taken by such retail c ustomer from such facility as if such power and energy had been delivered by the electric utility. Provided, however, tha t an industrial retail customer that is taking power from a ge neration facility that does not meet the above criteria but tha t is located on such customer's premises will not be subject to a transition charge for the power and energy taken by suc h retail customer from such generation facility if the facility does not serve any other retail customer and either was insta lled on behalf of the customer and for its own use prior to Jan uary 1, 1997, or is both predominantly fueled by byproducts of such customer's manufacturing process at such premises a nd sells or offers an average of 300 megawatts or more of elect ricity produced from such generation facility into the wholesale market. Such charges shall be calculated as provided in Section 16-102, and shall be collected on each kilowatt-hour delivered under a delivery services tariff to a retail customer from the date the customer first takes delivery servi ces until December 31, 2006 except as provided in subsectio n (h) of this Section. Provided, however, that an electri c utility, other than an electric utility providing service to at least 1,000,000 customers in this State on January 1, 199 9, shall be entitled to petition for entry of an order by the Commission authorizing the electric utility to implement tr ansition charges for an additional period ending no later than December 31, 2008. The electric utility shall file its pet ition with supporting evidence no earlier than 16 months, and no later than 12 months, prior to December 31, 2006. The Commission shall hold a hearing on the electric utility's petition and shall enter its order no later than 8 months after the petition is filed. The Commission shall determin e whether and to what extent the electric utility shall be au thorized to implement transition charges for an additional peri od. The Commission may authorize the electric utility to imple ment transition charges for some or all of the additional peri od, and shall determine the mitigation factors to be used i n implementing such transition charges; provided, that the Co mmission shall not authorize mitigation factors less than 110% of those in effect during the 12 months ended December 31, 2006. In making its determination, the Commission shall con sider the following factors: the necessity to implement trans ition charges for an additional period in order to maintain the financial integrity of the electric utility; the prudence of t he electric utility's actions in reducing its costs since the effective date of this amendatory Act of 1997; the ability of the electric utility to provide safe, adequate and reliable ser vice to retail customers in its service area; and the impact on competition o f allowing the electric utility to implement transition cha rges for the additional period. (g) The electr ic utility shall file tariffs that establish the transitio n charges to be paid by each class of customers to the electric utility in conjunction with the provision of delivery se rvices. The electric utility's tariffs shall define the c lasses of its customers for purposes of calculating tra nsition charges. The electric utility's tariffs shall provide for th e calculation of transition charges on a customer-spec ific basis for any retail customer whose average monthly maximu m electrical demand on the electric utility's system during the 6 months with the customer's highest monthly maximum electri cal demands equals or exceeds 3.0 megawatts for electric u tilities having more than 1,000,000 customers, and for oth er electric utilities for any customer that has an average m onthly maximum electrical demand on the electric utility's sy stem of one megawatt or more, and (A) for which there exists data on the customer's usage during the 3 years preceding the date that the customer became eligible to take delivery servic es, or (B) for which there does not exist data on the custome r's usage during the 3 years preceding the date that the custo mer became eligible to take delivery services, if in the elect ric utility's reasonable judgment there exists comparable usage information or a sufficient basis to develop su ch information, and further provided that the electric ut ility can require customers for which an individual calculatio n is made to sign contracts that set forth the tra nsition charges to be paid by the customer to the elect ric utility pursuant to the tariff. (h) An electric utility shall also be entitled to file tariffs t hat allow it to collect transition charges from retail custome rs in the electric utility's service area that do not take deli very services but that take electric power or energy from an alternative retail electric supplier or from an electric utility other than the electric utility in whose service are a the customer is located. Such charges shall be calculated, in a ccordance with the definition of transition charges in Secti on 16-102, for the period of time that the customer wo uld be obligated to pay transition charges if it were taking d elivery services, except that no deduction for delivery servi ces revenues shall be made in such calculation, and usage data from the customer's class shall be used where historical usage data is not available for the individual customer. The cus tomer shall be obligated to pay such charges on a lump sum basi s on or before the date on which the customer commences to take service from the alternative retail electric supplier or other electric utility, provided, that the electric uti lity in whose service area the customer is located shall offer the customer the option of signing a contract pursuant to which the customer pa ys such charges ratably over the period in which the cha rges would otherwise have applied. (i) An electric utility shall be entitled to add to the bills of delivery services cu stomers charges pursuant to Sections 9-221, 9-222 (except as pr ovided in Section 9-222.1), and Section 16-114 of this Act, Section 5-5 of the Electricity Infrastr ucture Maintenance Fee Law, Section 6-5 of the R enewable Energy, Energy Efficiency , and Coal Resources Development Law of 1997, and Section 13 of the Energy Assistance Act. (i-5) A n electric utility required to impose the Coal to Solar and Energy Storage Initiative Charge provided for in subsection (c-5) of Sec tion 1-75 of the Illinois Power Agency Act shall add suc h charge to the bills of its delivery services customers pursuant to the terms of a tariff conforming to the requirements of subsection (c-5) of Section 1-75 of the Illinois Power Ag ency Act and this subsection (i-5) and filed with a nd approved by the Commission. The electric utility shall file its proposed tariff with the Commission on or before July 1, 2 022 to be effective, after review and approval or modification by the Commission, beginning January 1, 2023. On or before Dec ember 1, 2022, the Commission shall review the electric utility 's proposed tariff, including by conducting a docketed pr oceeding if deemed necessary by the Commission, and shall app rove the proposed tariff or direct the electric utility to m ake modifications the Commission finds necessary for the tariff to conform t o the requirements of subsection (c-5) of Section 1-75 o f the Illinois Power Agency Act and this subsection (i-5). The electric utility's tariff shall provide for i mposition of the Coal to Solar and Energy Storage Initi ative Charge on a per-kilowatthour basis to all kilowatt hours delivered by the electric utility to its delivery service s customers. The tariff shall provide for the calculation of t he Coal to Solar and Energy Storage Initiative Charge to be in effect for the year beginning January 1, 2023 and each yea r beginning January 1 thereafter, sufficient to collect the electric utility's estimated payment obligations for the d elivery year beginning the following June 1 under contracts for purch ase of renewable energy credits entered into pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act and the obligations of the Depart ment of Commerce and Economic Opportunity, or any successor depart ment or agency, which for purposes of this subsection (i- 5) shall be referred to as the Department, to make grant pa yments during such delivery year from the Coal to Solar and Energy St orage Initiative Fund pursuant to grant contracts entered into pursu ant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, and using the electric utili ty's kilowatthour deliveries to its delivery services customer s during the delivery year ended May 31 of the preceding cal endar year. On or before November 1 of each year beginning Nove mber 1, 2022, the Department shall notify the electric u tilities of the amount of the Department's estimated obliga tions for grant payments during the delivery year beginning the following June 1 pursuant to grant contracts entered into pursuant to su bsection (c-5) of Section 1-75 of the Illinois Powe r Agency Act; and each electric utility shall incorporat e in the calculation of its Coal to Solar and Energy Stor age Initiative Charge the fractional portion of the Departm ent's estimated obligations equal to the electric utility' s kilowatthour deliveries to its delivery services customers in the delivery year ended the preceding May 31 divided by t he aggregate deliveries of both electric utilities to deliver y services customers in such delivery year. The electric utilit y shall remit on a monthly basis to the State Treasurer, for depos it in the Coal to Solar and Energy Storage Initiative Fund provided for in subsection (c-5) of Section 1-75 of the Illi nois Power Agency Act, the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge esti mated to be needed by the Department for grant payments pursuant to grant contracts entered into pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. The initial charge under the electric utility's tariff sha ll be effective for kilowatthours delivered beginning January 1 , 2023, and thereafter shall be revised to be effective January 1, 2024 and each January 1 thereafter, based on the payment obligations for the delivery year beginning the following June 1. The tariff shall provide for the electric utility to make an annual filing with the Commission on or before Novem ber 15 of each year, beginning in 2023, setting forth the Coal t o Solar and Energy Storage Initiative Charge to be in effe ct for the year beginning the following January 1. The electric utility's tariff shall also provide that the electric utility shall make a filing with the Commission on or before August 1 of each year beginning in 2024 setting forth a reconciliation, for the delivery year ended the preceding May 31, of the elec tric utility's collections of the Coal to Solar and Energy Storage Initiative Charge against actual payments for renewable energy credits pursuant to contracts entered into, and the actual g rant payments by the Department pursuant to grant contracts entered into, pursuant to subsection (c-5) of Section 1- 75 of the Illinois Power Agency Act. The tariff sh all provide that any excess or shortfall of collections to payments shall be deducted from or added to, on a per-kilowatthour basi s, the Coal to Solar and Energy Storage In itiative Charge, over the 6-month period beginning October 1 of that calendar year. (j) If a retail customer that obtains electric power and energy f rom cogeneration or self-generation facilities installed for its own use on or before January 1, 1997, subsequent ly takes service from an alternative retail electric supplier or an electric utility other than the electric utili ty in whose service area the customer is located for any portion of the customer's electric power and energy requi rements formerly obtained from those facilities (including t hat amount purchased from the utility in lieu of such generatio n and not as standby power purchases, under a cogeneration di splacement tariff in effect as of the effective date of this a mendatory Act of 1997), the transition charges otherwise app licable pursuant to subsections (f), (g), or (h) of this Section shall not be applicable in any year to th at portion of the customer's electric power and energy re quirements formerly obtained from those facilities, provided, that f or purposes of this subsection (j), such portion shall not exceed the average number of kilowatt-hours per year obtained from the cogeneration or self-generation facilities during the 3 years prior to the date on which the customer became eli gible for delivery services, except as provided in sub section (f) of Section 16-110. (k) The electric utility shall be entitled to recover throug h tariffed charges all of the costs associated with the purchase of zero emission credits from zero emission facilities to meet the requirements of subsection (d-5) of Section 1-75 of the Illinois Power Agency Act and all of the costs a ssociated with the purchase of carbon mitigation credits from carbon-free energy resources to meet the requirements of subsec tion (d-10) of Section 1-75 of the Illinois Power Agency Act. Such costs shall include the costs of procuring the zero emission credits and carbon mitigation credits fro m carbon-free energy resources, as well as the reasonab le costs that the utility incurs as part of the procurement processes and to implement and comply with plans and processes approv ed by the Commission under subsections (d-5) an d (d-10). The costs shall be allocated across all retail custom ers through a single, uniform cents per kilowatt-hour charge appl icable to all retail customers, which shall appear as a se parate line item on each customer's bill. The electric utility shall be entitled to recover through tariffed charges approved by the Commission all of the prudent and reason able costs associated with energy storage resources procurements to meet t he energy storage system portfolio standard of subsection (d-20) of Section 1-75 of the Illinois Power Agency Act. Such costs shall include the contract costs for the energy storage system resources and the prudent and reasonab le costs that the utility incurs as part of the procu rement processes and in implementing and complying with plans and p rocesses approved by the Commission under subsection (d- 20). The costs associated with the purchase of energy storage s ystem resources shall be allocated across all retail cust omers in proportion to the amount of energy storage system reso urces the utility procures for such customers through a singl e, uniform cents per kilowatt-hour charge applicable to such retai l customers, which shall appear as a separate line item on each customer's bill. Beginning June 1, 2017, the electric utility shall be entitled to recover through tariff ed charges all of the costs associated with the purchase of renewable energy resources to meet the renewable energy resource st andards of subsection (c) of Section 1-75 of the Illinois Powe r Agency Act, under procurement plans as approved in accordan ce with that Section and Section 16-111.5 of this Ac t. Such costs shall include the costs of procuring the re newable energy resources, as well as the reasonable costs that the utility incurs as part of the procurement processes an d to implement and comply with plans and processes approved by the Commission under such Sections. The costs associated with the purchase of renewable energy resources shall be allocated across all retail customers in proportion to the amount of renewable energy resources the utility procures for such c ustomers through a single, uniform cents per kilowatt-hour charge applicable to such retail customers, which sha ll appear as a separate line item on each such customer's bill. The credits, costs, and penalties associated with the self-direct renewable portfolio standard compliance program describ ed in subparagraph (R) of paragraph (1) of subsection (c) of S ection 1-75 of the Illinois Power Agency Act shall be allocate d to approved eligible self-direct customers by the utilit y in a cents per kilowatt-hour credit, c ost, or penalty, which shall appear as a separate line i tem on each such customer's bill. Notwithstandin g whether the Commission has approved the initial long-term renewable resources procurement plan as of June 1, 2017, an electric utility shall place new tariffed charges int o effect beginning with the June 2017 monthly billing period , to the extent practicable, to begin recovering the costs of procuring renewable energy resources, as those charges are calculated under the limitations described in subparagraph (E) of paragraph (1) of subsection (c) of Section 1-75 of t he Illinois Power Agency Act. Notwithstanding the date on w hich the utility places such new tariffed charges into effect, the utility shall be permitted to collect the charges under s uch tariff as if the tariff had been in effect beginning with the first day of the June 2017 monthly billing period. For th e delivery years commencing June 1, 2017, June 1, 2018, June 1, 2019, and each delivery year thereafter, the e lectric utility shall deposit into a separate interest bear ing account of a financial institution the monies collected und er the tariffed charges. Money collected from customers fo r the procurement of renewable energy resources in a given deli very year may be spent by the utility for the procurement of renewable resources over any of the following 5 delivery years , after which unspent money shall be credited back to retai l customers. The electric utility shall spend all money c ollected in earlier delivery years that has not yet been retu rned to customers, first, before spending money collected in l ater delivery years. Any interest earned shall be credited bac k to retail customers under the reconciliation proceedin g provided for in this subsection (k), provided that the electric utility shall first be reimbursed from the interest for the administrative costs that it incurs to administer and ma nage the account. Any taxes due on the funds in the acco unt, or interest earned on it, will be paid from the account o r, if insufficient monies are available in the account, from t he monies collected under the tariffed charges to recove r the costs of procuring renewable energy resources. Monies deposite d in the account shall be subject to the review, reconciliati on, and true-up process described in this subsect ion (k) that is applicable to the funds collected and costs incurred for the procureme nt of renewable energy resources. The electr ic utility shall be entitled to recover all of the costs iden tified in this subsection (k) through automatic adjustment clau se tariffs applicable to all of the utility's retail custo mers that allow the electric utility to adjust its tariffed charges consistent with this subsection (k). The determinat ion as to whether any excess funds were collected during a gi ven delivery year for the purchase of renewable energy resources , and the crediting of any excess funds back to retail custom ers, shall not be made until after the close of the delivery yea r, which will ensure that the maximum amount of funds is avai lable to implement the approved long-term renewable reso urces procurement plan during a given delivery year. The amount of excess funds eligible to be credited back to retail custom ers shall be reduced by an amount equal to the payment oblig ations required by any contracts entered into by an electric utility under contracts described in subsection (b) of Section 1-56 a nd subsection (c) of Section 1-75 of the Illinois Power Agency Act, even if such payments have not yet been made and r egardless of the delivery year in which those payment obligations were incurred. Notwithstanding anything to the contrary, including in tariffs authorized by this subsecti on (k) in effect before the effective date of this amendat ory Act of the 102nd General Assembly, all unspent funds a s of May 31, 2021, excluding any funds credited to customers dur ing any utility billing cycle that commences prior to the effective date of this amendatory Act of the 102nd General A ssembly, shall remain in the utility account and shall on a first in, first out basis be used toward utility payment obligations under contracts described in subsection (b) of Section 1-56 a nd subsection (c) of Section 1-75 of the Illinois Power Agency Act. The electric utility's collections under such a utomatic adjustment clause tariffs to recover the costs of renewable energy reso urces, zero emission credits from zero emission facilities, energy storage resources, and carbon mitigation credits from carbon-free energy resources shall be subject to separate annual review, reconciliation, and true-u p against actual costs by the Commission under a procedure that shall be specified in the electric utility's automatic ad justment clause tariffs and that shall be approved by the Commission in connection with its approval of such tariffs. The proced ure shall provide that any difference between the electric utility's collections for energy storage resources, zero emission cr edits, and carbon mitigation credits under the automatic adjustment charges for an annual period and the electric uti lity's actual costs of energy storage resources, zero emission cr edits from zero emission facilities, and car bon mitigation credits from carbon-free energy resourc es for that same annual period shall be refunded to or col lected from, as applicable, the electric utility's ret ail customers in subsequent periods. Nothing in this subsection (k) is intended to affect, limit, or chang e the right of the electric utility to recover the costs assoc iated with the procurement of renewable energy resources for periods commencing b efore, on, or after June 1, 2017, as otherwise provided i n the Illinois Power Agency Act. The fun ding available under this subsection (k), if any, for the program s described under subsection (b) of Section 1-56 of the Illinois Power Agency Act shall not reduce the amount of funding fo r the programs described in subparagraph (O) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. If funding is available under this subsection (k) for programs described under subsection (b) of Section 1- 56 of the Illinois Power Agency Act, then the long-term renewable resources plan shall provide for the Agency to p rocure contracts in an amount that does not exceed the funding, and the contr acts approved by the Commission shall be executed by the applicable utility or utilities. (l) A utility that ha s terminated any contract executed under subsection (d-5) or (d-10) of Section 1-75 of the Illin ois Power Agency Act shall be entitled to recover any remaini ng balance associated with the purchase of zero emission credi ts prior to such termination, and such utility shall also apply a credit to its retail customer bills in the event of an y over-collection. (m)(1) An electric utility that recovers its costs of procuring zero emission cr edits from zero emission facilities through a cents-per -kilowatthour charge under subsection (k) of this Section shall be subject to the requirements of this subsection (m). Notwithstanding anything to the contrary, such electric util ity shall, beginning on April 30, 2018, and each April 30 thereafter unti l April 30, 2026, calculate whether any reduction must b e applied to such cents-per-kilowatthour charge th at is paid by retail customers of the electric utility that have opted out of subsections (a) through (j) of Section 8-103B o f this Act under subsection (l) of Section 8-103B. Such ch arge shall be reduced for such customers for the next deliver y year commencing on June 1 based on the amount necessary, if any, to limit the annual estimated average net increase for the prior calendar year due to the future energy inves tment costs to no more than 1.3% of 5.98 cents per kilowa tt-hour, which is the average amount paid per kilowattho ur for electric service during the year ending December 31, 2015 by Illin ois industrial retail customers, as reported to the Edison Electric Institute. The calcu lations required by this subsection (m) shall be made only o nce for each year, and no subsequent rate impact determinations shall be made. (2) For purposes of this Section, "future energy investment costs" sha ll be calculated by subtracting the cents-per-kilowatthour charge identified in subparagraph (A) of this paragraph (2) from the sum of the cents-per-kilowatthour charges identified in subparagraph (B) of this paragr aph (2): (A) The ce nts-per-kilowatthour charge identified in the electric utility's tariff placed into effect under Section 8-103 of the Public Utilities Act that, on Dece mber 1, 2016, was applicable to those retail customers that have opted out of subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B. (B) The su m of the following cents-per-kilowatthour charges app licable to those retail customers that have opted out of s ubsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B, provided that if one or more of the following charges has been in effect and applied to such customers for more than one calendar year, then each charge shall be equal to the average of the charges applied over a period that comme nces with the calendar year ending December 31, 2017 and ends with the most recently com pleted calendar year prior to the calculation required by this subsection (m): (i) the cents-per-kilowatthour charge to recover the c osts incurred by the utility under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act, adjusted for any reductions required under this subsection (m) ; and ( ii) the cents-per-kilowatthour charge to recover the costs inc urred by the utility under Section 16-107.6 of the Public Utilities Act.

If no charge was applied for a given calendar year under item (i) or (ii) of th is subparagraph (B), then the value of the charge for that year shall be zero. ( 3) If a reduction is required by the calculation performed unde r this subsection (m), then the amount of the reduction shall b e multiplied by the number of years reflected in the averages c alculated under subparagraph (B) of paragraph (2) of this subsection (m). Such reduction shall be applied to the cents-per-kilowatthour charge that is applicable to those retail customers that have opted out of subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B beginning with the next delivery year commencing after the date of the calculation required by this subsection (m). (4) The e lectric utility shall file a notice with the Commission on May 1 of 2018 and each May 1 thereafter until May 1, 2026 c ontaining the reduction, if any, which must be applied for the delivery year which begins in the year of the filing. The notice shall contain the calculations made pursuant to thi s Section. By October 1 of each year beginning in 2018, each electric utility shall notify the Commission if it appears, b ased on an estimate of the cal culation required in this subsection (m), that a reduction will be required in the next year. (S ource: P.A. 102-662, eff. 9-15-21.) (220 ILCS 5/16-108.19) Sec . 16-108.19. Division of Integrated Distribution Planning. (a) The Commission shall employ establish the Division of Integrated Distribution P lanning within the Bureau of Public Utilities. The Division shall be staffed by no less than 13 pr ofessionals, including engineers, rate analysts, accountant s, policy analysts, utility research and analysis analysts, cybersecurity analysts, informational technology specialists, and lawyers, and other personnel deemed necessary and appropriate by the Executive Director to review and evaluate Integrated Gr id Plans, updates to Integrated Grid Plans, audits, and other duties as assigned. The personnel may be organized or assigned into departments, bureaus, sections, or divisions as determined by the Execu tive Director pursuant to the authority granted under th is Section by the Chief of the Public Utilities Bureau.

(b) The Division of Integrated Distribution Planning shall be established by January 1, 2022. (S ource: P.A. 102-662, eff. 9-15-21.) (220 ILCS 5/16-108.30) Sec. 16-108.30. Energy Transi tion Assistance Fund. (a) The Energy Transition Assistance Fund is here by created as a special fund in the State treasury

Treasury. The Ener gy Transition Assistance Fund is authorized to receive moneys collected pursuant to this Section. Subject to ap propriation, the Department of Commerce and Economic Opportunity shall use m oneys from the Energy Transition Assistance Fund c onsistent with the purposes of this Act. (b) An electric utility serving more than 500,000 customers in the State shall assess an energy transition assistance ch arge on all its retail customers for the Energy Transition A ssistance Fund. The utility's total charge shall be set based upon the value determined by the Department of Commerce and Econom ic Opportunity pursuant to subsection (d) or (e), as a pplicable, of Section 605-1075 of the Department of Comm erce and Economic Opportunity Law of the Civil Administ rative Code of Illinois. For each utility, the charge shall be reco vered through a single, uniform cents per kilowatt-hour charge applicable to all retail customers. For each utility, the charge shall not exceed 1. 35% 1.3% of the amount paid per kilowatthour by eligible retail customers during the year endin g May 31, 2009. Beginning January 1, 2028, the limitati on shall be increased by an additional 0.636 percentage points of the amount paid per kilowatt-hour by eligible re tail customers during the year ending May 31, 2009, which w ould collect the equivalent of the average annual budget o f the programs administered by the utilitie s under Section 45 of the Electric Vehicle Act fo r the years 2026 through 2028.

(c) Within 75 days of the effective date of this amendatory Act of the 102nd General Assembly, each electric utili ty serving more than 500,000 customers in the State shall file with the Illinois Commerce Commission tariffs incorporat ing the energy transition assistance charge in other charges stated in such tariffs, which energy transition assistance c harges shall become effective no later than the beginning of the first billing cycle that begins on or after January 1 , 2022. Each electric utility serving more than 500,000 custo mers in the State shall, prior to the beginning of each ca lendar year starting with calendar year 2023, file wit h the Illinois Commerce Commission tariff revisions to incorpo rate annual revisions to the energy transition assistance charge as prescribed by the Department of Commerce and Economic Oppo rtunity pursuant to Section 605-1075 of the Department of Commerce and Economic Opportunity Law of the Civil Admi nistrative Code of Illinois so that such revision becomes effective no later than the beginning of the first b illing cycle in each respective year. (d) The en ergy transition assistance charge shall be considered a charge for public utility service. (e) By the 20th day of the month following the month in which the char ges imposed by this Section were collected, each electric utili ty serving more than 500,000 customers in the State shall r emit to Department of Revenue all moneys received as payment of the energy transition assistance charge on a return pre scribed and furnished by the Department of Revenue showing su ch information as the Department of Revenue may reasonab ly require. If a customer makes a partial payment, a public u tility may apply such partial payments first to amounts owed to the utility. No customer may be subjected to disconnection of his or her utility service for failure to pay the energ y transition assistance charge. If any payme nt provided for in this subsection exceeds the electric uti lity's liabilities under this Act, as shown on an origin al return, the Department may authorize the electric utility t o credit such excess payment against liability subsequently to be remitted to the Department under this Act, in accordance with reasonable rules adopted by the Department. All the prov isions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e, 5f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13 of the Retai lers' Occupation Tax Act that are not inconsistent with this A ct apply, as far as practicable, to the charge imposed by this Act to the same extent as if those provisions were include d in this Act. References in the incorporated Sections of the Retailers' Occupation Tax Act to retailers, to sellers, or to persons engaged in the business of selling ta ngible personal property mean persons required to rem it the charge imposed under this Act. (f) The Department of Revenue shall deposit into the En ergy Transition Assistance Fund all moneys remitted to it in accordance with this Section. (g) The Depar tment of Revenue may establish such rules as it deems ne cessary to implement this Section. (h) The Department of Commerce and E conomic Opportunity may establish such rules as it deems necessary to implement this Section. (Source: P.A. 102-662, eff. 9-15 -21; 102-1031, eff. 5-27-22.) (220 ILCS 5/16-111.5) Sec. 16-111.5. Provisions relating to procurement. (a) An elec tric utility that on December 31, 2005 served at least 100,0 00 customers in Illinois shall procure power and energy for its e ligible retail customers in accordance with the applicable prov isions set forth in Section 1-75 of the Illinois P ower Agency Act and this Section. Beginning with the delive ry year commencing on June 1, 2017, such electric util ity shall also procure zero emission credits from zero emission f acilities in accordance with the applicable provisions set fort h in Section 1-75 of the Illinois Power Agency Act , and, for years beginning on or after June 1, 2017, the utilit y shall procure renewable energy resources in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning w ith the delivery year commencing on June 1, 2022, an electric utility serving over 3,000,000 customers shall also procure carbon mitigation credits from carbon-free energy resources in accorda nce with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning with the delivery year commencing on June 1, 2026, a n electric utility serving more than 300,000 customers in t he State as of January 1, 2019 shall also procure energy storage re sources in accordance with the applicable provisions of subsec tion (d-20) of Section 1-75 of the Illinois Power Age ncy Act and this Section. A small multi-jurisd ictional electric utility that on December 31, 2005 serv ed less than 100,000 customers in Illinois may elect to pr ocure power and energy for all or a portion of its eligible Illinois retail customers in accordance with the applicable provisio ns set forth in this Section and Section 1-75 of the Illinois Power Agency Act. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Illinois Power Agency t o prepare a procurement plan for its eligible retail custom ers. "Eligible retail customers" for the purposes of this Section m eans those retail customers that purchase power and energy from the electric utility under fixed-price bundled serv ice tariffs, other than those retail customers whose service is declared or deemed competitive under Section 16-113 and those other customer groups specified in this Section, includ ing self-generating customers, customers electing hourly pricing, or t hose customers who are otherwise ineligible for fixed-price bundled tariff service. E xcept as otherwise provided for in subsection (b-1 0), for For those customers that are excluded from the procurement plan's electric supply service requirements, and the utility shall procure any supp ly requirements, including capacity, ancillary services, and h ourly priced energy, in the applicable markets as needed to se rve those customers, provided that the utility may include in its procurement plan load requirements for the load that is associated with those retail customers whose service has been de clared or deemed competitive pursuant to Section 16-113 of this Act to the extent that those customers are purchasing power and energy during one of the transition periods identified in subsection (b) of Sec tion 16-113 of this Act. (b) A pro curement plan shall be prepared for each electric utility co nsistent with the applicable requirements of the Illinois Powe r Agency Act and this Section. For purposes of this Section, Illinois electric utilities that are affiliated by virtue of a comm on parent company are considered to be a single electric utili ty. Small multi-jurisdictional utilities may requ est a procurement plan for a portion of or all of its Il linois load. Each procurement plan shall analyze the projected balance of supply and demand for those retail customers to be inc luded in the plan's electric supply service requirements ov er a 5-year period, with the first planning year beginni ng on June 1 of the year following the year in which the plan i s filed. The plan shall specifically identify the wholesale pr oducts to be procured following plan approval, and shall follow all the requirements set forth in the Public Utilities A ct and all applicable State and federal laws, statutes, rules , or regulations, as well as Commission orders. Nothin g in this Section precludes consideration of contracts longer than 5 years and related forecast data. Unless specified ot herwise in this Section, in the procurement plan or in the impl ementing tariff, any procurement occurring in accordance with this plan shall be competitively bid through a request for pr oposals process. Approval and implementation of the procure ment plan shall be subject to review and approval by the Co mmission according to the provisions set forth in t his Section. A procurement plan shall include each of the following components: (1) Hourly load analysis. This analysi s shall include: (i) multi-year historical ana lysis of hourly loads;

(ii) switching trends and competitive retail market analysis; (iii) known or projected changes to future loads; and (iv) growth forec asts by customer class. (2) Analysis of the impact of any demand side and renewable energy initiatives. This ana lysis shall include: (i) the impact of demand response programs and energy efficiency programs, both current and pr ojected; for small multi-jurisdictional utilities, t he impact of demand response and energy efficiency programs approv ed pursuant to Section 8-408 of this Act, both current and projected; and (ii) supply side needs that are projected to be offset by purchases of renewable energy resources, if any. (3 ) A plan for meeting the expected load requiremen ts that will not be met through preexisting contracts. This p lan shall include: (i) definitions of the different Illinois retail customer classes for which supply is being purchased;

(ii) the proposed mix of demand-response produ cts for which contracts will be executed during the ne xt year. For small multi-jurisdictional electric utilities that on December 31, 2005 served fewer than 100,000 customers in Illinois, these shall be defined as dem and-response products offered in an energy efficiency plan a pproved pursuant to Section 8-408 of this Ac t. The cost-effective demand-response meas ures shall be procured whenever the cost is lower t han procuring comparable capacity products, provided that such product s shall:

(A) be procured by a demand-response provider from thos e retail customers included in the plan's electric supply service requirements; (B) at least satisfy the demand -response requirements of the regional tran smission organization market in which th e utility's service territory is located, i ncluding, but not limited to, any applicable capacity or dispa tch requirements; (C) provide for customers' particip ation in the stream of benefits produced by the demand-response products;

(D) provide for reimbursement b y the demand-response provider of t he utility for any costs incurred as a result of the fail ure of the supplier of such products to perform its obligations t hereunder; and

(E) meet the same credit requirements as apply to suppl iers of capacity, in the applicable regional transm ission organization market; (iii) monthly forecasted system supply requirements, i ncluding expected minimum, maximum, and average values for t he planning period; (iv) the proposed mix and selectio n of standard wholesale products for which con tracts will be executed during the next year, separately or in combination, to meet that portion of its load requir ements not met through pre-existing contracts, includi ng but not limited to monthly 5 x 16 peak period block energy, monthly off-peak wrap energy, mon thly 7 x 24 energy, annual 5 x 16 energy, other stan dardized energy or capacity products designed to provide eligible retail customer benefits from co mmercially deployed advanced technologies including but not limited to high voltage direct current converter s tations, as such term is defined in Section 1-1 0 of the Illinois Power Agency Act, whether or not such p roduct is currently available in wholesale markets, an nual off-peak wrap energy, annual 7 x 24 ener gy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchase plan, and ancillary services;

(v) proposed term structures for each wholesale pr oduct type included in the proposed procurement plan po rtfolio of products; and (vi) an assessment of the price risk, load uncertainty, and other factors that are associat ed with the proposed procurement plan; this assessment, to the extent possible, shall include an analysis of the following factors: contract terms, time frames for securing products or services, fuel costs, weathe r patterns, transmission costs, market conditions, and the governmental regulatory environment; the proposed procurement plan shall also identify alternatives for those portfolio measures that are identified as having significant price risk and mitigation in the form of additional retail customer a nd ratepayer price, reliability, and environm ental benefits from standardized energy products de livered from commercially deployed advanced technologie s, including, but not limited to, high voltage direct current converter stations, as such term is defined i n Section 1-10 of the Illinois Power Agenc y Act, whether or not such product is currently availab le in wholesale markets.

(4) Proposed procedures for balancing loads. The procurement plan shall include, for load requireme nts included in the procurement plan, the process for (i) hourly balancing of supply and demand and (ii) the criter ia for portfolio re-balancing in the event of significant shifts in load. (5) Long-Term Renewable Resources Procurement Plan. The Agency shall prepare a long-term renewable resources procurement plan fo r the procurement of renewable energy credits under Sec tions 1-56 and 1-75 of the Illinois Power Agency Act for delivery beginning in the 2017 delivery year. (i) The initial long-term renewable resources procurement plan and all subsequent revisions shall be subject to review and approval by the Commission. For the p urposes of this Section, "delivery year" has the sa me meaning as in Section 1-10 of the Illinois Power Agency Ac t. For purposes of this Section, "Agency" shall mean the Illinois Power Agency. (ii) The long -term renewable resources planning process shall be condu cted as follows: (A) Electric utilities sha ll provide a range of load forecasts to the Illino is Power Agency within 45 days of the Agency's r equest for forecasts, which request shall sp ecify the length and conditions for the forecasts including, but not limited to, the quantity of distributed generation expected to be interconnecte d for each year. (B) The Agency shall publish for comment the initial long-term renewable resources procurement plan no later than 120 days after the effective date of this amendatory Act of th e 99th General Assembly and shall review, and ma y revise, the plan at least every 2 years thereafter. T o the extent practicable, the Agency shall review and propose any revisions to the long-t erm renewable energy resources procurement plan in conjunct ion with the Agency's other planning and appro val processes conducted under this Section. Plans may be released on separate dates, but the Age ncy shall, to the extent practicable, release both pl ans across a 30-day period. The initial long-term renewable resources procurement plan shall: (aa) Identify the procure ment programs and competitive procurement events consistent with the applicable requirem ents of the Illinois Power Agency Act and shall be designed to a chieve the goals set forth in subsection (c) of Section 1-7 5 of that Act. (bb) Include a schedu le for procurements for renewable en ergy credits from utility-scale wind projects, utility-scale so lar projects, and brownfield site photovoltaic projec ts consistent with subparagraph (G) of paragrap h (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.

(cc) Identify th e process whereby the Agency will submit to the Commission for review and a pproval the proposed contracts to implement the programs required by such plan. If so authorized by the Commission in its order approving the procuremen t plan, the procurement plan shall provide th at small multi-jurisdictional electric utilit ies that, on December 31, 2005, served fewer tha n 100,000 customers in Illinois shall, in lie u of serving as counterparties to contracts for the delivery of renewable energy cr edits, instead provide an amount equivalent to the contracts for the delivery of renewable e nergy credits in collections to utilities that served at least 100,000 customers in Illin ois as a compliance payment for the procuremen t of additional renewable energy credits to satisfy that small multi-jurisdictional electric utility' s obligation for compliance with the goals set fo rth in subsection (c) of Section 1-75 of the Illinois Power Agency Act. This auth orization may include the transfer of existing contract obligation s. Copies of the initial long-term renewable resources procurement pl an and all subsequent revisions shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also b e provided to each affected electric utility. An affected utility and other interested parties shal l have 45 days following the date of posting to provide comment to the Agency on the initial long-term renewable resources procurement pla n and all subsequent revisions. All comments submi tted to the Agency shall be specific, supported by data or other detailed analyses, and, if objectin g to all or a portion of the procurement plan , accompanied by specific alternative wording or proposa ls. All comments shall be posted on the Agency's and Commiss ion's websites. During this 45-day comment period, the Agency shall hold at least one vir tual or in-person public heari ng for within each utility's service area that is s ubject to the requirements of this paragraph (5) for the purpose of receiving public comment. Within 21 d ays following the end of the 45-day review period, the Agency may revise the long-term renewable resources procurement plan based on the comment s received and shall file the plan with the Commission for re view and approval. (C) Within 14 days after the filing of the initial long-term renewable resourc es procurement plan or any subsequent revisions, an y person objecting to the plan may file an objectio n with the Commission. Within 21 days after the f iling of the plan, the Commission shall determ ine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the initia l long-term renewable resources procurement plan or any subsequent revis ions within 120 days after the filing of the plan by the Illino is Power Agency. (D) The Commission shall approve the initia l long-term renewable resources procurement plan and any subsequent revisions, including e xpressly the forecast used in the plan and taking into account that funding will be limited to the amount of revenues actually collect ed by the utilities, if the Commission determines that th e plan will reasonably and prudently accomplish the requi rements of Section 1-56 and subsection (c) o f Section 1-75 of the Illinois Power Agency Act. The Commission shall also approve the proce ss for the submission, review, and approv al of the proposed contracts to procure renewable e nergy credits or implement the programs authori zed by the Commission pursuant to a lo ng-term renewable resources procurement plan approved under this Section.

In approving any long-term renewable r esources procurement plan after the effective da te of this amendatory Act of the 102nd General Ass embly, the Commission shall approve or modify the Agency's pro posal for minimum equity standards pursuant to s ubsection (c-10) of Section 1-75 of the Illinois Power Agency Act. The Commission shall consider any analysis performed by the Age ncy in developing its proposal, including past performance, availability of equity eligible contractors, and availability of equity eligible persons at the time the long-term renewable resources procurement plan is approved. (iii) The Agency or third parties contracted by t he Agency shall implement all programs authorized by t he Commission in an approved long-term renewab le resources procurement plan without further review an d approval by the Commission. Third parties shall not begin implementing any programs or receive any payment under this Section until the Commission has approved the contract or contracts under the process authori zed by the Commission in item (D) of subparagraph (ii ) of paragraph (5) of this subsection (b) and the third party and the Agency or utility, as applicable, have executed the contract. For those renewable energy credits subject to procurement through a c ompetitive bid process under the plan or under the initial forward procurements for wind and solar resources described in subparagraph (G) of paragraph (1) of su bsection (c) of Section 1-75 of the Illino is Power Agency Act, the Agency shall follow the procur ement process specified in the provisions rela ting to electricity procurement in subsections (e) through (i ) of this Section. (iv) An electric utility shall recover its cos ts associated with the procurement of renewable energy credits unde r this Section and pursuant to subsection (c-5 ) of Section 1-75 of the Illinois Power Agen cy Act through an automatic adjustment clause tariff under subsecti on (k) or a tariff pursuant to subsection (i-5) , as applicable, of Section 16-108 of this Act. A utility shall not be required to advance any paym ent or pay any amounts under this Section that exceed the ac tual amount of revenues collected by the utility under parag raph (6) of subsection (c) of Section 1-75 of the I llinois Power Agency Act, subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, and subsecti on (k) or subsection (i-5), as applicable, of Section 16-108 of this Act, and con tracts executed under this Section shall expressly incorporate this limitation. (v) For the public interest, safety, and welfar e, the Agency and the Commission may adopt rules to car ry out the provisions of this Section on an emergency basis immediately fo llowing the effective date of this amendatory Act of th e 99th General Assembly. (vi) On or before July 1 of each y ear, the Commission shall hold an informal heari ng for the purpose of receiving commen ts on the prior year's procurement process and any recommendations fo r change. (6) Energy Storage System Resources Procurement Plan . The Agency shall prepare an energy storage system resou rces procurement plan for the procurement of energy storage system resources in compliance with this Section and subsection (d-20) of Section 1-75 of the Illinois Power Agency Act.

(i) The initial energy storage system resources procurement plan and all subsequent revisions shall be subject to review and approval by the Commission. For the purposes of this paragraph (6), "delivery year" has t he meaning given to that term in Section 1-10 of the Ill inois Power Agency Act, and "Agency" means the Illinois Power Agency. (ii) The energy storage system resources procurement planning process shall be conducted as follows: (A) The Agency shall pub lish for comment the initial energy storage system resources procurement plan no later than J une 1, 2027 and may revise the plan at least e very 2 years thereafter. To the extent practicabl e, the Agency shall review and propose any revisi ons to the energy storage system resources procure ment plan in conjunction with the Agency's long-term renewable resources proc urement plan. The initial energy storage system resources plan shall:

(aa) include a schedule for procureme nts for energy storage system resources consistent with subsection (d-20) of Section 1-75 of the Illinois Power Agency Act; and (bb) identify th e process whereby the Agency will submit to the Commission for review and approval t he proposed contracts to implement the programs required by the plan. Copies of the initial ene rgy storage system resources procurement pl an and all subsequent revisions shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also b e provided to each affected electric utility. An a ffected utility and other interested parties shall have 45 days after the date of posting to provide comment to the Agency on the initial storage system resources procurement plan and all subsequent revisions. All co mments shall be posted on the Agency's and the Commission's websites.

(B) The Commission shall approve the initial energy storage system resources procurement plan and any subsequent revis ions if the Commission determines that the plan will reasonabl y and prudently accomplish the requirements of subsection (d-20) of Section 1-75 of the Illinois Power Agency Act. The Commission shall also approve the process for the submission , review, and approval of the proposed contracts t o procure energy storage system resources or im plement the programs authorized by the Commission pursuant to an energy s torage system resources procurement plan approved under this Section.

(iii) The Agency or third parties contracted by the Agency shall implement all programs authorized by the Commission in an approved energy storage syst em resources procurement plan without further review an d approval by the Commission. Third parties shall not b egin implementing any programs or receive any payme nt under this Section until the Commission has approved a contract under the en ergy storage system resources procurement process under this Section. (iv) An electric utility shall recover its pruden t and reasonable costs associated with the procurement of energy storage system resources procurements under this Section and under subsection (d-20) of Sectio n 1-75 of the Illinois Power Agency Act through an a utomatic adjustment clause tariff under subsection (k) of S ection 16-108. (b-5) An electric utility that as of January 1, 2019 served more t han 300,000 retail customers in this State shall purch ase renewable energy credits from new renewable energy facilities constructed at or adjacent to the sites of coal-fueled electri c generating facilities in this State in accordance with subsection ( c-5) of Section 1-75 of the Illinois Power Agency Act and shall purchase energy storage credits, or oth er services as applicable, for energy storage system resources in accorda nce with subsection (d-20) of Section 1-75 of the Illinois Power Agency Act. Except as expressly provi ded in this Section, the plans and procedures for such p rocurements shall not be included in the procurement plans prov ided for in this Section, but rather shall be conducted and implemented solely in acco rdance with subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. (b-10) In r ecognition of the potential need to facilitate additional s upply to address any resource adequacy challenges through a stable and competitively neutral cost allocation mechanism, up on an identification of need by the Commission pursuant to the integrated resource planning process outlined in Sectio n 16-201, the procurement plan described in subs ection (b) may also include the procurement of energy, capacit y, environmental attributes, resource adequacy attribut es, or some combination thereof intended to serve all retail customers. An y procurements proposed under this subsection (b-10) s hall feature long-term contracts, shall be structured to facilitate new and additive supply resources, and shall be sized to ensure that the substantial majority of any load-serving entity's supply portfolio is not composed of contracts awarded under this subsection (b-10). (1) Facilities e ligible for long-term contracts under this subsection (b -10) must be new clean energy resources, as define d in Section 1-10 of the Illinois Power Agency Act, including clean generation associated high voltage di rect current transmission facilities, and must qual ify as an accredited capacity resource within the servi ce areas of PJM Interconnection, LLC, or Midcontinent Independe nt System Operator, Inc. For purposes of this subsection (b -10), "new" means energized on or after the effective date of this amendatory Act of the 104th General A ssembly. (2) Contracts may take the form of a sourcing agreeme nt, power purchase agreement, or other instrument as determined by the Commission in approving the plan, and may feature fixed or variable pricing structures, i ncluding utilization of a contract for differences in p ricing structure. Contracts may feature both electri c utilities and alternative retail electric suppliers a s counterparties. In approving the contract structure uti lized for any contract awards made pursuant to this subsect ion (b-10), the Commission shall prioritize structures that ensure stable, reliable, and competitively neutral allocations of costs and responsibiliti es. (3) Pu rchases made under contracts awarded through this subsection (b-10) shall be funded in a competiti vely neutral manner as determined by the Commission in appr oving the plan. To meet contract obligations, the Commission ma y order collections from all retail customers or from all load-serving entities, including alternative retail electr ic suppliers as defined in Section 16-102 of thi s Act, as a means of ensuring a fair and competitively neut ral allocation of contract costs. In establishing collections, the Agency may propose and the Commission may approve ad justments for load-serving entities that have contr acts entered into before the effective date of this amendatory Act of the 104t h General Assembly for energy, capacity, or environmental attribu tes. (4) The Agency may propose and the Commission may appro ve additional terms, conditions, and requirement s applicable to this procurement process through developm ent and approval of the Agency's annual electricity procurement p lan.

(5) The manner and form for developing co ntracts, qualifying potential counterparties, and awarding contracts shall be proposed as part of the annual electricity procurement plan described in this subsection (b-10). However, to the extent practicable, the proposed approach for contract development and award should endeavor to follow t he provisions of subsections (c) and (e) through (i) of this Section. ( 6) As further outlined in Section 16-115A, compliance with any procurement process proposed under this subsection (b-10) shall be considered a condition of service for alternative retai l electric suppliers. (c) The provi sions of this subsection (c) shall not apply to procurements condu cted pursuant to subsection (c-5) of Section 1-7 5 of the Illinois Power Agency Act. However, the Agency may ret ain a procurement administrator to assist the Agency i n planning and carrying out the procurement events and implementing the ot her requirements specified in such subsection (c-5) of Se ction 1-75 of the Illinois Power Agency Act, wit h the costs incurred by the Agency for the procurement adminis trator to be recovered through fees charged to applicants for select ion to sell and deliver renewable energy credits to electric utilitie s pursuant to subsection (c-5) of Section 1-75 of the Ill inois Power Agency Act. The procurement process set forth in Section 1-75 of the Illinois Power Agency Act and subsec tion (e) of this Section shall be admi nistered by a procurement administrator and monitored by a procurement monit or. (1) The procureme nt administrator shall: (i) design the final procurement proce ss in accordance with Section 1-75 of the Illinois Power Agency Act and subsec tion (e) of this Section following Commission approval of the procurement plan; (ii) develop benchmarks in accordance w ith subsection (e)(3) to be used to evaluate bids; th ese benchmarks shall be submitted to the Commission for review and approval on a confidential basis prior to the p rocurement event; (iii) serve as the interface between the electric utilit y and suppliers; (iv) manage the bidder pre-qualification and re gistration process; (v) obtain the electric utilities' agreem ent to the final form of all supply contracts and credit collateral agreements; (vi) administer the reque st for proposals process; (vii) have the discretion to negotiate to determine whether bidders are willing to lower the pri ce of bids that meet the benchmarks approved by the Co mmission; any post-bid negotiations with bid ders shall be limited to price only and shall be comp leted within 24 hours after opening the sealed bids and shall be conducted in a fair and unbiased ma nner; in conducting the negotiations, there shall be no disclosure of any information derived from prop osals submitted by competing bidders; if informa tion is disclosed to any bidder, it shall be provided to all competing bidders; (viii) maintain confidentiality of supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs; (ix) submit a conf idential report to the Commission recommending acceptance or r ejection of bids; (x) notify the utility of contract counterparties and cont ract specifics; and (xi) administer related contingency procurement events. (2) The procurement monitor, who shall be retained by th e Commission, shall: (i) mo nitor interactions among the procurement administrator, suppl iers, and utility; (ii) m onitor and report to the Commission on the progress of the pr ocurement process; (iii) provide an independent confid ential report to the Commission regarding the results of the p rocurement event; (iv) assess compliance with the procurement plans approved by the Commission for each utility that on December 31, 2005 provided electric service to at least 1 00,000 customers in Illinois and for each small multi-jurisdictional ut ility that on December 31, 2005 served less than 100,000 cust omers in Illinois; (v) preserve the confidentiality of supplier and bidding information in a manner consistent with all applicable laws, rules, regulat ions, and tariffs; (vi) provide expert advice to the Commission a nd consult with the procurement administrator regarding issues related to proc urement process design, rules, protocols, and policy-re lated matters; and (vii) consult with the procurement admi nistrator regarding the development a nd use of benchmark criteria, standard form contracts, credit policies, and bid documents. (d) Except as provided in subsection (j), the planning process shall be con ducted as follows: (1 ) Beginning in 2008, each Illinois utility procuring pow er pursuant to this Section shall annually provide a range o f load forecasts to the Illinois Power Agency by July 15 of each year, or such other date as may be required by the Co mmission or Agency. The load forecasts shall co ver the 5-year procurement planning period for the next procuremen t plan and shall include hourly data representing a high-load, low-load, and expected-load scen ario for the load of those retail customers included in th e plan's electric supply service requirements. The ut ility shall provide supporting data and assumptions for each of the scenarios. (2) B eginning in 2008, the Illinois Power Agency shall prepare a procurement plan by August 15th of each year, o r such other date as may be required by the Commission. Th e procurement plan shall identify the portfolio of demand-respons e and power and energy products to be procured. Cost-effective demand-response measures shall be pr ocured as set forth in item (iii) of subsection (b) of this Section. Copies of the procurement plan shall be pos ted and made publicly available on the Agency's and Com mission's websites, and copies shall also be provide d to each affected electric utility. An affected utilit y shall have 30 days following the date of posting to provide comment to the Agency on the procurement pl an. Other interested entities also may comment on the p rocurement plan. All comments submitted to the Agency s hall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the pro curement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commiss ion's websites. During this 30-day comment period, the Agency shall hold at least one virtual or in -person public hearing for within each utility's servic e area for the purpose of receiving public comment on the procu rement plan. Within 14 days following the end of the 30-day review period, the Agency shall revise the pr ocurement plan as necessary based on the comments received and file the proc urement plan with the Commission and post the procurement pl an on the websites. (3 ) Within 5 days after the filing of the procurement pl an, any person objecting to the procurement plan shall file an objection with the Commission. Within 10 days after the filing, the Commission shall determine whether a heari ng is necessary. The Commission shall enter its order confirming or modifying the procurement plan within 90 days after the filing of the procurement plan by the Illi nois Power Agency. (4) The Commission shall approve the procurement plan, inc luding expressly the forecast used in the procu rement plan, if the Commission determines that it will ensu re adequate, reliable, affordable, efficient, and environm entally sustainable electric service at the lo west total cost over time, taking into account any be nefits of price stability. (4.5) The Commission shall review the Agency's recommen dations for the selection of applicants to enter in to long-term contracts for the sale and delivery of renewable energy credits from new renewable energy faciliti es to be constructed at or adjacent to the sites of co al-fueled electric generating facilities in this State in acco rdance with the provisions of subsection (c-5) o f Section 1-75 of the Illinois Power Agency Act, an d shall approve the Agency's recommendations if the C ommission determines that the applicants recommended by the Agency for selection, the proposed new renewable energy facilities to be constructed, the amounts of r enewable energy credits to be delivered pursuant to the contra cts, and the other terms of the contracts, are consistent with the requi rements of subsection (c-5) of Section 1-7 5 of the Illinois Power Agency Act. (e) The procurement process shall include each of the followin g components: (1) Solicitation, pre-qualification, and registrati on of bidders. The procurement administrator shall di sseminate information to potential bidders to promote a procurem ent event, notify potential bidders that the procu rement administrator may enter into a post-bid pr ice negotiation with bidders that meet the applicable ben chmarks, provide supply requirements, and otherwise explain the competitive procurement process. In addition to such other publication as the procurement administrator det ermines is appropriate, this information shall be p osted on the Illinois Power Agency's and the Commis sion's websites. The procurement administrator sh all also administer the prequalification process, incl uding evaluation of credit worthiness, compliance wit h procurement rules, and agreement to the standard form c ontract developed pursuant to paragraph (2) of this subsection (e). The procurement administrator sh all then identify and register bidders to participate i n the procurement event. (2) Standard contract forms and credit terms a nd instruments. The procurement administrator, in consul tation with the utilities, the Commission, and other inter ested parties and subject to Commission oversight, shall develop and provide standard contract forms for the supplie r contracts that meet generally accepted industry practic es. Standard credit terms and instruments that meet generally accepted industry practices shall be simil arly developed. The procurement administrator sha ll make available to the Commission all written comments it receives on the contract forms, credit terms, or instrum ents. If the procurement administrator cannot r each agreement with the applicable electric utility as to the contract terms and conditions, the procurement admi nistrator must notify the Commission of any disputed terms and the Commission shall resolve the dispute. The term s of the contracts shall not be subject to negotiation by winning bidders, and the bidders must agree to the terms of the cont ract in advance so that winning bids are selected solely on the b asis of price. (3) Estab lishment of a market-based price benchmark. As part of the development of the procurement process, the procurement administrator, in consultation with th e Commission staff, Agency staff, and the procurement m onitor, shall establish benchmarks for evaluating the final prices in the contracts for each of the products th at will be procured through the procurement process. The benchmarks shall be based on price data for similar products for the same delivery period and same delivery h ub, or other delivery hubs after adjusting for that di fference. The price benchmarks may also be adjusted to tak e into account differences between the information refl ected in the underlying data sources and the specific prod ucts and procurement process being used to procure power fo r the Illinois utilities. The benchmarks shall be confiden tial but shall be provided to, and w ill be subject to Commission review and approval, prior to a procurement event. (4) Request for proposals competitive procurement pr ocess. The procurement administrator shall design an d issue a request for proposals to supply electricity in accordance with each utility's procurement plan, as appr oved by the Commission. The request for proposals shall set forth a procedure for sealed, binding commitment bidding with pay-as-bid settlement, and provision for selection of bids on t he basis of price. (5) A plan for implementing contingencies in the event of supplier default or failure of the procurement process to fully meet the expected load requirement due to insufficie nt supplier participation, Commission rejection of results, or any other cause. (i) Event of supplier default: In the event of supplier default, the utility shall review t he contract of the defaulting supplier to determ ine if the amount of supply is 200 megawatts or grea ter, and if there are more than 60 days remain ing of the contract term. If both of these conditio ns are met, and the default results in termination of the contract, the utility shall immediately notify the Illinois Power Agency that a request for prop osals must be issued to procure replacement power, and the procurement administrator shall run an add itional procurement event. If the contracted supply of the defaulting supplier is less than 200 megawatts or there are less than 60 days remaining of the cont ract term, the utility shall procure power and energ y from the applicable regional transmission organizati on market, including ancillary services, capa city, and day-ahead or real time energy, or both, for the duration of the contract term to repl ace the contracted supply; provided, however, that if a needed product is not available through the regional tr ansmission organization market it shall be purchased from the wholesale market. (ii) Failure of the procurement process t o fully meet the expected load requirement: If the proc urement process fails to fully meet the expected loa d requirement due to insufficient supplier p articipation or due to a Commission rejection of the procurement results, the procurement administrator, th e procurement monitor, and the Commission staff shall meet within 10 days to analyze potential causes of low supplier interest or causes for the Commissi on decision. If changes are identified that would likely result in increased supplier participation, or that would address concerns causing the Commission to reject the results of the prior procurement event, the procurement administrator may implement those changes and rerun the request for proposals process acco rding to a schedule determined by those parties and consistent with Section 1-75 of the Illinois Pow er Agency Act and this subsection. In any event, a new request for proposals process shall be implemented by the procurement administrator within 90 days after the determination that the procurement process has failed to fully meet the expect ed load requirement. (iii) In all cases where there is ins ufficient supply provided under contracts awarded throu gh the procurement process to fully meet the electri c utility's load requirement, the utility shall me et the load requirement by procuring power and energ y from the applicable regional transmission organization market, including ancillary services, capacity, an d day-ahead or real time energy, or both; provid ed, however, that if a needed product is not available through the regional tr ansmission organization market it shall be purchased f rom the wholesale market. (6) The p rocurement processes described in this subsection and in su bsection (c-5) of Section 1-75 of the Illi nois Power Agency Act are exempt from the re quirements of the Illinois Procurement Code, pursuant to S ection 20-10 of that Code. (f) Wit hin 2 business days after opening the sealed bids, the procurem ent administrator shall submit a confidential report to the Commission. The report shall contain the results of the b idding for each of the products along with the procurement a dministrator's recommendation for the acceptance and reject ion of bids based on the price benchmark criteria and o ther factors observed in the process. The procurement monit or also shall submit a confidential report to the Commiss ion within 2 business days after opening the sealed bids. T he report shall contain the procurement monitor's assessment o f bidder behavior in the process as well as an assessment of th e procurement administrator's compliance with the proc urement process and rules. The Commission shall review the confidential reports submitted by the procurement administra tor and procurement monitor, and shall accept or reject the recommendat ions of the procurement administrator within 2 business d ays after receipt of the reports. (g) Wi thin 3 business days after the Commission decision approvin g the results of a procurement event, the utility shall ente r into binding contractual arrangements with the winning s uppliers using the standard form contracts; except that the utility shall not be required either directly or indirec tly to execute the contracts if a tariff that is consistent with sub section (l) of this Section has not been approved and pl aced into effect for that utility. (h) F or the procurement of standard wholesale products, the names of the successful bidders and the load weighted average of the w inning bid prices for each contract type and for each contra ct term shall be made available to the public at the time of C ommission approval of a procurement event. For procurements conducted to meet the requirements of subsection (b) of Section 1-56 or subsection (c) of Section 1-75 of the Illinoi s Power Agency Act governed by the provisions of this Secti on, the address and nameplate capacity of the new renewable en ergy generating facility proposed by a winning bidder shall al so be made available to the public at the time of Commiss ion approval of a procurement event, along with the business ad dress and contact information for any winning bidder. A n estimate or approximation of the nameplate capacity of the new renewable energy generating facil ity may be disclosed if necessary to protect the confiden tiality of individual bid prices. The Commiss ion, the procurement monitor, the procurement administrator, t he Illinois Power Agency, and all participants in the proc urement process shall maintain the confidentiality of all oth er supplier and bidding information in a manner consistent wit h all applicable laws, rules, regulations, and tariffs. Confidential information, including the confidential r eports submitted by the procurement administrator and procureme nt monitor pursuant to subsection (f) of this Section, shall not be made publicly available and shall not be discov erable by any party in any proceeding, absent a comp elling demonstration of need, nor shall those reports be admissible in any proceeding other than one for law enforcement purposes. For procurem ents conducted to meet the requirements of subsection (b) of Sec tion 1-56 or subsection (c) of Section 1- 75 of the Illinois Power Agency Act, the Illinois Power Age ncy may release aggregated information related to participati on levels across product types and the basis of rejection fo r non-accepted bids if the Commission, the procurem ent monitor, the procurement administrator, and the Illinois Po wer Agency determine that the release of this information wo uld not result in the disclosure of confidential bid informa tion or negatively impact the competitiveness of future renew able energy credit procurements. The Agency may also release informa tion about the development status of new renewable energy proj ects under contract and project-specific information abou t renewable energy credit delivery quantities for projects unde r contract if the Commission, the procurement monitor, the p rocurement administrator, and the Illinois Power Agency deter mine that the release of this information would not result in the disclosure of confidential bid information or negati vely impact the competitiveness of future renewable ene rgy credit procurements. (i) W ithin 2 business days after a Commission decision approving t he results of a procurement event or such other date as may be required by the Commission from time to time, the utility shall file for informational purposes with the Commission its actual or estimated retail supply charges, as applicab le, by customer supply group reflecting the costs associat ed with the procurement and computed in accordance with th e tariffs filed pursuant to subsection (l) of this Section and approved by the Commission. (j) Wit hin 60 days following August 28, 2007 (the effective date of Public Act 95-481), each electric utility that on December 31, 2005 provided electric service to at least 100,0 00 customers in Illinois shall prepare and file with the Com mission an initial procurement plan, which shall conform in all material respects to the requirements of the procuremen t plan set forth in subsection (b); provided, however, that the Illinois Power Agency Act shall not apply to the in itial procurement plan prepared pursuant to this subsectio n. The initial procurement plan shall identify the portfolio of power and energy products to be procured and delivered for the period June 2008 through May 2009, and shall identify the proposed procurement administrator, who shall have the same ex perience and expertise as is required of a procurement adminis trator hired pursuant to Section 1-75 of the Illinois Power Agency Act. Copies of the procurement plan shall be posted and made publicly available on the Commission's website. The initial procurement plan may include contracts for renewable resources that e xtend beyond May 2009. ( i) Within 14 days following filing of the initial pr ocurement plan, any person may file a detailed objection with the Commission contesting the procurement plan subm itted by the electric utility. All objections to the elect ric utility's plan shall be specific, supported by data or other detailed analyses. The electric utility may fil e a response to any objections to its procurement plan with in 7 days after the date objections are due to be filed. Within 7 days after the date the utility's respon se is due, the Commission shall determine whether a hear ing is necessary. If it determines that a hearing is neces sary, it shall require the hearing to be completed and is sue an order on the procurement plan w ithin 60 days after the filing of the procurement plan by the electric utility. (i i) The order shall approve or modify the procurement plan, approve an independent procurement administrator, a nd approve or modify the electric utility's tariffs t hat are proposed with the initial procurement plan. The Commission shall approve the procurement plan if the Commission determines that it will ensure adequate, rel iable, affordable, efficient, and environmentally sustainable electric servic e at the lowest total cost over time, taking into account any benefits of price stability. (k) (Blank). (k-5) (Blank). (l) An electric utility shall recover its costs incurred under this Section and subse ction (c-5) of Section 1-75 of the Illinois Power Agency Act, including, but not limited to, the costs of procurin g power and energy demand-response resources under this Section and i ts costs for purchasing renewable energy credits pursuant to su bsection (c-5) of Section 1-75 of the Illinois P ower Agency Act. The utility shall file with the initial proc urement plan its proposed tariffs through which its costs of proc uring power that are incurred pursuant to a Commission-approved procurement plan and those other costs identifi ed in this subsection (l), will be recovered. The tarif fs shall include a formula rate or charge designed to pa ss through both the costs incurred by the utility in procuring a su pply of electric power and energy for the applicable customer classes with no mark-up or return on the price paid by the utility for that supply, plus any just and reasonab le costs that the utility incurs in arranging and providin g for the supply of electric power and energy. The formula ra te or charge shall also contain provisions that ensure that its application does not result in over or under recovery due to changes in customer usage and demand patterns, and that provide for the correction, on at least an annual basis, of an y accounting errors that may occur. A utility shall recov er through the tariff all reasonable costs incurred to implement or comply with any procurement plan that is developed and p ut into effect pursuant to Section 1-75 of the Illinois P ower Agency Act and this Section, and for the procurement of renewab le energy credits pursuant to subsection (c-5) of Se ction 1-75 of the Illinois Power Agency Act, includin g any fees assessed by the Illinois Power Agency, costs associ ated with load balancing, and contingency plan costs. The el ectric utility shall also recover its full costs of procuri ng electric supply for which it contracted before the effective date of this Section in conjunction with the provision of fu ll requirements service under fixed-price bundled serv ice tariffs subsequent to December 31, 2006. All such costs shall be deemed to have been prudently incurred. The pass-through tariffs that are filed and approved pursuant to this Section shall not be subject to review under, or in any way limited by, Section 16-111(i) of this Act. All of the costs incurred by the elec tric utility associated with the purchase of zero emission credits in accordance with subsection (d-5) of Section 1- 75 of the Illinois Power Agency Act, all costs incurred by the electric utility associated with the purchase of carbon mitigation cre dits in accordance with subsection (d-10) of Sectio n 1-75 of the Illinois Power Agency Act, and, beginni ng June 1, 2017, all of the costs incurred by the electric utility associa ted with the purchase of renewable energy resources in accordanc e with Sections 1-56 and 1-75 of the Illinois Power Agency Act, and all of the costs incurred by the electric utility i n purchasing renewable energy credits in accordance with s ubsection (c-5) of Section 1-75 of the Illinois P ower Agency Act, shall be recovered through the electric utilit y's tariffed charges applicable to all of its retail customers, as specifie d in subsection (k) or subsection (i-5), as applica ble, of Section 16-108 of this Act, and shall not be re covered through the electric utility 's tariffed charges for electric power and energy suppl y to its eligible retail customers. (m) The Commission has the authority to adopt rules to car ry out the provisions of this Section. For the public interes t, safety, and welfare, the Commission also has authority to ad opt rules to carry out the provisions of this Section on an emergency ba sis immediately following August 28, 2007 (the effective date of Public Act 95-481). (n) Notwith standing any other provision of this Act, any affiliated electric utilities that submit a single procurement plan cov ering their combined needs may procure for those combined needs in conjunction with that plan, and may enter jointly into power supply contracts, purchases, and other procurement arran gements, and allocate capacity and ene rgy and cost responsibility therefor among themselves in pr oportion to their requirements. (o) On or bef ore June 1 of each year, the Commission shall ho ld an informal hearing for the purpose of recei ving comments on the prior year's procurement proces s and any recommendations for change. (p) An electric utility subject to this Section may propose to invest, lease, own, or operate an electric generation facility a s part of its procurement plan, provided the utility demonstr ates that such facility is the least-cost option to pro vide electric service to those retail customers included in the pl an's electric supply service requirements. If the facility is shown to be the least-cost option and is included in a procurement plan prepared in accordance with Section 1-75 of the Illinois Power Agency Act and this Section, then the electric utility shall make a filing pursuant to Section 8-406 of this Act, and may request of the Commissi on any statutory relief required thereunder. If the Commission grants all of the necessary approvals for the proposed facili ty, such supply shall thereafter be considered as a pre -existing contract under subsection (b) of this Sectio n. The Commission shall in any order approving a proposal under this subsection specify how the utility will recover the prude ntly incurred costs of investing in, leasing, owning, or operat ing such generation facility through just and reasonable rates charged to those retail customers included in the plan's e lectric supply service requirements. Cost recovery for faci lities included in the utility's procurement plan pursuan t to this subsection shall not be subject to review under or in any way limited by the provisions of Section 16-111(i) of thi s Act. Nothing in this Section is intended to prohibit a utility from filing for a fuel adjustment clause as is otherwise permitt ed under Section 9-220 of this Act. (q) If the Illinois Power Agency filed with the Commission, under S ection 16-111.5 of this Act, its proposed procurement p lan for the period commencing June 1, 2017, and the Commission h as not yet entered its final order approving the plan on or b efore the effective date of this amendatory Act of the 99th G eneral Assembly, then the Illinois Power Agency shall file a n otice of withdrawal with the Commission, after the effective date of this amendatory Act of the 99th General Assembly, to w ithdraw the proposed procurement of renewable energy reso urces to be approved under the plan, other than the procure ment of renewable energy credits from distributed renewable en ergy generation devices using funds previously collected from electric utilities' retail customers that take service pursuan t to electric utilities' hourly pricing tariff or tari ffs and, for an electric utility that serves less than 10 0,000 retail customers in the State, other than the procu rement of renewable energy credits from distributed renewable energy generation devices. Upon receipt of the notice, the Commission shall enter an order that approves the withdrawal of the proposed procurement of renewable energy resources fro m the plan. The initially proposed procurement of renewable en ergy resources shall not be approved or be the subject of any further hearing, investigation, p roceeding, or order of any kind. This amendatory Act of the 99th General Assembly preempts and super sedes any order entered by the Commission that appro ved the Illinois Power Agency's procurement plan for the period commencing June 1, 2017, to the extent it is inconsistent w ith the provisions of this amendatory Act of the 99th General Assembly. To the extent any previously entered order approved the procurement of renewable energy resources, the portion o f that order approving the procurement shall be void, other than the procurement of renewable energy credits from dist ributed renewable energy generation devices using funds previ ously collected from electric utilities' retail customers th at take service under electric utilities' hourly pricing tarif f or tariffs and, for an electric utility that serves less than 100,000 retail customers in the State, other than the procurement of renewable energy credits for distributed renewable energy generation devices. (S ource: P.A. 102-662, eff. 9-15-21.) (220 ILCS 5/16-111.7) Sec. 16-111.7. On-bill financing program; electric utilities. (a) The Illinois General Assembly finds that Illinois homes and businesses have the potential to save energy through conservation and c ost-effective energy efficiency measures. Programs crea ted pursuant to this Section will allow util ity customers to purchase cost-effective energy efficiency measures, including measures set forth in a Commission-approved energy effic iency and demand-response plan under Section 8-103 or 8-103B of this Act, with no required initial upfront pa yment, and to pay the cost of those products and service s over time on their utility bill. (b) Notwithstanding any other provision of this Act, an electric utility serving more than 100,000 customers on January 1, 2009 shall o ffer a Commission-approved on-bill financing program ("pr ogram") that allows its eligible retail customers, as that term is defined in Section 16-111.5 of this A ct, who own a residential single family home, duplex, or oth er residential building with 4 or less units, or condomini um at which the electric service is being provided (i) to bo rrow funds from a third party lender in order to purchase electric energy efficiency measures approved under the program for installation in such home or condominium without any r equired upfront payment and (ii) to pay back such funds over time through the electric utility's bill. Based upon the pro cess described in subsection (b-5) of this Section, sm all commercial customers who own the premises at which el ectric service is being provided may be included in suc h program. After receiving a request from an electric util ity for approval of a proposed program and tariffs pursuant to this Section, the Commission shall render its decision within 120 days. If no decision is rendered within 120 days, then the requ est shall be deemed to be approved. Beginn ing no later than December 31, 2013, an electric utility s ubject to this subsection (b) shall also offer its program to eligible retail customers that own multifamily residential or m ixed-use buildings with no more than 50 residential unit s, provided, however, that such customers must either be a resid ential customer or small commercial customer and may not use the program in such a way that repayment of the cost of energ y efficiency measures is made through tenants' utility bills . An electric utility may impose a per site loan limit not to exceed $150,000. The program, and loans issued thereunder, sha ll only be offered to customers of the utility that meet the requirements of this Section and that also have an elec tric service account at the premises where the energy effici ency measures being financed shall be installed. Beginnin g no later than 2 years after the effective date of this amend atory Act of the 99th General Assembly, the 50 residential u nit limitation described in this paragraph shall no longer app ly, and the utility shall replace the per site loan limi t of $150,000 with a loan limit that correlates to a maximum m onthly payment that does n ot exceed 50% of the customer's average utility bill over the prior 12-month period. Begi nning no later than 2 years after the effective date of thi s amendatory Act of the 99th General Assembly, an electric ut ility subject to this subsection (b) shall also offer its prog ram to eligible retail customers that are Unit Owners' Associa tions, as defined in subsection (o) of Section 2 of the Con dominium Property Act, or Master Associations, as defined in subsection (u) of the Condominium Property Act. However, such customers must either be residential customers or small co mmercial customers and may not use the program in such a way that repayment of the cost of energy efficiency measu res is made through unit owners' utility bills. The program and loans issued under the program shall only be offered to custom ers of the utility that meet the requirements of this Secti on and that also have an electric service accoun t at the premises where the energy efficiency measures bei ng financed shall be installed. For purp oses of this Section, "small commercial customer" means, for an electric utility serving more than 3,000,000 retail custome rs, those customers having peak demand of less than 100 kilow atts, and, for an electric utility serving less than 3,000,000 retail customers, those customers having peak demand of le ss than 150 kilowatts; provided, however, that in the event th e Commission, after the effective date of this amendatory A ct of the 98th General Assembly, approves changes to a utility' s tariffs that reflects new or revised demand criteria for the utility's customer rate classifications, then the utility m ay file a petition with the Commission to revise the applicable definition of a small commercial customer to reflect the new or revised demand criteria for the purposes of this Section. After notice and hearing, the Commission shall enter an order approving, or approving with modification, the revised definition within 60 days after th e utility files the petition. (b-5) Within 30 days after the effective date of this amendato ry Act of the 96th General Assembly, the Commission shal l convene a workshop process during which interested participa nts may discuss issues related to the program, includin g program design, eligible electric energy efficiency measures, vendor qualifications, and a methodology for ensu ring ongoing compliance with such qualifications, financing, sample documents such as request for proposals, contracts and agreem ents, dispute resolution, pre-installment and post-installment verification, and evaluation. The workshop pr ocess shall be completed wit hin 150 days after the effective date of this amendator y Act of the 96th General Assembly. (c) Not later than 60 days following completion of the workshop pro cess described in subsection (b-5) of this Section, each electric utility subject to subsection (b) of this Section shall subm it a proposed program to the Commission that contains the f ollowing components: (1) A l ist of recommended electric energy efficiency measures t hat will be eligible for on-bill financing. An eligib le electric energy efficiency measure ("measure" ) shall be a product or service for which one or more o f the following is true: (A) (blank); (B) the projected electricity savings ( determined by rates in effect at the time of purchas e) are sufficient to cover the costs of implementing t he measures, including finance charges an d any program fees not recovered pursuant to subsection (f) of this Section; or (C) the product or service is included in a Commission-approved energy efficiency and dem and-response plan under Section 8-103 or 8 -103B of this Act. (1.5) Beginning no later than 2 years after the effect ive date of this amendatory Act of the 99th General Ass embly, an eligible electric energy efficiency measure ( measure) shall be a product or service that qualifies under subparagraph (B) or (C) of paragrap h (1) of this subsection (c) or for which one or more of the f ollowing is true: (A) a building energy assessment, performed by an energy auditor who is certified by the Building Performance Institute or who holds a similar certification, has recommended the product or servic e as likely to be cost effective over the course of its installed life for the building in which the measure is to be installed; or

(B) the product or service is necessary to sa fely or correctly install to code or industry sta ndard an efficiency measure, including, but no t limited to, installation work; changes needed to pl umbing or electrical connections; upgrades to wiring or fixtures; removal of hazardous materials; correction of leaks; changes to thermostats, controls, or similar devices; and changes to venting or exhaust necessitated by the measure. However, the costs of th e product or service described in this subp aragraph (B) shall not exceed 25% of the total cost of in stalling the measure. (2) The electric utility shall issue a request for pr oposals ("RFP") to lenders for purposes of providing financ ing to participants to pay for approved measures. The R FP criteria shall include, but not be limited to, the interest rate, origination fees, and credit terms. The uti lity shall select the winning bidders based on its evaluat ion of these criteria, with a preference for t hose bids containing the rates, fees, and terms most favora ble to participants;

(3) The utility shall work with the lenders sele cted pursuant to the RFP process, and with vendors , to establish the terms and processes pursuant to which a participant can purchase eligible electric energy effic iency measures using the financing obtained from the lender. The vendor shall explain and offer the approved fi nancing packaging to those customers identified in subsecti on (b) of this Section and shall assist customers in appl ying for financing. As part of the process, vendors shall also provide to participants information about any other incentives that may be available for the measures. (4) The lender shall conduct credit checks or undertake other appropriate measures to limit c redit risk, and shall review and approve or deny financ ing applications submitted by customers identified in su bsection (b) of this Section. Following the lender's appro val of financing and the participant's purchase of the meas ure or measures, the lender shall forward payment informa tion to the electric utility, and the utility shall add as a separate line item on the participa nt's utility bill a charge showing the amount due under t he program each month. (5) A loan issued to a participant pursuant to th e program shall be the sole responsibility of the parti cipant, and any dispute that may arise concerning the loa n's terms, conditions, or charges shall be resolved betwe en the participant and lender. Upon transfer of th e property title for the premises at which the part icipant receives electric service from the utility or the participant's request to terminate service at such premise s, the participant shall pay in full its electric utility bill, including all amounts due under the program, provid ed that this obligation may be modified as provided in sub section (g) of this Section. Amounts due under the program shall be deemed amoun ts owed for residential and, as appropriate, small commerci al electric service. (6 ) The electric utility shall remit payment in full to the lender each month on behalf of the participant. In t he event a participant defaults on payment of its electric utility bill, the electric utility shall continue to re mit all payments due under the program to the lend er, and the utility shall be entitled to recover all costs related to a participant's nonpayment through the automatic ad justment clause tariff established pursuant to Section 16-111.8 of this Act. In addition, the electric util ity shall retain a security interest in the measure or measures purchased under the program, and the utility retains its righ t to disconnect a participant that defaults on the payment of its utility bill. (7) T he total outstanding amount financed under the program in this subsection and subsection (c-5) of thi s Section shall not exceed $2.5 million for an electric utility or electric utilities under a single holding comp any, provided that the electric utility or electric util ities may petition the Commission for an increase in su ch amount. Beginning after the effective date of this ame ndatory Act of the 99th General Assembly, the total maximum outstandi ng amount financed under the program in this subsection a nd subsections (c-5) and (c-10) of this Se ction shall increase by $5,000,000 per year until s uch time as the total maximum outstanding amount financed r eaches $20,000,000. For purposes of this Section, "maximum outstanding amount financed" means the sum of all principal that has bee n loaned and not yet repaid. (c-5) Within 120 days after the effective date of this amendato ry Act of the 98th General Assembly, each electric uti lity subject to the requirements of this Section shall subm it an informational filing to the Commission that describ es its plan for implementing the provisions of this amendat ory Act of the 98th General Assembly on or before December 31, 2013. Such filing shall also describe how the electric utility shall coordinate its program with any gas utility or u tilities that provide gas service to buildings within the elect ric utility's service territory so that it is practical and fe asible for the owner of a multifamily building to make a single application to acc ess loans for both gas and electric energy efficiency measures i n any individual building. (c-1 0) No later than 365 days after the effective date of this am endatory Act of the 99th General Assembly, each electric uti lity subject to the requirements of this Section shall subm it an informational filing to the Commission that desc ribes its plan for implementing the provisions of this amendato ry Act of the 99th General Assembly that were incorporated into this Section. Such filing shall also include th e criteria to be used by the program for determining i f measures to be financed are eligible electric ene rgy efficiency measures, as defined by paragraph (1. 5) of subsection (c) of this Section. (d) A program approved by the Commis sion shall also include the following criteria and guidel ines for such program:

(1) guidelines for financing of measures installed under a program, including, but not limited to, RFP cri teria and limits on both individual loan amounts and the duration of the loans; (2) criteria and standards for identifying and approving measures; (3) qualifications of vendors that will market or install measures, as well as a methodology for ensuring ongoing compliance w ith such qualifications; (4) sampl e contracts and agreements necessary to implement the measu res and program; and (5) the types of data and information that utilities and vendors participating in the program shall co llect for purposes of preparing the reports required under subsection (g) of this Section. (e) The proposed program submitted by each electric ut ility shall be consistent with the provisions of this Section that define operational, financial and billing arrang ements between and among program participants, vendors, len ders, and the electric utility. (f) An electric utility shall recover all of the prudently incurred costs of offering a program approved by the Commission pursuant to this Section, including, but not limited to, al l start-up and administrative costs and the costs for pro gram evaluation. All prudently incurred costs under t his Section shall be recovered from the residential and smal l commercial retail customer classes eligible to participate in the progra m through the automatic adjustm ent clause tariff established pursuant to Section 8-103 or 8-103B of this Act. (g) An independent evaluation of a program shall be conduc ted after 3 years of the program's operation. The electric util ity shall retain an independent evaluator who shall evaluate the effects of the measures installed under the program and th e overall operation of the program, including, but no t limited to, customer eligibility criteria and whether the pa yment obligation for permanent electric energy efficiency measu res that will continue to provide benefits of energy savi ngs should attach to the meter location. As part of the eval uation process, the evaluator shall also solicit feedbac k from participants and interested stakeholders. The evalua tor shall issue a report to the Commission on its findings no later than 4 years after the date on which the program commen ced, and the Commission shall issue a report to the G overnor and General Assembly including a summary of the information described in this Section as well as its recom mendations as to whether the program should be discontinued, c ontinued with modification or modifications or continued with out modification, provided that any recommended m odifications shall only apply prospectively and to measures n ot yet installed or financed. (h) An ele ctric utility offering a Commission-approved program pu rsuant to this Section shall not be required to comply with any other statute, order, rule, or regulation of this State tha t may relate to the offering of such program, provided that no thing in this Section is intended to limit the electric util ity's obligation to comply with this Act and the Commission's orders, r ules, and regulations, including Part 280 of Title 83 o f the Illinois Administrative Code. (i) The source of a utility customer's electric supply shall not disqual ify a customer from participation in the utility's on-bil l financing program. Customers of alternative retail elect ric suppliers may participate in the program under the same terms and conditions applicable to the utility's supply cus tomers. (j) This Section is repealed on January 1, 2027. (Source: P.A. 98-586, eff. 8-27-13; 99-906, eff. 6-1-17.) (220 ILCS 5/16-115A) Sec. 16-115A. Obligations of alternative retail electric suppliers. (a) An alternative re tail electric supplier: (i) shall comply with the requirements imposed on public utilities by Sections 8-201 through 8-207, 8-301, 8-505 and 8-507 of this Act, to the extent that these Sections have applica tion to the services being offered by the alternative reta il electric supplier; (ii) shall continue to comply with the r equirements for certification stated in subsection (d) of Section 16-115; (iii) by May 31, 2020 and every June 30 thereafter, shall submit to the Commission and the Office of the Attorney General the rates the retail electric supplier c harged to residential customers in the prior year, includ ing each distinct rate charged and whether the rate was a f ixed or variable rate, the basis for the variable ra te, and any fees charged in addition to the supply rate, including monthly fees, flat fees, or other service charges; and (iv) shall make publicly available on its website, without the need for a customer login, rate information for all of i ts variable, time-of-use, and fixed rate c ontracts currently available to residential customers, including, but not limited to, fixed monthly charges, early termination fees , and kilowatt-hour charges; . (v) shall provide to the Commission, in the form and manner requested, the information necessary for the Commission to compile and submit the integrated resource plan required under Section 16-201; and (vi) shall com ply with the Commission's determinations made pursuan t to subsection (b-10) of Section 16-111. 5, including, but not limited to, the imposition of any collections, the execution of any c ontracts, and the required performance under any contract s developed thereunder. (b) An alt ernative retail electric supplier shall obtain verifiable auth orization from a customer, in a form or manner approved by t he Commission consistent with Section 2EE of the Consumer Fraud an d Deceptive Business Practices Act, before the customer i s switched from another supplier. (c) No alt ernative retail electric supplier, or electric utility oth er than the electric utility in whose service area a custo mer is located, shall (i) enter into or employ any arrangem ents which have the effect of preventing a retail customer w ith a maximum electrical demand of less than one megawatt from having access to the services of the electric utility in whose service area the customer is located or (ii) charge retail customers for such access. This subsection shall not be construed to prevent an arms-length agreement between a supplier and a retail customer that sets a term of service, notice period f or terminating service and provisions go verning early termination through a tariff or contra ct as allowed by Section 16-119. ( d) An alternative retail electric supplier that is certified to serve residential or small commercial retail customers shall not: (1) deny service to a customer or group of custom ers nor establish any differences as to prices, terms, conditions, services, products, facilities, or in any ot her respect, whereby such denial or differences are based upon race, gender or income, except as provided in Se ction 16-115E. (2) deny service to a customer or group of cust omers based on locality nor establish any unreasonable difference as to pric es, terms, conditions, services, products, or facilities as between localities. (3) warrant that it has a residential cust omer or small commercial retail customer's express consent agre ement to access interval data as described in subsection (b ) of Section 16-122, unless the alternative retail electr ic supplier has:

(A) disclosed to the consumer at the outset of the offer that the alternative retail electr ic supplier will access the consumer's interval d ata from the consumer's utility with the consumer's express agreement and the consumer's option to refuse to provide express agreement to access the consumer's i nterval data; and (B) obtained the consumer's express agreement for the alternative retail electric supplier to access the consumer's interval data from the consumer's utili ty in a separate letter of agency, a distinct res ponse to a third-party verification, or as a separate affirmative consent during a recorded enro llment initiated by the consumer. The disclosure b y the alternative retail electric supplier to the consu mer in this Section shall be conducted in, translate d into, and provided in a language in whic h the consumer subject to the disclosure is able to understa nd and communicate. (4) rel ease, sell, license, or otherwise disclose any customer interval data obtained under Section 16-122 to any third perso n except as provided for in Section 16-122 and para graphs (1) through (4) of subsecti on (d-5) of Section 2EE of the Consumer Fraud and D eceptive Business Practices Act. (e) An alte rnative retail electric supplier shall comply with the followi ng requirements with respect to the marketing, offering and provisio n of products or services to residential and small com mercial retail customers: (i) All marketing materials, including, but not limited t o, electronic marketing materials, in-person solici tations, and telephone solicitations, shall contain information that adequately discloses the prices, te rms, and conditions of the products or services that th e alternative retail electric supplier is offering or selli ng to the customer and shall disclose the current utility electric supply price to compare applicable at the time the alternative retail electric supplier is offering o r selling the products or services to the customer and sh all disclose the date on which the utility electric supply price to compare became effective and the date on which it will expire. The utility electric supply price to compare s hall be the sum of the electric supply charge and the t ransmission services charge and shall not include the p urchased electricity adjustment. The disclosure shall include a statement that the price to compare does not include the purchased electricity adjustment, and, i f applicable, the range of the purchased electricity adjustm ent. All marketing materials, including, but not limited t o, electronic marketing materials, in-person soli citations, and telephone solicitations, shall include the following statement: "(Name of the alternative retail elec tric supplier) is not the same entity as your el ectric delivery company. You are not required to en roll with (name of alternative retail electric su pplier). Beginning on (effective date), the electric su pply price to compare is (price in cents per kilow att hour). The electric utility electric supply price w ill expire on (expiration date). The utility electric s upply price to compare does not include the purchased electricity adjustment factor. For more information g o to the Illinois Commerce Commission's free website at ww w.pluginillinois.org. If applicable, the statement shall also include the fo llowing statement: "The purchased electricity adjustme nt factor may range between +.5 cents and -.5 cen ts per kilowatt hour.". This paragraph (i) does not apply to goodwill or inst itutional advertising. (ii) Before any customer is switched from another su pplier, the alternative retail electric supplier sha ll give the customer written information that adequately d iscloses, in plain language, the prices, terms and condi tions of the products and services being offered and sol d to the customer. This written information shall be pro vided in a language in which the customer subject to the m arketing or solicitation is able to understand and commu nicate, and the alternative retail electric supplier sha ll not switch a customer who is unable to understan d and communicate in a language in which the marketing or solicitation was conducted. The alternative retail electric supplier shall comp ly with Section 2N of the Consumer Fraud and Deceptive Bus iness Practices Act.

(iii) An alternative retail electric supplier shall pr ovide documentation to the Commission and to customers t hat substantiates any claims made by the alternative re tail electric supplier regarding the technologie s and fuel types used to generate the electricity offered or sold to customers. (iv) The alternative retail electric supplier shall pro vide to the customer (1) itemized billing stateme nts that describe the products and services provided to the customer and their prices, and (2) an additional state ment, at least annually, that adequately discloses the average monthly prices, a nd the terms and conditions, of the products and services sold to t he customer. (v) All in -person and telephone solicitations shall be conducted in, translated into, and provided in a langu age in which the consumer subject to the marketing or s olicitation is able to understand and communicate. An alt ernative retail electric supplier shall terminate a solic itation if the consumer subject to the marketing or com munication is unable to understand and communicate in the language in which the marketing or solicitation is bei ng conducted. An alternative retail electric supplier shall com ply with Section 2N of the Consumer Fraud and Deceptive Bus iness Practices Act. (vi ) Each alternative retail electric supplier shall conduct trai ning for individual representatives engaged in in- person solicitation and telemarketing to residential custom ers on behalf of that alternative retail electric su pplier prior to conducting any such solicitations on the alternative retail electric supplier's behalf. Each alte rnative retail electric supplier shall submit a copy of its training material to the Commission on an annua l basis and the Commission shall have the right to review and require updates to the material. After initial training, each alternative retail electric supplier shall be required to conduct refresher training for its individual representatives every 6 months. (f) An alternative retail electric supplier may limit the overal l size or availability of a service offering by specifying one or more of the following: a maximum number of customers, max imum amount of electric load to be served, time period d uring which the offering will be available, or other comparab le limitation, but not including the geographic locatio ns of customers within the area which the alternative retail e lectric supplier is certificated to serve. The alternative re tail electric supplier shall file the terms and conditions o f such service offering including the applicable li mitations with the Commission prior to making the service offering available to customers. (g ) Nothing in this Section shall be construed as preventing an alternative retail electric supplier, which is an af filiate of, or which contracts with, (i) an industry or trad e organization or association, (ii) a membership or ganization or association that exists for a purpose other than the purchase of electricity, or (iii) another organization th at meets criteria established in a rule adopted by the Commiss ion, from offering through the organization or associat ion services at prices, ter ms and conditions that are available solely to the members of the organization or association.(Source: P.A. 102-459, eff. 8-2 0-21; 103-237, eff. 6-30-23.) (220 ILCS 5/16-119A) Sec. 16-119A. Fu nctional separation. (a) Wi thin 90 days after the effective date of this amendator y Act of 1997, the Commission shall open a rulemaking pr oceeding to establish standards of conduct for every electric u tility described in subsection (b). To create efficient co mpetition between suppliers of generating services and se llers of such services at retail and wholesale, the rules s hall allow all customers of a public utility that dist ributes electric power and energy to purchase electric power and ener gy from the supplier of their choice in accordance with the p rovisions of Section 16-104. In addition, the ru les shall address relations between providers of any 2 servi ces described in subsection (b) to prevent undue discriminatio n and promote efficient competit ion. Provided, however, that a proposed rule shall n ot be published prior to May 15, 1999. (b) The Commission shall also have the authority to invest igate the need for, and adopt rules requiring, functional sepa ration between the generation services and the delivery service s of those electric utilities whose principal service a rea is in Illinois as necessary to meet the objective of creati ng efficient competition between suppliers of generating ser vices and sellers of such services at retail and wholesale . After January 1, 2003, the Commission shall also have the authority to investigate the need for, and adopt rules requiring, functiona l separation between an electric utility's competitive and non-competitive services. (b- 5) If there is a change in ownership of a majority of the v oting capital stock of an electric utility or the ownership o r control of any entity that owns or controls a majority of the voting capital stock of an electric utility, the electr ic utility shall have the right to file with the Commission a new plan. The newly filed plan shall supersede any plan pre viously approved by the Commission pursuant to this Section fo r that electric utility, subject to Commission approval. Th is subsection only applies to the extent that the Commission rules for the functional separation of delivery services and generation services provide an electric utility with the abi lity to select from 2 or more options to comply with this S ection. The electric utility may file its revised plan with the Commission up to one calendar year after the conclusion of the sale, purchase, or any other transfer of ownership descr ibed in this subsection. In all other respects, an electric uti lity must comply with the Commission rules in effect under t his Section. The Commission may promulgate rules to im plement this subsection. This subsection shall have no legal effect after January 1, 2005. (c) In establishing or considering the need for rules under subsection s (a) and (b), the Commission shall take into account the effec ts on the cost and reliability of service and the obligatio n of the utility to provide bundled service under this Act. The Commission shall adopt rules that are a cost effective means to ensur e compliance with this Section. (d) Noth ing in this Section shall be co nstrued as imposing any requirements or obligations that a re in conflict with federal law. (e) Notwithstanding anything to the contrary, an electric utility may market and promote the services, r ates and programs authorize d by Sections 16-107, 16-107.8, and 16-108.6 of this Act.(Source: P.A. 99-906, eff. 6-1-17.) (220 ILCS 5/16-126.2 new) Sec. 16-126.2. Energy Reliability Corporation of Illinois. (a) The General Assembly finds that:

(1) When Illinois restructured its electric market in 1997, Illinois' largest 2 electric utilities unexpecte dly elected to join 2 different regional transmission organizations (RTO), which effectively split the State into 2 zone s.

(2) In 2021, Illinois became the first state in the Midwest to mandate a cl ean energy future when it enacted the Climate and Equitable Jobs Act. (3) Illinois' bifurcated, existing RTO members hip structure has created significant concerns relat ed to delays in transmission build out, excessively long i nterconnection queue processes, favoring polluting ge neration resources over more cost-effective clean sou rces, inhibiting State policies, and inexplicably frustrating State efforts to address i ts resource adequacy needs through the development of new generation.

(4) The governance structures of PJM Intercon nection, LLC (PJM) and the Midcontinent Independent System Operator, I nc. (MISO) have consistently failed to represent Illinois' interes ts. (5) The Illinois Commerce Commission is a trusted, neu tral party with relevant expertise to evaluate and present its fi ndings related to the costs and benefits of Illinois establish ing a single, State-specific Independent System Operator (ISO) . (6) The General Assembly intends to understand fully the effe ctiveness over time of creating such a single, State-specific ISO, including reducing ratepayer bills, supporting e nvironmental and public health, and providing economic ben efits to Illinois while creating good-p aying jobs in equity communities, as well as for the members o f organized labor. The potential benefits of a State -specific ISO may include, but are not limi ted to, support for Illinois' resource adequacy needs, grid reliabili ty, reducing carbon and other pollutant emissions, stabil izing long-term and short-term electric rates, and supporting environmen tal justice communities, organized labor, job creation, and the ove rall economy. (b) The Co mmission shall conduct and publish the findings of a policy stud y to evaluate the effectiveness over time of establishing a sin gle State-operated ISO and to determine whether such a move would be consistent with the State's goals and would maximize benefits to State businesses an d residents. (c) The pol icy study shall evaluate the benefits and costs of participation in M ISO and PJM, including consideration of the relative net ben efits of participation in a State-specific ISO. The study shall examine the costs and benefits of such participation o ver 20 years. The study shall examine the costs and benefits to State ratepayers, including, but not limited to, consider ation of the regulatory, reliability, operational, and competitive b enefits of participating in MISO and PJM versus a State -specific ISO. The costs and benefits evaluated should i nclude resource adequacy benefits, resilience, affordabil ity, equity, the impact on the envi ronment, and the general health, safety, and welfare of the People of the State. The study shall, at a minimum, include the follo wing, and it may consider or suggest additional or alternative items: (1) the appropriate timetable to establish and effectivel y transition to a State-specific ISO, taking int o account how that schedule could support the emission reduction timeline established in Section 9.15 of the Environmental Protection Act; a nd (2) the appropriate benefits and costs to consider, such as the regulatory, reliability, operational, and competitive benefits, including, but not limit ed to:

(i) capacity market benefits and costs of separat ing from the PJM and MISO territories versus those of the status quo; (ii) transmission benefits and costs of separating from the PJM and MISO territories versus those of a State-specific ISO ; (iii) the legal, correct, and a ppropriate exit fees for leaving regional transmission organization s; (iv) managing the State's energy resources to supply elect ricity throughout the State versus the existing bifurcated structure; (v) the potential improvements in interconnection queue s peed versus the current lengthy delays in the PJM and MISO processes; (vi) the potential for a State-specific ISO to more effectively value and enable re sources, such as storage of renewable resources, deman d response, energy efficiency, and the adoption of new technolog ies and applications, versus the current PJM and MISO structures; and

(vii) an evaluation of any improved ability for the State to meet its goals and object ives in a new State-specific ISO versus the existing structure . After the completion of the study, if the Co mmission finds that the results of the study were overal l beneficial to the citizens of this State, then the C ommission may conduct and publish an additional policy stu dy that explores the steps required to establish a State-specific ISO. The Governor and members of the General Assembly may request an additional study regardless of the outcome of the original study. The additional policy study shall investigate a gover nance structure and design that would enable State polic y independence and more fully support State resource ad equacy and reliability while also complying with FERC Orde r 2000. The additional study may investigate how a State-specific ISO would be abl e to demonstrate the following issues, including, but not limited to: (i) independence from market participants; (ii) an appropriate scope and regional configurat ion; (iii) possession of operational authority for all trans mission facilities under the control of the State-specific ISO;

(iv) excl usive authority to maintain short-term reliability of the grid; (v) tariff administration and design; (vi) congestion management; (vii) management of parallel pat h flows; (viii) provision of last resort for ancillary servic es; (ix) deve lopment of an Open Access Same-time Information System (OASIS); (x) market monitori ng; and (xi) re sponsibility for planning and expanding facilities under its cont rol. The additional policy study shall also include an assess ment of the appropriate entity and organizational structure and t he staffing needs and physical needs of the indepen dent organization, not-for-profit independent co mpany, or State agency that would be tasked with overseein g the State-specific ISO, including, but not limit ed to: (i) identifying the functions necessary for a State-specific ISO; (ii) attracting and retai ning qualified staff; (iii) the engineering, design, or procure ment of the physical facilities that would be required of a State-specific ISO; and (iv) the length of time it would reasonably take to establish a State-specific ISO i n this State. (d) The C ommission shall retain the services of technical and policy experts with relevant fields of expertise. Given the critica l and rapid actions required under this Section, the Commis sion may procure the services of any facilitator, expert, or co nsultant to assist with the implementation of this Section. Such p rocurement is exempt from the requirements of the Illinois Pr ocurement Code under Section 20-10 of the Illinois Procur ement Code. The Commission may determine that the cost of any c ontract pursuant to this Section may be borne initial ly by the relevant electric public utilities, but shall be r ecovered as an expense through normal ratemaking procedures. The Illinois Power Agency, the Illinois Finance Authority, the Illinois Environmental Protection Agency, and the D epartment of Commerce and Economic Opportunity shall pr ovide support to and consult with the Commission when requested. The Commissi on may consult with other State agencies, commissions, or task forces as needed. (e) The Commission may solicit information, including confidential or pro prietary information, from entities likely to be impacted by the creation of a State-specific ISO. The Commissio n may consult with and seek assistance from (i) Independent S ystem Operators in other states, such as Texas, California, a nd New York, (ii) federal agencies, such as the Federal E nergy Regulatory Commission, and (iii) the regional transmiss ion organizations PJM and MISO. Any information designated as c onfidential or proprietary information by the entity providi ng the information shall be kept confidential by the Commis sion, its consultants, and its contractors and is not subject to disclosure under the Freedom of Information Act. The Office of the Attorney General shall have access to, and maintain the confident iality of, such information pursuant to Section 6.5 of the Attorney General Act. (f) The Commission shall publish its final policy study no later than December 1, 2027 and suitable copies shall be delivered to the G overnor and members of the General Assembly. (220 ILCS 5/16-145 new) Sec. 16-145. Powering Up Illinois. (a) For the purposes of this Section: "Electric utili ty" means an electric utility serving more than 500,000 customers i n this State. "Energ ization" and "energize" means the connection of new elect ric vehicle charging infrastructure projects over 5 megawatts to the electrical grid or upgrading electrical capaci ty to provide adequate service to such electric vehicle cha rging infrastructure projects. "Energization" and "energiz e" do not include activities related to connecting electricity sup ply resources. "Energ ization time period" means the period of time that begins wh en the electric utility receives a substantially complete ener gization project application and ends when the electric servi ce associated with the project is installed and energized, consistent with the servi ce obligations set forth in the Section 8-101 of the Publ ic Utilities Act. (b) The Commission shall adopt rules to establish and track reaso nable average and maximum target energization time periods for energizati on projects. Such rules shall, at a minimum, establish the following: (1) reasonable average and maximum target energizatio n time periods. The targets shall ensure that work is completed in a safe and reliable manner that minimizes delay in meeting the date requested by a customer for co mpletion of the energization project to the greatest extent possible. The targets may vary based on factors, including, but not limited to, customer class, size of the project, the complexity and magnitude of the work requi red, and uncertainties regarding the readiness of the cus tomer project needing energization. The targets may also recognize any factors beyond the electric utility's control;

(2 ) requirements for an electric utility to report to the Com mission, at least annually, in order to track and imp rove electric utility performance. The report shall, at a minimum, include the average, median, and standard d eviation time between receiving an application for elect rical service and energizing the electrical service, and d etailed explanations for energization time periods that exceed the target maximum for energization projects, constraints and obstacles to each type of ene rgization, including, but not limited to, funding limitations, qualified staffing availability, or equipment availability, and any other information that the Commissio n, in its discretion, concludes that such reports should contain; a nd (3) procedures for customers to report energization delays to the Commission. ( c) If an electric utility's average time period for energiz ation in a calendar year exceeds the Commission's target averages or if an electric utility has exceeded the Commission' s target maximums as established by rule, the electric ut ility shall include in its report pursuant to rules adopt ed under paragraph (2) of subsection (b) a detailed remedial p lan for meeting the targets in the future. The Commissio n may require modification to the electric uti lity's remedial plan to ensure that the electric utility m eets targets promptly. (d) Data reported by electric utilities shall be anonymized or aggregated to the extent necessary to prevent identifying indi vidual customers. The Commission shall make all such reports publ icly available. (e) In ad dition to requiring remedial plans pursuant to subsection ( c) of this Section, the Commission may require an electric utility to take any remedial actions ne cessary to achieve the Commission's targets. (220 ILCS 5/16-201 new) Sec. 16-201. Integrated resource plan development. (a) The General Assembly hereby finds that:

(1) In 2021, Illinois set itself on the path to a clean en ergy future that would produce the least amount of ca rbon and copollutant emissions while ensuring adequate, rel iable, affordable, efficient, and environmentally sustai nable electric service at the lowest total cost over time and in a manner that benefits the Illinois economy and workforce and improves the q uality of life, including environmental health, for all its citi zens. (2) In the ensuing years, Illinois has create d a strong economic environment that has led to th e revitalization and expansion of its manufacturing sector and has made Illinois an attractive place for the technology industry to locate new data and quantum computing centers. These developments hav e led to the creation of good-paying jobs for working famili es. ( 3) The unforeseen growth in the manufacturing and technology sectors wil l likely lead to a dramatic increase in electricity demand over tim e.

(4) The long interconnection times and the capacity m arket structures enacted by the 2 regional transmi ssion organizations that Illinois is split between further exacerbate the potential for an imbalance between electricity supply a nd demand. (5) The new sources of load growth from the manufacturing and technology sectors combined with ex ternal challenges require a more nimble and responsive administrative approach to effectively address future resource adequacy challenges . (6 ) The Illinois agencies that oversee and implement Illi nois energy policy must have the ability to (i) fully unde rstand current and future resource adequacy needs, (ii) p lan for what resources could be utilized to address such needs, (iii) be able to coordinate, modify, expand, and direct all of Illinois' existing energy programs and policies so as to address any resource adequacy or reli ability concerns, and (iv) direct the development of new energy programs and policies in order meet resource ad equacy and reliability needs without the need for additional le gislative action. (b) The purpose of this Section is to ensure that t he Commission, the agencies, electric utilities supplying ele ctric service in Illinois, stakeholders, market participants, and policymakers have a common set of data and information reg arding the State's electricity resource needs in order to plan for sufficient electricity resources to serve Illinois customers in a manner that is adequate, safe, reliable, affo rdable, efficient, environmentally sustainable, at the lowest cost over time, and consistent with the energy policy goals of the St ate, including, but not limited to, the clean energy policy es tablished by Public Act 102-662. To that end, this Sec tion establishes a requirement that the agencies pre pare an integrated resource plan and submit such plan to t he Commission consistent with this Section for t he Commission's review and approval after an opportunity for notic e and hearing. (c) Unless otherwise specified, as used in this Section, the following terms shall have the following me anings: (1) "Advanced transmission technologies" mea ns technologies, tools, and software that improve power flows over transmission systems and lines. "Advanced trans mission technologies" includes, but is not limited to, the following: (i) technology that dynamically adjusts the rate d capacity of transmission lines based on real-time conditions; (ii) advanced power flow controls used to actively control the flow of electrici ty across transmission lines to optimize usage or relieve congest ion; (iii) software or hardware used to identify optimal transmission grid confi gurations or enable routing power flows around congestion points; and

(iv) advanced transmission line conducto rs that have a direct current electrical resistance at least 10% lower than existing conductors of a similar diameter on the transmission system. (2) "Agencies" means the Illinois Commerce Commission Sta ff, the Illinois Power Agency, the Illinois Finance Author ity, the Illinois Environmental Protection Agency, and any consultants those agencies retain, including, but not limited to, the consultant retained by the Commission pursuant to subsection (j) of this Section and the consultant re tained by the Illinois Power Agency pursuant to paragraph (1) of s ubsection (a) of Section 1-75 of the Illinois Power Agenc y Act. (3) "Clean energy" means energy generation that either: (A) emits no on-site SO₂, NO_x, mercury, or any other regulated pollu tants; or (B) as s hown through pollution control technologies, has reduc ed a utility's CO₂ emissions by 90% compared to w hat the utility would have otherwise emitted an d that has CO₂ emissions less than 130 lb/ MWh. (4) "Regional transmission organization" or "RTO" means PJM Interconnection, LLC (PJM) and the Midcontinent Indep endent System Operator, Inc. (MISO) or the regional tran smission organization or independent system operator of which the electric utility is a member or would be a member, given the l ocation of the electric utility's customers, if it were required t o be a member. (d) The ag encies, coordinated by Commission staff, shall compile and prop ose an integrated resource plan in compliance with this Section once every 4 years. The agencies may consult with each ele ctric utility that has more than 500,000 electric retail cust omers in developing the plan and the plan shall consider any necessary interactions between RTO zones in the State. Com mission staff shall submit the initial integrated resource p lan to the Commission no later than December 31, 2026, and subsequent plans shall be submitted every 4 years thereafter , in each case by December 31 of the applicable year. For th e first integrated resource plan due on December 31, 2026, the agencies shall take into account the resource adequ acy report prepared pursuant to subsection (o) of Section 9.15 of the Environmental Protection Act and shall specifi cally address any and all divergences from the analysis and con clusions in the report. At any time after the submission of a plan, the agencies may submit an update to the plan if the agencies believe that a material change in the inputs or conclusions of the plan is warranted. The agencies shall n otify the Commission as soon as practicable of the material c hange and the potential update to the plan. The Commission shall publish the integrated resource plan on its website. (e) An a lternative retail electric supplier shall provide info rmation related to the resource needs of its customers loca ted in an electric utility's service territory as requested by the agen cies or the Commission to compile and develop the plan requir ed by this Section. (f) Commission staff shall lead the agencies in the development of the integrated resource plan to ensure that a plan submitted pu rsuant to this Section includes a detailed analysis of the follow ing: (1) an evaluation of the future electric resource need s in each electric utility's service area for periods of at least 5, 10, 15, and 20 years such that the plan coi ncides with the timelines established in Section 9.15 of T itle II of the Environmental Protection Act and is designed to support those standards t o the maximum extent practicable on the schedule established therein;

(2) peak demand and energy usage forecasts, such that the pla n:

(i) contains no fewer than 3 scenarios of (i) forecasted peak demand, (ii) net peak demand if different from peak demand, (iii) non-coincide ntal peak demand, and (iv) energy usage, to capture a reasonable range of forecasts based on historic trends and a diverse range of more conservative to high load growth based on reasonable projections. The scenarios s hould consider estimates of peak demand correspondi ng to seasons or other applicable time periods as defined by the regional transmissio n organization in which this State's electric utilities are a mem ber; (ii) reflects known changes in facility and appliance codes an d standards; (iii) reflects load reductions from State-sponsored progr ams; (iv) re flects load reductions from programs sponsored by electric utilities; (v) reflects load reductions from aggregators of retail customers that can be applied t o the host load-serving entity's resource adequacy requireme nt; (vi) reflects load reductions from any other sources i ncluding out-of-state programs that could influence load;

(vii) reflects expected adoption of other distributed ene rgy resources, including behind-the-meter generation; and

(viii) includes any additional sensitivities as determined by the agencies;

(3) an analysis of all generation and energy resource options a vailable to meet the range of load forecasts with a focus on the first period of at least 5 years covered by the pla n, including an analysis of existing supply found within each electric utility's service area and new supply expected to come online across that period of at least 5 years, such that the plan shall consider the following: (i) the current and projected status of electric resource ade quacy throughout the State from sources the agencies deem reasonab le; (ii) a range of resource options that can be deployed at a reasonable scale, that provide clean energy to the maximum extent practicable, and that include generation and energy resources on both the demand-side and supply- side; (iii) developing technol ogies that will be commercially viable during the period of analysis;

(iv) reflect reasonable assumptions for capit al and operating costs and the performance of resou rce technologies. The calculation of resource costs sha ll include reasonable expected costs for transmission interconnection and network upgrades made necessary by the addition of each resource; and (v) appropriate considerations for implementation, such as: (A) timelines for implement ation, including, but not limited to, siting, permitting, engineering, transmission interconnection, and the time it takes to modify existing programs or create new programs and put them into operat ion;

(B) recommendations for how new clean resource s should be developed to respond to resource adequacy challenges; and (C) any other requirements for implement ation; (4) confirmation that the resource adequacy and reliabi lity requirements employed in the plan meet the following conditions: (i) the plan must reflect planning rese rve margin requirements established by the correspon ding RTO, other resource adequacy requirements set by an applicable authority as autho rized by the State, or another standard chosen by the Commission; and

(ii) the integrated resource plan may refle ct a supplemental reliability analysis, including the e valuation of reliability metrics not prescribe d by an RTO or other applicable authority as authorized by the State;

(5) consistency with existing State and federal en vironmental laws and policies, including, but not limit ed to, the decarbonization goals set forth in Section 9.1 5 of the Illinois Environmental Protection Act. The pla n may consider potential changes in State and federal environmental laws and policies. The plan must provide expected emissi ons for CO₂, SO₂, NO_x, mercury, and any other r egulated pollutants in order to analyze the impact of r etirement timelines on emissions reductions. The plan must be consistent with the State's other clean ener gy goals and targets, including, but not limited to, its r enewable portfolio standard, its energy efficiency portfoli o standard, the carbon mitigation credit program, and its energy storage system por tfolio standard. The plan shall include an analysis of the follow ing: (i) the State's current progress towa rd its renewable energy resource development goals, its stor age development goals, and its energy efficiency and demand-response goals, as well as the pace of t he development of renewables, energy storage, including distributed storage, the deploymen t of virtual power plants, and demand-response utilization; and (ii) the statu s of the State's CO_2e and copollutant emissions reductions and its current stat us and progress toward developing emerging clean energy technologies; (6) consideration of the following additional issues: (i) an integrated resource plan shall be designed to colle ctively meet all of Illinois' energy policy goals and shall describe: (A) how th e plan complies with the various requirements of State energy policy;

(B) the assumptions and analytical methods used in the plan ; (C) recommendations for how Stat e policy should serve to facilitate the development of new resources; (D) the impacts of the plan on customer c osts, including net present value costs relative to alternatives; and (E) how the plan improves ene rgy equity within environmental justice and equ ity investment eligible communities, as defined by the Energy Transition Act, including, but not limited to, reducing energy burden, ensuring affordability of electric utility bills and uninterruptible essential u tility service, and reducing barriers to accessing renewable energy; (ii) an integrated resource plan shall include a discussion of the steps needed to implement the p lan, including, but not limited to, options and steps to bring on new or increased energy generated fro m any recommended resources for the 5 years after the plan would be implemented, that align with State clean energy policy; (iii) an integrated resource plan shall co nsider the information and conclusions set forth in the r enewable energy access plan developed in accordanc e with Section 8-512, including, but not limite d to, information concerning the locations of renewa ble energy access plan zones, considerations of advan ced transmission technologies to increase efficienci es, and different transmission planning options and cost allocations; (iv) an integrated resource plan may consider the impacts of future or a nticipated changes in State and federal energy laws and policies; and (v) any solutions for any additional conclusions; (7) if the agencies choose, portfolio-optimization results based on the follo wing: (i) capacity expansion and production cost modeling cons istent with the conditions and constraints set forth in this Section ; (ii) optimized candidate portfolios that ali gn with the load-growth scenarios describe d in paragraph (2) of subsection (f) of this Section and any additional portfolios chosen by the agencies to reflect alternative policy or technology assumptio ns; (iii) a comparison of total system cost on a net-present-value basis, customer rate and bill im pacts, risk metrics, including, but not limi ted to, cost variability under fuel-price and loa d shocks, emissions trajectories, and key reliability indicators; and (iv) an identification of a preferred portfolio or portfolios that best satisfy the obj ectives of affordability, reliability, equity, and emissio n reduction and a narrative explanation of why the portfolio i s recommended; and The agencies may request that PJM and MISO, or their respec tive successor organizations, conduct a resource adequacy and r eliability study. The study shall include the megawatt amoun t of energy storage capacity that would maintain resource adequacy during the stud y period to fully meet the requirements for CO_2e and copollutant emissions reductions under Public Act 102-662 that would not otherwise be met by the interconnection queue a nd without large transmission upgrades, including maintaining sufficient in-State capacity to meet the zonal requireme nts of MISO Zone 4 or the PJM ComEd Zone. The study shall a lso identify recommended geographic locations for new s torage and clean energy to mitigate local reliability r isks, including at or near the sites of any generator deactivations to maximize the effic ient utilization of existing infrastructure. (220 ILCS 5/16-202 new) Sec. 16-202. Integrated resource plan review and approval.

(a ) The Commission shall enter its order approving or approvi ng with modifications an integrated resource plan within 18 0 days after the agencies filing the plan and any companion reports or other information. The Commission may extend the period of review of the plan for no more than an additi onal 180 days. (b) The Commission may approve a plan or a modified plan and auth orize its implementation only if, after notice and hearing, including the conduct of discovery and taking of evidence, it finds that the plan:

(1) addresses any resource adequacy challenges in the 5 years immediately following approval of the plan, while also taking into account the 10 years following the plan; (2) prepares the State to best address issues of resource adequacy at the l east amount of CO_2e and copollutant emissions;

(3) considers the emissions' impacts on environmental justice communities while taking into account all applicable labor and equity standards ; (4) supports the provisioning of adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time; and (5) utilizes the expansion of renewable energy, energy storage, virt ual power plants and distributed energy storage, energy efficiency, demand response, time-of-use rates or other mechanisms designed to manage peak load, tr ansmission development, carbon mitigation credits or any other clean energy strategies to the maximum extent practicab le to resolve any identified resource adequacy shortfall or reliab ility violation in a cost-effective, affordable, timely, and clean manner. (c) T he Commission may, as a part of its decision to approve a plan or modified plan and to the extent consistent with the uniform al location of costs required under subsection (k) of Section 16-108, order changes to existing programs, direct specific a ctions within existing programs including the authorization to support the expansion of an existing program, including, but not limited to: (1) any of the following plans or programs designed to increase the amount of generation and capacity available:

(i) the Long-Term Renewable Resources Procure ment Plan, including programs and procurements authorized through that Plan, and to increase the lim itations placed on the procurement of renewable energy resour ces established pursuant to subparagraph (E) of paragraph (1) of subsection (c) of Section 1- 75 of the Illinois Power Agency Act in order to increase, direct, or adjust procurements of renewable energy resources to support new renewable energy project s; (ii) the Energy Storage Resources Procuremen t Plan, including programs and procurements author ized through that Plan, and to increase the procurement of energ y storage established pursuant to subsection (d-20) of Section 1-75 of the Illinois Power Agency Ac t in order to increase or adjust procurements for new energy storage ; (iii) the carbon mitigation credit procurement plans est ablished pursuant to subsection (d-10) of Section 1 -75 of the Illinois Power Agency Act in order to preserve existing carbon-free energy r esources, including extending or expanding carbon mitigation credit contract awards in accordance with a new schedule of baselin e costs;

(iv) the Illinois Power Agency's annual elec tricity procurement plans established pursuant to para graph (2) of subsection (d) of Section 16-111.5, including modification of the products to be procured a nd allowing for costs associated with the purchase of ne w or additional products to be socialized across all re tail customers or all load-serving entities, as applicable; and

(v) any additional programs designed to proc ure appropriate sources of new clean energy and capa city resources, including any associated clean attribute credits; and (2) any of the follo wing designed to manage energy demand, including, but not limited to:

(i) extending or expanding the energy eff iciency programs implemented by electric utilities and the limitation on the amount of energy efficiency and demand-response measures implemented pursuant to Section 8-103B in order to gain increased load reductions; and

(ii) the Multi-Year Integrated Grid Plans implemented by electric utilities pursuant to Section 16-105.17 in order to extend or expand programs related to peak load management and re duction, including, but not limited to, virtual power plants, front of th e meter distributed storage, demand response, and time-of-use rates. (d) If all of the changes made to the programs pursuant to this Se ction would reasonably be insufficient to balance supply and demand and avoid a reso urce adequacy shortfall, then the Commission may delay, in whole or in part, the CO_2e and copollu tant emissions reductions requirements found in Section 9 .15 of the Environmental Protection Act but only to the minimum extent and duration necessary to address the res ource adequacy shortfall needs of the State. If the Commissi on finds that reducing or delaying the emissions reductions re quirements is necessary, despite any or all of the changes made pursuant to this Section, then it shall also include in i ts final order recommendations to the General Assembly on what additional policies m ay be adopted that could avoid future modifications to the em issions reductions. (e) The agencies, electric utilities, and any other impacted en tities shall comply with any of the Commission's orders, and w hen required seek approval from the Commission and make any req uired modifications to their plans, programs, or related initia tives in a manner consistent with the process and timing for those changes as outlined in the approved plans or, if no ne is specified, as soon as practicable. If the integrated re source plan approved by the Commission contains recommendatio ns that are outside the Commission's authority, the Commission shal l communicate any such recommendations to the Governor and the Ge neral Assembly. (f) Give n the critical and rapid actions required under this Section, the Commission may procure the services of any facilitator, e xpert, or consultant, including the procurement monitor retained by the Commission pursuant to paragraph (2) of subsection (c) o f Section 16-111.5. Such procurement is exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-1 0 of that Code. (g) Co sts that are prudently and reasonably incurred by electric utilities to comply with the requirements of this Section shal l be recovered and shall be excluded from the calculation performed u nder paragraph (6) of subsection (f) of Section 16-108.18 . Nothing in the Commission's order directing changes t o a prior approved plan as enumerated in this Section sha ll be the sole basis for a finding of imprudence or unre asonableness or the lack of use or usefulness of any investme nt or expenditure. (h) The Commission may adopt rules to implement the requirements of this Section. (220 ILCS 5/17-900) Sec. 17-900. Customer self-generation o f electricity. (a) T he General Assembly finds and declares that municipal systems and electric cooperatives shall continue to be governed by their respective governing bodies, but that such governi ng bodies should recognize and implement policies to provide the oppo rtunity for their residential and small commercial customers who wish to self-generate electricity and for reasonable credits t o customers for excess electricity, balanced against the rig hts of the other non-self-generating customers. This includes creating consistent, fair policies that are accessible to all customers and transparent, fair processes for raising and addressing any concerns. (b) Customers have the right to install renewable generating facil ities to be located on the customer's premises or customer's si de of the billing meter and that are intended primarily to offset the customer's own electrical requirements and produce, consume, and store their own renewable energy witho ut discriminatory repercussions from an electric cooperative or municipal system. This includes a customer's rights to: ( 1) generate, consume, and deliver excess renewable energy to the dis tribution grid and reduce his or her use of electricity obtained fr om the grid; (2) u se technology to store energy at his or her r esidence; (3) interconnect his or her electrical system t hat generates renewable energy, stores energy, or an y combination thereof, with the electricity meter on the custo mer's premises that is provided by an electric cooperative or mun icipal system: (A) in a timely manner; (B) in accordance with requirements established by the electri c cooperative or municipal utility to ensure the safety of util ity workers; and (C) after providing written notice to t he electric cooperative or municipal utility system p roviding service in the service territory, install ing a nomenclature plate on the electrical me ter panel and meeting all applicable State and local safety and e lectrical code requirements associated with in stalling a parallel distributed generation system; and (4) receive fair cred it for excess energy delivered to the distribution grid; a nd (5) for residential and small commercial customers, inte rconnect renewable energy systems sized up to and i ncluding 25 kW AC. (c) The po licies of municipal systems and electric cooperatives regarding self-generation and credits for excess electricity may reasonably differ from those required of other entities by Article XVI of the Public Utilities Act or other Acts. The credits must recognize th e value of self-generation to the distribution grid and benefi ts to other customers. (c-5) The po licies of municipal systems and electric cooperatives regardin g self-generation and credits for excess electricity shal l not require customers to name the municipal system or elec tric cooperative as an additional insured on the customer' s insurance policies or have any minimum liability limit requi rement in connection with the installation and operation of re newable generating facilities if the renewable generating fac ilities meet the safety standards listed in the applicable inte rconnection agreement and the contractor used to install the renewable generating facilities is licensed and possesses commercial general liability insurance coverage of at least $1,000,000 per occurrence and $2,000,000 in the aggregate per year. (d) With in 180 days after this amendatory Act of the 102nd General As sembly, each electric cooperative and municipal system shall upd ate its policies for the interconnection and fair crediting o f customer self-generation and storage if necessary, to comply with the standards of subsection (b) of this Section. Each el ectric cooperative and municipal syste m shall post its updated policies to a public-facin g area of its website. (e) An e lectric cooperative or municipal system customer who produ ces, consumes, and stores his or her own renewable energy shal l not face discriminatory rate design, fees or char ges, treatment, or excessive compliance requirements that would unreasonably affect that custo mer's right to self-generate electricity as provid ed for in this Section. (f) An el ectric cooperative or municipal utility system customer shall ha ve a right to appeal any decision related to self-generation and storage that violates these rights to self-gene ration and non-discrimination pursuant to the provisions of this Section through a complaint under the Administrative Review Law or similar legal process.(S ource: P.A. 102-662, eff. 9-15-21.) (220 ILCS 5/20-140 new) Sec. 20-140. Interconnection Working Group.

(a) The Commission shall establish an Interconnection Working Grou p. The Working Group shall include representatives from el ectric utilities, developers of renewable electric generating facilities, representatives of new large loads seeking gr id interconnection, other industries that regularly app ly for interconnection with the electric utilities as appropria te, representatives of distributed generation custom ers, the Commission staff, and other stakeholders with a su bstantial interest in the topics addressed by the Interconnectio n Working Group. (b) The Interconnection Working Group shall address at least th e following issues in relation to new generation and new large loads:

(1) the cost of and the best available technology for interconnection and meter ing, including the standardization and publication of stan dard costs; (2) transparency, accuracy, and use of the distribution interconnection queue and hosting capacity maps; (3 ) distribution system upgrade cost avoidance through use of advanced inverter functions, energy storage, and load management; (4) predict ability of the queue management process and enforcement of timeli nes; (5) be nefits and challenges associated with group studies and cost sh aring; (6) minimum requirements for application to the interconnection process and thr oughout the interconnection process to avoid queue clogg ing behavior; (7) the process and customer service for interconnecting custo mers adopting distributed energy resources, including energy storage; (8) options for metering distributed energy resources, including energy stora ge; (9) interconnecti on of new technologies, including smart inverters and energy storage ; (1 0) collection, examination, and sharing of data on Level 1 interconnection costs, including cost and type of upgr ades required for interconnection, and the use of this d ata to inform the final standardized cost of Level 1 interconnection ; (11) determination of a single standardize d cost for Level 1 interconnections, which shall not exceed $200; an d ( 12) such other technical, policy, and tariff issues re lated to and affecting interconnection perf ormance and customer service as determined by the Interconne ction Working Group. (c) The Commission may create subcommittees of the Intercon nection Working Group to focus on specific issues of importance, as appropriate. (d) The Interconnection Working Group shall report to the Commission on recommended improvements to interconnection r ules, tariffs, and policies as determined by the Interconnectio n Working Group at least every year. A report shall include c onsensus recommendations of the Interconnection Working Group and, if applicable, additional recommendations for which consensus was not reached. Non-consensus shall not be a basis for excluding recommendations that are majority or minority reco mmendations. The Commission shall use the report from the Inte rconnection Working Group to determine whether processes shou ld be commenced to formally codify or implement the r ecommendations. The Interconnection Working Group shall p rovide the reports under this subsection (d) to the Commission on at least the following topics in the order listed below w ithin a reasonable time after the effective date of this amend atory Act of the 104th General Assembly: (A) a mech anism for good cause extensions to construction timeline s as long as the interconnection customer reasonably demonstra tes progress; (B) a mechanism for all electric utilities to accept cash, letters of credit, or bonds for any deposits required under the interconnection agreement; ( C) cost sharing for distribution system upgrades and interc onnection facilities for multiple interconnection customers at tempting to interconnect on the same feeder or substation; and (D) requirements that interconnection studies process wit hout delay based on queue position or status of applications ahead in the queue, and associated requirements for disclosure of conting ent upgrades. (d-5) Within 12 months after the report directed by subsect ion (d) has been submitted, the Working Group shall repo rt to the Commission on the following: (A) mandatory d isclosures on the hosting capacity map and studies for continge nt upgrades including timelines for notice of responsibility and payment; and (B) a frame work for concurrent study on multiple feeders for a distributed ener gy resource. (d-10) With in 12 months after the report directed by subsection (d-5 ) has been submitted, the Working Group shall report to th e Commission on the following: (A) dynamic hosting capacit y maps; (B) standards for public queue and hosting cap acity map information regarding individual projects in queue, inc luding (i) distributed generation nameplate capacity, (ii) p aired or stand-alone energy storage system nameplate c apacity, (iii) detailed estimated upgrade costs, and (iv) systems that have completed upgrades and withdrawn projects; a nd (C) timelines for refund of deposits if the interconnec tion agreement is terminated. Within the same time period, utilities shall publish all final interconnection agreements, facilities studies, and system imp act studies. (d-15) Withi n 12 months after the report directed by subsection (d-10 ) has been submitted, the Working Group shall report to the C ommission on the following: (A) level of detail of costs in system impact and facilities studies and level 2 studies; and (B) a cap on charges to the interconnection customer b ased on a percentage of the non-bindi ng cost estimate in the facilities study, system impact study, or level 2 study. (e ) In collaboration with the General Counsel of the Commission, the Office of Retail Market Development shall develop polici es and procedures to facilitate employees of the Office i n leading the Interconnection Working Group without inte rference with docketed proceedings. The policies and procedu res developed under this subsection (e) shall be designed to allow the Interconnection Working Group to work without interruption. (220 ILCS 5/20-145 new) Sec. 20-145. Interconnection Monitor. (a) The Of fice of Retail Market Development may employ, designate, or otherwise retain the services of an Ombudsperson who, in addition to the roles described in this Act, is responsible fo r overseeing electric utility compliance with the standards established by this S ection and other regulatory or statutory obligations regarding in terconnections. (b ) The Ombudsperson may from time to time request, and each electric utility shall timely pr ovide records and information to carry out his or her duties u nder this Section. (c ) The Office shall monitor interconnection between elec tric utilities and applicants for interconnection and inter connection customers. The Office may request, and elect ric utilities shall promptly provide, informat ion and records related to pending, successful, and terminated inter connections. (d) The Office ma y require electric utilities to provide a detailed breakdow n of the non-binding costs of operation and an estima te that transparently itemizes operational costs, including equ ipment by type or model, labor, operation and maintenance, engineering and design, permitting, easements and rights-of-way, direct overhead, and indi rect overhead. (e) The Office may establish an informal interconnection dispute re solution process that may supersede 83 Ill. Adm. Code 466.1 30, 83 Ill. Adm. Code 467.80, and interconnection agreemen ts to the extent described in this subsection (e). Follo wing the informal process described in this Section, including any extensions agreed upon by the parties, an e lectric utility, an interconnection customer, or an inter connection applicant may submit the interconnection di spute to the Ombudsperson, or his or her designee. The Ombud sperson, or his or her designee, shall provide a recommende d resolution of such dispute within 30 days after the O mbudsperson determines that full information from all parti es to the dispute has been received. The electric utility, th e interconnection customer, the interconnection applicant, or a ny other party authorized to initiate dispute resolution und er the Commission's rules authorized by this Act may include the Ombudsperson's recommendation in any formal complaint befo re the Commission. (f) Th e Office is encouraged to include at least one employee , at the Bureau Chief's discretion, with a background in engineering of renewable resources and distribution interconnections. Section 90-40. The Electric Transmission Systems Construction Standards Act is amended by changing Sec tions 5 and 15 as follows: (220 ILCS 32/5) Sec. 5. Definitions. For the pur poses of this Act: "Commission" means the Illinois Comm erce Commission. "Construction contractor" means any nonutility entity responsible for the construction, installation, maintenance, or repair of electric tra nsmission systems subject to this Act. "Electric transmission systems" means an electrical t ransmission system designed and constructed with the capabilit y of being safely and reliably energized at 69 kilovolt s or more, including transmission lines, transmission t owers, conductors, insulators, foundations, grounding syst ems, access roads, and all associated transmission facilities, including transmission substations. "Electric transmission syst ems" does not include projects located on the electric generating faci lity's side of the facility's point of interconnection or facili ties not functionally classified as transmis sion systems, regardless of voltag e. "OSHA" means Occupational Safety and Health Administration. "Utility" means an entity that is a public utility, as defined in Section 3-105 of the Publ ic Utilities Act, and that serves residential customers. has t he meaning given to that term in Section 3-105 of the Public Utilities Act.(So urce: P.A. 103-1066, eff. 2-20-25.) (220 ILCS 32/15) Sec. 15. Requirements for construction contractors. (a) Prevailing wage compl iance. All utilities and construction contractors responsible for the construction, installati on, maintenance, or repair of electric transmission system s shall pay employees performing the construction, installation, maintenance, or repair work of such systems wages and benefits consiste nt with the Prevailing Wage Act.

(b) Training and competence requirement. To ensure safety and reliability i n the construction, installation, maintenance, and repair of electric trans mission systems, each electric utility and construction contractor must demonstrate the compet ence of their employees who are performing the work of constru ction, installation, maintenance, or repair of electric transm ission systems, which shall be consistent with the standards required by Illinois utilities as of January 1, 2007, or great er. Competence must include, at a minimum: (1) completion, or active participation with ultimate completion, in an accredited or recognized apprenticeship program for the relevant craft, trade, or skill; or (2) a minimum of 2 years of direct em ployment in the specific work function. The Commission shall oversee compliance t o ensure employees meet these standards. (c) Safety training. All employees engaged in the construction, installat ion, maintenance, or repair of electric transmission syst ems must successfully complete O SHA-certified safety training required for their specific roles on the project site.

(d) Diversity Plan. (1) All construction contractors engaged in the c onstruction, installation, maintenance, or repair o f electric transmission systems shall develop a Diversity Plan that sets forth:

(A) the goals for apprenticeship hours to be performed by min orities and women; (B) the goal s for total hours to be performed by underrepresented minorities and w omen; and (C) spen ding for women-owned, minority-owned, vet eran-owned, and small business enterprises in the prev ious calendar year. ( 2) These goals shall be expressed as a percentage of the total work performed by the construction contractor submitting the plan and the actual spending for all women-o wned, minority-owned, veteran-owned, and small business enterprises shall also be expressed as a percentage of the tot al work performed by the construction contractor submitting t he Diversity Plan. ( 3) For purposes of the Diversity Plan, minorities and w omen shall have the same definition as defined in th e Business Enterprise for Minorities, Women, and Person s with Disabilities Act.

(4) The construction contractor shall submit the Diversity Plan to the Commission.(Source: P.A. 103-1066, eff. 2-20-25.) Section 90-45. The Environmental Protection Act is amended by changing Sectio ns 9.15 and 39 as follows: (415 ILCS 5/9.15) Sec. 9.15. Greenhouse gases. (a) An air pollution construction permit shall not be requ ired due to emissions of greenhouse gases if the equipment , site, or source is not subject to regulation, as defined by 4 0 CFR 52.21, as now or hereafter amended, for greenhouse ga ses or is otherwise not addressed in this Section or by the Board in regulations for greenhouse gases. These exemptions do not relieve an o wner or operator from the obligation to comply with other applicable rules or regulations. (b) An air pollution operating permit shall not be requ ired due to emissions of greenhouse gases if the equipment, site , or source is not subject to regulation, as defined by Sec tion 39.5 of this Act, for greenhouse gases or is otherwis e not addressed in this Section or by the Board in regulati ons for greenhouse gases. These exemptions do not relieve an o wner or operator from the obliga tion to comply with other appli cable rules or regulations. (c) (Blank). ( d) (Blank). (e) (Blank). (f) As used in this Section: "Carbon dioxide emission" means the plant annual CO₂ total output emission as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrated Database (eGrid), or its su ccessor. "Carbon dioxide equivalent emiss ions" or "CO₂e" means the sum total of the mass amount of emissions in tons per year, calculated by multiplying the mass amount of each of the 6 greenhouse gases specified in Section 3.207, in tons per year, by its associated glob al warming potential as set forth in 40 CFR 98, subpart A, table A-1 or its successor, an d then adding them all together. "Cogenerat ion" or "combined heat and power" refers to any system th at, either simultaneously or sequentially, produces electricity and useful thermal energy from a single fuel source. "Co pollutants" refers to the 6 criteria pollutants that have been iden tified by the United States Environmental Protectio n Agency pursuant to the Clean Air Act. "Electric generating unit" or "EGU" means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle s ystem that serves a gene rator that has a nameplate capacity greater than 25 MWe an d produces electricity for sale. "Environme ntal justice community" means the definition of that term b ased on existing methodologies and findings, used and as may be updated by the Illinois Power Agency and its program administrator in the Illinois Solar for All Program. "Equit y investment eligible community" or "eligible community" me ans the geographic areas throughout Illinois that would m ost benefit from equitable investments by the State designed to combat discrimination and foster sustainab le economic growth. Specifically, eligible community me ans the following areas:

(1) areas where residents have been historicall y excluded from economic opportunities, including opportunities in the energy sector, as defined as R3 ar eas pursuant to Section 10-40 of the Cannabis Reg ulation and Tax Act; and (2) areas where residents have been historically subject to disproportionate burdens of pollution, inclu ding pollution from the energy sector, as established by environmental justice communities as defined by the Illinois Power Ag ency pursuant to the Illinois Power Agency Act, excluding any racial or ethnic indicators. "Equ ity investment eligible person" or "eligible person" means the persons who would most benefit from equitable investments b y the State designed to combat discrimination and foster sustain able economic growth. Specifically, eligible person means the following people: (1) persons whose primary residence is in an equity i nvestment eligible community;

(2) persons whose primary residence is in a municip ality, or a county with a population under 100,000, whe re the closure of an electric generating unit or mine has b een publicly announced or the electric generati ng unit or mine is in the process of closing or closed within the last 5 years; (3) p ersons who are graduates of or currently enrolled in the foster care system; or (4) persons who were formerly incarcerated. "Existing emissions" means: (1) for CO₂e, the total average tons-per-year of CO₂e emitted by t he EGU or large GHG-emitting unit either in the years 2018 through 2020 or, if the unit was not yet in operat ion by January 1, 2018, in the first 3 full years of that unit's operation; and (2 ) for any copollutant, the total average tons-per-y ear of that copollutant emitted by the EGU or large GHG-emitting unit either in the years 2018 through 2020 or, if the unit was not yet in operation by January 1, 2018, in the first 3 full years of that unit's operation. "Green h ydrogen" means a power plant technology in which an EGU creates electric power exclusively from electro lytic hydrogen, in a manner that produces zero carbon and copollutant emissions, using hyd rogen fuel that is electrolyzed using a 100% renewabl e zero carbon emission energy source. "Large greenh ouse gas-emitting unit" or "large GHG-emitting un it" means a unit that is an electric generating unit or other fossil fuel-fired unit that itself has a nameplate cap acity or serves a generator that has a nameplate capacity greater tha n 25 MWe and that produces electricity, including, but not limited to, coal-fi red, coal-derived, oil-fired, natural gas-fired, and cogeneration units. "NO_x emission rate" means the plant annual NO_x total output emission rate as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrate d Database (eGrid), or its successor, in the most recent year for which data is available. "Public greenhouse ga s-emitting units" or "public GHG-emitting unit" mea ns large greenhouse gas-emitting units, including EGUs, that are wholly owned, directly or indirectly, by one or mor e municipalities, municipal corporations, joint municipal el ectric power agencies, electric cooperatives, or other governmental or nonp rofit entities, whether organized and created under the laws of Illinois or another state. "SO₂ emission rate" mea ns the "plant annual SO₂ total output emiss ion rate" as measured by the United States Environmental Protec tion Agency in its Emissions & Generation Resource Integrate d Database (eGrid), or its successor, in the most recent year fo r which data is available. (g) All EGUs and large gr eenhouse gas-emitting units that use coal or oil as a fuel and are not public GH G-emitting units shall permanently reduce all CO ₂e and copollutant emissions to zero no l ater than January 1, 2030. (h) All EGUs and lar ge greenhouse gas-emitting units that use coal as a fuel and are public G HG-emitting units shall permanently reduce CO₂e emissions to zero no later than December 31, 2045. Any sourc e or plant with such units must also reduce their CO₂e emissions by 45% from existing emissions by no later than January 1, 2035. If the emissions reduction re quirement is not achieved by December 31, 2035, the plant shall retire one or more un its or otherwise reduce its CO₂e emissions by 45% from existing e missions by June 30, 2038. (i) All EGUs and large greenhouse gas-emitting units that use gas as a fuel and are not public GHG-emitting units shall permanently reduce all CO ₂e and copollutant emissions to zero, includin g through unit retirement or the use of 100% green hydroge n or other similar technology that is co mmercially proven to achieve zero carbon emissions, accordin g to the following: (1) No later than January 1, 2 030: all EGUs and large greenhouse gas-emitting units that have a NO_x emissions rate of greater than 0.12 lbs/MW h or a SO₂ emission rate of greater than 0.006 lb/MWh, and are located in or within 3 m iles of an environmental justice communi ty designated as of January 1, 2021 or an equity investment eligible community. (2) No later than January 1, 2040: all EGUs and large greenhouse gas-emitting units that have a NO_x emission rate of greater than 0.1 2 lbs/MWh or a SO₂ emission ra te greater than 0.006 lb/MWh, and are not located in or w ithin 3 miles of an environmental justice community desig nated as of January 1, 2021 or an equity investment eligible c ommunity. After January 1, 2035, each such EGU and large greenhouse gas-emit ting unit shall reduce its CO₂e emissions by at least 50% fr om its existing emissions for CO₂e, a nd shall be limited in operation to, on average, 6 hours or less per day, measured over a calendar year, and shall not run for more than 24 consecutive hours except in emergency conditions, as des ignated by a Regional Transmission Organization or Independe nt System Operator. (3) No l ater than January 1, 2035: all EGUs and large greenhouse g as-emitting units that began operation prior to the effective date of this a mendatory Act of the 102nd General Assembly and have a NO_x emission rate of less than or equal to 0.12 lb/MWh and a SO₂ emission rate less than or equ al to 0.006 lb/MWh, and are located in or within 3 m iles of an environmental justice community designated as of Janua ry 1, 2021 or an equity investment eligible community. Each such EGU and large gr eenhouse gas-emitting unit shall reduce its CO₂e em issions by at least 50% from its ex isting emissions for CO₂e no later th an January 1, 2030. (4) No l ater than January 1, 2040: All remaining EGUs and large gr eenhouse gas-emitting units that have a heat rate greate r than or equal to 7000 BTU/kWh. Each such EGU and Large greenhouse gas-emit ting unit shall reduce its CO₂e emissions by at least 50% from its ex isting emissions for CO₂e no later th an January 1, 2035. (5) No late r than January 1, 2045: all remaining EGUs and large greenhouse gas-emitting units. (j) All EGUs and la rge greenhouse gas-emitting units that use gas as a fuel and are public GHG-emitting units shall permanently reduce all CO ₂e and copollutant emissions to zero, includin g through unit retirement or the use of 100% green hydrogen or other similar t echnology that is commercially proven to achieve zero carbon emi ssions by January 1, 2045. (k) All EGUs a nd large greenhouse gas-emitting units that utilize combined heat and power or c ogeneration technology shall permanently reduce all CO₂e and copollutant emissions to z ero, including through unit retirement or the use of 100 % green hydrogen or other similar t echnology that is commercially proven to achieve zero carbon emissio ns by January 1, 2045. (k-5) No EGU or larg e greenhouse gas-emitting unit that uses gas as a fuel and is not a public GHG-em itting unit may emit, in any 12-month period, CO₂e or copollutants in excess of that unit's existing emiss ions for those pollutants. (l) Notwithstanding subsections (g) through (k-5), large GHG-emitting units including EGUs may temporarily continue emitting CO₂e and copollutants after any applicable deadline specified in any of subsections (g) through (k-5) if it has been determined, as described in paragraphs (1) and (2) of this subsection, that ongoing operation of the EGU is necessary to mai ntain power grid supply and reliability or ongoing o peration of large GHG-emitting unit that is not an EGU i s necessary to serve as an emergency backup to operations. U p to and including the occurrence of an emission reduction deadline under subsection (i), al l EGUs and large GHG-emitting units must comply with the following terms:

(1) if an EGU or large GHG-emitting unit that is a participant in a regional transmission organization intends to retire, it must submit documentation to the app ropriate regional transmission organization by the approp riate deadline that meets all applicable regulatory requirements necessary to ob tain approval to permanently cease operating the large GHG-emitting unit; ( 2) if any EGU or large GHG-emitting unit that is a participant in a regional transmission organiz ation receives notice that the regional transmission o rganization has determined that continued operation of t he unit is required, the unit may continue operating un til the issue identified by the regional transmissi on organization is resolved. The owner or operator of th e unit must cooperate with the regional transmission organ ization in resolving the issue and must reduce its emis sions to zero, consistent with the requirements un der subsection (g), (h), (i), (j), (k), or (k-5), as applicable, as soon as practicable when the issue identified by the regional transmission organiza tion is resolved; and ( 3) any large GHG-emitting unit that is not a participant in a regional transmission organization shall be allowed to continue emitting CO₂e and copollutants after the zer o-emission date specified in subsection (g), (h), (i), (j), (k), or (k-5), as applicable, in the capacity of an emergency backup unit if approved by the Illinois Commerce Commission. (m) No v ariance, adjusted standard, or other regulatory relief o therwise available in this Act may be granted to the emissions reduction and eliminati on obligations in this Section. (n) By J une 30 of each year, beginning in 2025, the Agency shall p repare and publish on its website a report setting forth the ac tual greenhouse gas emissions from individual units and the aggregate statewide emissions from all units for the prior year.

(o) The Every 5 ye ars beginning in 2025, the Environmental P rotection Agency, Illinois Power Agency, and Illinois Commerc e Commission shall jointly prepare, and release publicly, a re port to the General Assembly that examines the State's current progress towar d its renewable energy resource development goals, the status of CO₂e and copollutant emissions red uctions, the current status and progress toward developing and implementing green hydrogen technologies, the current and pr ojected status of electric resource adequacy and reliabili ty throughout the State for the period beginning 5 years ahe ad, and proposed solutions for any findings. Th e Environmental Protection Agency, Illinois Power Agency, and Illinois Commerce Commission shall consult PJM Intercon nection, LLC and Midcontinent Independent System Operator, Inc ., or their respective successor organizations regarding fore casted resource adequacy and reliability needs, anticipated new gene ration interconnection, new transmission development or upgrade s, and any announced large GHG-emitting unit clos ure dates and include this information in the report. The report shall b e released publicly by no later than December 15, 2025 or the effective dat e of this amendatory Act of the 104th General Assembly, whichever is later of the year it is prepared. If the Environmental Protection Agency, Illinois P ower Agency, and Illinois Commerce Commission jointly conclude in the report that the data from the regional grid operat ors, the pace of renewable energy development, the pace of development of en ergy storage and demand response utilization, transmission capa city, and the CO₂e and copollutant em issions reductions required by subsection (i) or (k-5) reasonably demonstrate that a resource adequacy shortfall will occur, including whether there will be sufficient in-sta te capacity to meet the zonal requirements of MISO Zone 4 or the PJM ComEd Zone, per the requirements of the regional tr ansmission organizations, or that the regional transmission ope rators determine that a reliability violation will occur during the time frame the study is evaluating, then the I llinois Power Agency, in conjunction with the Environmental Protection Age ncy shall develop a plan to reduce or delay CO₂e and copollutant emissions reductions requirements only to the extent and for the duration necessary to meet the resource adequacy and reliability needs of the State, i ncluding allowing any plants whose emission reduction deadline has been identified in the plan as creating a reliab ility concern to continue operating, including operating with r educed emissions or as emergency backup where appropri ate. The plan shall also consider the use of renewable ener gy, energy storage, demand response, transmission development, or other strategies to resolve the identified resource adequacy shortfal l or reliability violation. (1) In developing the plan, the Environmental Protection Agency and the Illinois Power Agency shall hold at lea st one workshop open to, and accessible at a time and place convenient to, the public and shall conside r any comments made by stakeholders or the public. Upon development of the plan, copies of the plan shall be poste d and made publicly available on the Environmental Prote ction Agency's, the Illinois Power Agency's, and the Illi nois Commerce Commission's websites. All interested partie s shall have 60 days following the date of posting to pr ovide comment to the Environmental Protection Agency and the Illinois Power Agency on the plan. All comments submit ted to the Environmental Protection Agency and the Ill inois Power Agency shall be encouraged to be specific, sup ported by data or other detailed analyses, and, if objec ting to all or a portion of the plan, accompanied by speci fic alternative wording or proposals. All comments shal l be posted on the Environmental Protection Agency's, the I llinois Power Agency's, and the Illinois Commerce Commission' s websites. Within 30 days following the end of the 60-day review period, the Environmental Protection Agency and the Illinois Power Agency shall revise the plan as necessary based on the comments receive d and file its revised plan with the Illinois Commerce Co mmission for approval. (2) Within 60 days after the filing of the revised plan at the Illinois Commerce Commission, any person o bjecting to the plan shall file an objection with the Il linois Commerce Commission. Within 30 days after the expir ation of the comment period, the Illinois Commerce Commiss ion shall determine whether an evidentiary hearing is ne cessary. The Illinois Commerce Commission shall also host 3 public hearings within 90 days after the plan is filed. Following the evidentiary and public hearings, the Illinois Commerce Commission shall enter its order approving o r approving with modifications the reliability mitigat ion plan within 180 days. (3) The Illinois Commerce Commission shall only a pprove the plan if the Illinois Commerce Commission d etermines that it will resolve the resource adequacy or reliability deficiency iden tified in the reliability mitigation plan at the least amou nt of CO₂e and copollutant emiss ions, taking into consideration the emissions impacts on environmental justice communities, and that it will ensu re adequate, reliable, affordable, efficient, and enviro nmentally sustainable electric service at the lowest total cost over time, taking into account the impact of incre ases in emissions. (4) If the resource adequacy or reliability deficiency ident ified in the reliability mitigation plan is resolved or r educed, the Environmental Protection Agency and the Illinois Power Agency may f ile an amended plan adjusting the reduction or delay in CO₂e and copollutant emission reduction requirements identified in the plan. (Source: P.A. 102-662, eff. 9-15 -21; 102-1031, eff. 5-27-22.) (415

ILCS 5/39) (from Ch. 111 1/2, par. 1039) Sec. 39. Issuance of permits ; procedures. (a) When t he Board has by regulation required a permit for the co nstruction, installation, or operation of any type of facil ity, equipment, vehicle, vessel, or aircraft, the applicant shall apply to the Agency for such permit and it shall be the duty of the Agency to issue such a permit upon proof by the ap plicant that the facility, equipment, vehicle, vessel, or aircraft will not cause a violation of this Act or of regul ations hereunder. The Agency shall adopt such procedures as a re necessary to carry out its duties under this Section. In mak ing its determinations on permit applications under this Secti on the Agency may consider prior adjudications of noncomplian ce with this Act by the applicant that involved a rel ease of a contaminant into the environment. In granting permits, the Agency may impose reasonable conditions speci fically related to the applicant's past compliance histo ry with this Act as necessary to correct, detect, or prevent noncompliance. The Agency may impose such other conditions as may be necessary to accomplish the purposes of this A ct, and as are not inconsistent with the regulations promulg ated by the Board hereunder. Except as otherwise provided in this Act, a bond or other security shall not be required as a condition for the issuance of a permit. If the Agency denies a ny permit under this Section, the Agency shall transmit to t he applicant within the time limitations of this Section speci fic, detailed statements as to the reasons the permit application w as denied. Such statements shall include, but not be limited to, the following: (i) the Sections of this Act which may be violated if th e permit were granted; (ii) the provision of the regulations , promulgated under this Act, which may be violated if the p ermit were granted; (iii ) the specific type of informatio n, if any, which the Agency deems the applicant did not pro vide the Agency; and (iv) a statement of spe cific reasons why the Act and the regulations might not b e met if the permit were granted. If there i s no final action by the Agency within 90 days after the filing of the application for permit, the applicant may deem the p ermit issued; except that this time period shall be ext ended to 180 days when (1) notice and opportunity for publi c hearing are required by State or federal law or regulation, (2) the application which was filed is for any permit to develo p a landfill subject to issuance pursuant to this subsection , or (3) the application that was filed is for a MSWLF unit required to iss ue public notice under subsection (p) of Section 39. The 90-day and 180-day time periods for the Agency to take final action do not apply to NPDES permit application s under subsection (b) of this Section, to RCRA permit applica tions under subsection (d) of this Section, to UIC permit ap plications under subsection (e) of this Section, or to CCR surface impoundment applications under subsection (y) of this Section. The Ag ency shall publish notice of all final permit determinations for development permits for MSWLF units and for signifi cant permit modifications for lateral expansions for existing MSWLF units one time in a newspap er of general circulation in the county in which the uni t is or is proposed to be located. After Janu ary 1, 1994 and until July 1, 1998, operating permits issued u nder this Section by the Agency for sources of air pollutio n permitted to emit less than 25 tons per year of any combinati on of regulated air pollutants, as defined in Section 39.5 of this Act, shall be required to be renewed only upon written re quest by the Agency consistent with applicable provisions of th is Act and regulations promulgated hereunder. Such operating pe rmits shall expire 180 days after the date of such a r equest. The Board shall revise its regulations for the existing State air pollution operating permit program consistent with t his provision by January 1, 1994. After June 3 0, 1998, operating permits issued under this Section by the Agency for sources of air pollution that are not subject to S ection 39.5 of this Act and are not required to have a federall y enforceable State operating permit shall be required to be renewed only upon written request by the Agency consistent with applicable provisions of this Act and its rules. Such op erating permits shall expire 180 days after the date o f such a request. Before July 1, 1998, the Board shall revis e its rules for the existing State air pollution operating perm it program consistent with this paragraph and shall adopt rules that require a source to demonstrate that it qualifies for a permit under this paragraph. Each air pollution construction permit for fossil fuel-fired power ba ckup generators to a source that is a data center, as defined i n subsection (c) of Section 605-1025 of the Department of Commerce and Economic Opportunity Law of the Civil Administ rative Code of Illinois, that is applied for 6 months after the effective date of this amendatory Act of the 104th General Assembly and that is required to have a federally enforceable State operating permit or a Clean Air Act Permit Program permit shall, in addition to any other applicabl e requirements, require each generator to: (i) meet standar ds at least as protective as Tier 4 standards for non-r oad diesel engines set out by the United States Environmen tal Protection Agency in 40 CFR 1039, as it exists on the eff ective date of this amendatory Act of the 104th General Assembl y; and (ii) operate solely as an emergency or standby unit in accordance with 35 Ill. Adm. Code 211.1920, as it exi sts on the effective date of this amendatory Act of the 1 04th General Assembly. (b) The A gency may issue NPDES permits exclusively under this subsecti on for the discharge of contaminants from point sources in to navigable waters, all as defined in the Federal Water Pollution Control Act, as now or hereafter amended, within the ju risdiction of the State, or into any well. All NPDES permits shall contain those terms and conditio ns, including, but not limited to, schedules o f compliance, which may be required to accomplish the purp oses and provisions of this Act. The Agency m ay issue general NPDES permits for discharges from categories o f point sources which are subject to the same permit limitat ions and conditions. Such general permits may be issued without individual applications and shall conform to regulations promulgated under Section 402 of the Federal Water Pollution Control Act, as now or hereafter amended. The Agency may include, among such conditions, effluent limitations and o ther requirements established under this Act, Board regulati ons, the Federal Water Pollution Control Act, as now or hereafter amended, and regulations pursuant thereto, and schedules for achieving compliance therewith at the earliest reasonable date. The Agency shall adopt filing requirements and procedures which are neces sary and appropriate for the issuance of NPDES permits, and which are consistent with the Act or regulations adopted by the Board, and with the Federal W ater Pollution Control Act, as now or hereafter ame nded, and regulations pursuant thereto. Th e Agency, subject to any conditions which may be prescribed b y Board regulations, may issue NPDES permits to allow dis charges beyond deadlines established by this Act or by regulat ions of the Board without the requirement of a variance, subject to the Federal W ater Pollution Control Act, as now or hereafter amend ed, and regulations pursuant thereto. (c ) Except for those facilities owned or operated by sanitary districts organized under the Metropolitan Water Reclam ation District Act, no permit for the development or constru ction of a new pollution control facility may be granted by the Agency unless the applicant submits proof to the Agency that th e location of the facility has been approved by the c ounty board of the county if in an unincorporated area, or th e governing body of the municipality when in an incorporated ar ea, in which the facility is to be located in accordance with Section 39.2 of this Act. For purposes of this subsect ion (c), and for purposes of Section 39.2 of this Act, the a ppropriate county board or governing body of the municipality s hall be the county board of the county or the governing bo dy of the municipality in which the fa cility is to be located as of the date when the applic ation for siting approval is filed. In t he event that siting approval granted pursuant to Section 39. 2 has been transferred to a subsequent owner or operato r, that subsequent owner or operator may apply to the Agency for, and the Agency may grant, a development or constructi on permit for the facility for which local siting approval was granted. Upon application to the Agency for a development or construction permit by that subsequent owner or operator, the permit applicant shall cause written notice of the permit application to be served upon the appropriate county b oard or governing body of the municipality that granted siting approval for that facility and upon any party to the siting pro ceeding pursuant to which siting approval was granted. In that event, the Agency shall conduct an evaluation of the subsequent owner or operator's prior experience in waste man agement operations in the manner conducted under sub section (i) of Section 39 of this Act.

Beginning August 20, 1993, if the pollution control fa cility consists of a hazardous or solid waste disposal facility for which the proposed site is located in an unincorporated ar ea of a county with a population of less than 100,000 and i ncludes all or a portion of a parcel of land that was, on Ap ril 1, 1993, adjacent to a municipality having a population of less than 5,000, then the local siting review required un der this subsection (c) in conjunction with any permit applie d for after that date shall be performed by the governing body of that adjacent municipality rather than the county boar d of the county in which the proposed site is located; and for the purposes of that local siting review, any referenc es in this Act to the county board shall be deemed to mean the governing body of that adjacent municipality; provided, howe ver, that the provisions of this paragraph shall not apply to any pro posed site which was, on April 1, 1993, owned in whole o r in part by another municipality. In the ca se of a pollution control facility for which a development p ermit was issued before November 12, 1981, if an operating permit has not been issued by the Agency prior to August 31, 1 989 for any portion of the facility, then the Agency may not i ssue or renew any development permit nor issue an original o perating permit for any portion of such facility unles s the applicant has submitted proof to the Agency that the loc ation of the facility has been approved by the appropriate county board or municipal governing body pursua nt to Section 39.2 of this Act. After Janua ry 1, 1994, if a solid waste disposal facility, any portio n for which an operating permit has been issued by the Agenc y, has not accepted waste disposal for 5 or more consecu tive calendar years, before that facility may accept any new or additional waste for disposal, the owner and operator must obtain a new operating permit under this Act for that facilit y unless the owner and operator have applied to the Agency for a permit authorizing the temporary suspension of waste acce ptance. The Agency may not issue a new operation permit und er this Act for the facility unless the applicant has submitted pro of to the Agency that the location of the facility has been app roved or re-approved by the appropriate county board or municipa l governing body under Section 39.2 of this Act after the facility ceased accepting waste. Except for those facilities owned or operated by sanitary districts orga nized under the Metropolitan Water Reclamation District Act, and except for new pollution control facilities governed by S ection 39.2, and except for fossil fuel mining facilities, the granting of a permit under this Act shall not relieve the applicant from meeting and securing all necessary zoning ap provals from the unit of government having zoning jurisdic tion over the proposed facility. Before beginning construction on any new sewage treatment plant or sludge drying site to be owned or operated by a sanitary district organized under the Metropolitan Water Reclamation D istrict Act for which a new permit (rather than the renewal or amendment of an existing permit) is required, such sanit ary district shall hold a public hearing within the munic ipality within which the proposed facility is to be located, or within the nearest community if the proposed facility is to be located within an unincorporated area, at which informa tion concerning the proposed facility shall be made available t o the public, and members of the publ ic shall be given the opportunity to express their v iews concerning the proposed facility. The Agency may issue a permit for a municipal waste trans fer station without requiring appro val pursuant to Section 39.2 provided that the followi ng demonstration is made: (1) the municipal waste transfer station was in existence on or before January 1 , 1979 and was in continuous operation from January 1, 1979 t o January 1, 1993; (2) t he operator submitted a permit application to the Agency to develop and operate the municipal waste transfer station dur ing April of 1994; (3) the operator can demonstrate that the county board of th e county, if the municipal waste transfer station is in a n unincorporated area, or the governing body of the mu nicipality, if the station is in an incorp orated area, does not object to resumption of the operation of t he station; and (4) t he site has local zoning approval. (d) The A gency may issue RCRA permits exclusively under this subsec tion to persons owning or operating a facility for the treatmen t, storage, or disposal of hazardous waste as defined under this Act. Subsection (y) of this Section, rat her than this subsection (d), shall apply to permits issued for CCR surface impoundments. All RCRA per mits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Ac t. The Agency may include among such conditions standards and other requirements established under this Act, Board regulations, the Resource Conservation and Recovery Act of 1976 (P.L. 94-580), as amended, and regulations pursuant thereto, and m ay include schedules for achieving compliance therewith as soo n as possible. The Agency shall require that a perfor mance bond or other security be provided as a condition for the issuance of a RCRA permit. In the case of a permit to operate a hazardous waste or PCB incinerator as defined in subsection (k) of Section 44, the Agency shall re quire, as a condition of the permit, that the operator of the facility perform such analyses of the waste to be incine rated as may be necessary and appropriate to ensure the sa fe operation of the incinerator. The Agency shall adopt filing requirements and procedures which are nece ssary and appropriate for the issuance of RCRA permits, and w hich are consistent with the Act or regulations adopted by the Board, and with the Resource Conservation a nd Recovery Act of 1976 (P.L. 94-580), as amend ed, and regulations pursuant thereto. The applicant shall make available to the public for inspection al l documents submitted by the applicant to the Agency in furthe rance of an application, with the exception of trade secrets , at the office of the county board or governing body of t he municipality. Such documents may be copied upon payment of the actual cost of reproduction during regular business hour s of the local office. The Agency shall issue a written statemen t concurrent with its grant or denial of the permit exp laining the basis for its decision. (e) The Agency may issue UIC permits exclusively under this subsect ion to persons owning or ope rating a facility for the underground injection of contami nants as defined under this Act. All UIC per mits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Ac t. The Agency may include among such conditions standards and other requirements established under this Act, Board regulations, th e Safe Drinking Water Act (P.L. 93-523), as amended, and regulations pursuant thereto, and may include schedules for ac hieving compliance therewith. The Agency shall require that a perfo rmance bond or other security be provided as a condition f or the issuance of a UIC permit. The Agenc y shall adopt filing requirements and procedures which are nec essary and appropriate for the issuance of UIC permits, and which are consistent with the Act or regulations adopted by the Board, and with the Safe Drinking Water Act (P.L. 93-523), as amend ed, and regulations pursuant thereto. The applicant shall make available to the public for inspection al l documents submitted by the applicant to the Agency in furthe rance of an application, with the exception of trade secrets , at the office of the county board or governing body of t he municipality. Such documents may be copied upon payment of the actual cost of reproduction during regular business hour s of the local office. The Agency shall issue a written statemen t concurrent with its grant or denial of the permit explain ing the basis for its decision. (f) In making any determination pursuant to Section 9.1 of this Act: (1) The Agency shall have authority to make the determin ation of any question required to be determined by the Clean Air Act, as now or hereafter amended, th is Act, or the regulations of the Board, including the de termination of the Lowest Achievable Emission Ra te, Maximum Achievable Control Technology, or Best Available Control Technology, consistent with the Board's regulations, if any. ( 2) The Agency shall adopt requirements as necessary to implement public participation procedures, inc luding, but not limited to, public notice, comment, and an opportunity for hearing, which must accompany the processing of applications for PSD permits. The Agency shall briefly describe and respond to all significant comm ents on the draft permit raised during the public comment p eriod or during any hearing. The Agency may group re lated comments together and provide one unified response fo r each issue raised. (3) Any complete permit application submitted to the Ag ency under this subsection for a PSD permit shall be granted or denied by the Agency not later than one year after the filing of suc h completed application.

(4) The Agency shall, after conferring with the appl icant, give written notice to the applicant of its propos ed decision on the application, including the terms and con ditions of the permit to be issued and the fact s, conduct, or other basis upon which the Agency wil l rely to support its proposed action. (g) The Agency shall include as conditions upon all permits issued for hazardous waste disposal sites such restrictions upon the future use of such sites as are reas onably necessary to protect public health and the environment, including permanent prohibition of the use of such sit es for purposes which may create an unreasonable risk of inj ury to human health or to the environment. After administrati ve and judicial challenges to such restrictions have been exhau sted, the Agency shall file such restrictions of record in the O ffice of the Recorder of the county in which the hazard ous waste disposal site is located. (h) A h azardous waste stream may not be deposited in a permitted hazar dous waste site unless specific authorization is obtained from the Agency by the generator and disposal site owner and opera tor for the deposit of that specific hazardous waste stream. The Agency may grant specific authorization for disposal of hazardous waste streams only after the generator has reasonab ly demonstrated that, considering technological feasibility and economic reasonableness, the hazardous waste cannot b e reasonably recycled for reuse, nor incinerated or chemically , physically, or biologically treated so as to neutralize the hazardous waste and render it nonhazardous. In granting a uthorization under this Section, the Agency may impose su ch conditions as may be necessary to accomplish the purposes o f the Act and are consistent with this Act and regulati ons promulgated by the Board hereunder. If the Agency ref uses to grant authorization under this Section, the appl icant may appeal as if the Agency refused to grant a permit, pursuant to the provisions of subsection (a) of Section 40 of t his Act. For purposes of this subsection (h), the term "generator" has the meaning given in Section 3.205 of this Act, unless: (1) the hazardous waste is treate d, incinerated, or partially recycled for reuse prior to disp osal, in which case the last person who treats, incinerates, or partially recycles the hazardous waste prior to disposal is the generator; or (2) the hazardous waste is from a respons e action, in which case the person performing the response act ion is the generator. This subsection (h) does not apply to any hazardous waste that is restricted from land dispos al under 35 Ill. Adm. Code 728. (i) Before issuing any RCRA permit, any permit for a waste storage site, sanitary landfill, waste disposal site, waste transfer station, was te treatment facility, waste incinerator, or any waste-transportation operation, any permit or interim authorization for a clean construction or demolition debris fill operation, or a ny permit required under subsection (d-5) of Section 5 5, the Agency shall conduct an evaluation of the prospective ow ner's or operator's prior experience in waste management opera tions, clean construction or demolition debris fil l operations, and tire storage site management. The Agency may deny such a permit, or deny or revoke interim authorization , if the prospective owner or operator or any employee or officer of the prospective owner or opera tor has a history of:

(1) repeated violations of federal, State, or local laws, regulations, standards, or ordinances in t he operation of waste management facilities or sites, clean construction or demolition debris fill operation facilities or sites, or ti re storage sites; or (2) conviction in this or another State of any crime which is a felony under the laws of this State, or conv iction of a felony in a federal court; or conviction in t his or another state or federal court of any of the follo wing crimes: forgery, official misconduct, bribery, p erjury, or knowingly submitting false infor mation under any environmental law, regulation, or permit term or condition; or

(3) proof of gross carelessness or incompetence in handling , storing, processing, transporting, or disposing of waste, clean construction or demolition debris, or u sed or waste tires, or proof of gr oss carelessness or incompetence in using clean construction or demolition debris as fill. (i-5) Be fore issuing any permit or approving any interim authorization for a clean construction or demolition debris fill ope ration in which any ownership interest is transferred between J anuary 1, 2005, and the effective date of the prohibition set forth in Section 22.52 of this Act, the Agency shall conduct an evaluation of the operation if any previous activities at the site or facility may have caused or allowed cont amination of the site. It shall be the responsibility of the o wner or operator seeking the permit or interim authorization to provide to the Agency all of the information necessary for the Agency to conduct its evaluation. The Age ncy may deny a permit or interim authorization if previo us activities at the site may have caused or allowed contamination at the site, unless such contamination is authorized under any permit issued by the Agency. (j) The issuance under this Act of a permit to engage in the surface mining of any resources other than fossil fuels shall not relieve the permittee from its duty to comply with any applicable l ocal law regulating the commencement, location, or opera tion of surface mining facilities. (k) A devel opment permit issued under subsection (a) of Section 39 for an y facility or site which is required to have a permit under subs ection (d) of Section 21 shall expire at the end of 2 calend ar years from the date upon which it was issued, unless within that period the applicant has taken action to develop the faci lity or the site. In the event that review of the conditions of the development permit is sought pursuant to Section 40 or 41, or permittee is prevented from commencing development of the facility or site by any other litigation beyond the permittee' s control, such two-year period shall be deemed to begin on the date upon which such review proc ess or litigation is concluded. (l) No permi t shall be issued by the Agency under this Act for construction or operation of any facility or site located within the boundaries of any setback zone established pursuant to this Act, where such cons truction or operation is prohibited. ( m) The Agency may issue permits to persons owning or operatin g a facility for composting landscape waste. In granting such pe rmits, the Agency may impose such conditions as may be necessary to accomplish the purposes of this Act, and as are not inconsistent with applicable regulations promulgated by the Board. Except as otherwise provided in this Act, a bo nd or other security shall not be required as a condition for the issuance of a permit. If the Agency denies any permit pursuant to this subsection, the Agency shall transmit to the applicant within the time limitations of this subsection spec ific, detailed statements as to the reasons the permit application was denied. Such statements shall include but not be limit ed to the following: (1) the Sections of this Act that may be violated if the permit were granted; (2) the specific regulations pr omulgated pursuant to this Act that may be violated if the pe rmit were granted; (3 ) the specific information, if any, the A gency deems the applicant did not provide in its applicati on to the Agency; and (4) a statement of spec ific reasons why the Act and the regulations might be vio lated if the permit were granted. If no fina l action is taken by the Agency within 90 days after the fi ling of the application for permit, the applicant may deem the permit issued. Any applicant for a p ermit may waive the 90-day limitation by filing a written statement with the Agency. The Agency shall issue permits for such facilities upon receipt of an ap plication that includes a legal description of the site, a topog raphic map of the site drawn to the scale of 200 feet to the inch or larger, a description of the operation, including the area served, an estimate of the volume of materials to be processed, an d documentation that: (1) the facility incl udes a setback of at least 200 feet from the nearest potab le water supply well; (2) the facility is located outside the boundary of the 10-year floodplain or the site will be floodproofed; (3) the facility is located so as to minimiz e incompatibility with the character of the surrounding are a, including at least a 200 foot setback from any resi dence, and in the case of a facility that is developed or t he permitted composting area of which is expanded after November 17, 1991, the composting area is located at least 1/8 mile from the nearest r esidence (other than a residence located on the same p roperty as the facility); (4) the design of the facility will prevent any compos t material from being placed within 5 feet of the water tab le, will adequately control runoff from th e site, and will collect and manage any leachate that is generated on the site; (5) the operation of the facility will include approp riate dust and odor control measures, limitations on o perating hours, appropriate noise control measures for shredding, chipping and similar equipment, management pr ocedures for composting, containment and disposal of n on-compostable wastes, procedures to be used for te rminating operations at the site, and recordkeeping sufficient to docum ent the amount of materials received, composted, and otherwis e disposed of; and (6) the operation will be conducted in accordance with any app licable rules adopted by the Board. The Agency shall issue renewable permits of not longer than 10 yea rs in duration for the composting of l andscape wastes, as defined in Section 3.155 of th is Act, based on the above requirements. Th e operator of any facility permitted under this subsection (m) must submit a written annual statement to the Agency on or before April 1 of each y ear that includes an estimate of the amount of mater ial, in tons, received for composting. (n) The Agency shall issue permits jointly with the Department of Transportation for the dredging or deposit of mate rial in Lake Michigan in accord ance with Section 18 of the Rivers, Lakes, and Streams Act . (o) (Blank). (p) (1) Any person submitting an application for a permit for a ne w MSWLF unit or for a lateral expansion under subsection (t) o f Section 21 of this Act for an existing MSWLF unit that has not received and is not subject to local siting approval und er Section 39.2 of this Act shall publish notice of the app lication in a newspaper of general circulation in the county i n which the MSWLF unit is or is proposed to be located. The not ice must be published at least 15 days before submissio n of the permit application to the Agency. The notice shall st ate the name and address of the applicant, the location of the MSWLF unit or proposed MSWLF unit, the nature and size of t he MSWLF unit or proposed MSWLF unit, the nature of the activ ity proposed, the probable life of the proposed activity, th e date the permit application will be submitted, and a state ment that persons may file written comments with the Agency concerning the permit application within 30 days after the filing of t he permit application unless the time period to submit com ments is extended by the Agency. When a permit applicant submits information to the Agency to supp lement a permit application being reviewed by th e Agency, the applicant shall not be required to reissue the notice under this subsection. (2) The Agency shall accept written comments concerning the permit application that are postmarked no later than 30 days after the filing of th e permit application, unless the time period to accept co mments is extended by the Agency. (3) Each applicant for a permit described in part (1) of this subsectio n shall file a copy of the permit application with the count y board or governing body of the municipality in which the MSWLF unit is or is proposed to be located at the same time the application is submitted to the Agency. The permit applica tion filed with the county board or governing body of the mun icipality shall include all documents submitted to or to be submitted to the Agency, except trade secrets as determ ined under Section 7.1 of this Act. The permit application and other documents on file with the county board or governing body of the municipality shall be made available for pu blic inspection during regular business hours at the office of the county board or the governing b ody of the municipality and may be copied upon payment of the actual cost of reproduction. (q) Within 6 months after July 12, 2011 (the effective date of Public Act 97-95), the Agency, in consultation with the regulat ed community, shall develop a web portal to be posted on its w ebsite for the purpose of enhancing review and promoting ti mely issuance of permits required by this Act. At a minimu m, the Agency shall make the following information available on the web portal: (1) Checklists and guidance relating to the completion of permit applications, developed pursuant to subsect ion (s) of this Section, which may include, but are not lim ited to, existing instructions for completing the applica tions and examples of complete applications. As the Agency develops new checklists and develops guidance, it shall supplement the web portal wi th those materials. (2) Wi thin 2 years after July 12, 2011 (the effective date of Pu blic Act 97-95), permit application forms or portions of permit applications that can be completed and saved elec tronically, and submitted to the Agency electronically with digital signatures. (3) Within 2 years after July 12, 2011 (the effective date o f Public Act 97-95), an online tracking system where an applicant may review the status of its pending applicat ion, including the name and contact information of the permit analyst assigned to the application. Until the online tracking system has been developed, the Agency shall post on its website semi-annual permitting effic iency tracking reports that include statistics on the tim eframes for Agency action on the following types of permits rece ived after July 12, 2011 (the effective date of Public Act 97-95): air construction permits, new NPDES perm its and associated water construction permits, and m odifications of major NPDES permits and associated water construction permits. The reports must be posted by February 1 and August 1 each year and shall include: (A) the number of applications received for each type of permit, the number of applications on which the Agency has taken action, and the number of applications still pending; and

(B) for those applications where the Agenc y has not taken action in accordance with the timef rames set forth in this Act, the date the appl ication was received and the reasons for any dela ys, which may include, but shall not be limited to, (i) the application being inadequate or incompl ete, (ii) scientific or technical disagreements with t he applicant, USEPA, or other local, state, or federal agencies involved in the permitting approval proce ss, (iii) public opposition to the permit, or (iv) Ag ency staffing shortages. To the extent practicable, the tracking report shall provide approximate dates when cause for delay was identified by the Agency, whe n the Agency informed the applicant of the problem leading to the delay, and when the applicant remedied th e reason for the delay. (r) Up on the request of the applicant, the Agency shall notify th e applicant of the permit analyst assigned to the appli cation upon its receipt. (s) The Agency is authorized to prepare and distribute guida nce documents relating to its administration of this Section an d procedural rules implementing this Section. Guidance doc uments prepared under this subsection shall not be consid ered rules and shall not be subject to the Illinois Administrative Procedure Act. Such guidance shall no t be binding on any party. (t) Ex cept as otherwise prohibited by federal law or regulation, any person submitting an application for a permit may include wit h the application suggested permit language for Agency consi deration. The Agency is not obligated to use the suggested language or any portion thereof in its permitting decis ion. If requested by the permit applica nt, the Agency shall meet with the applicant to discuss the suggested language. (u) If requ ested by the permit applicant, the Agency shall provide the perm it applicant with a copy of the draft permit prior to any p ublic review period. (v) If requ ested by the permit applicant, the Agency shall provide the permit applicant with a copy of the fin al permit prior to its issuance. (w) An air pollution permit shall not b e required due to emissions of greenhouse gases, as specif ied by Section 9.15 of this Act. (x) If, bef ore the expiration of a State operating permit that is issued pursuant to subsection (a) of this Section and conta ins federally enforceable conditions limiting the potential t o emit of the source to a level below the major source thresh old for that source so as to exclude the source from the Clean Air Act Permit Program, the Agency receives a complete ap plication for the renewal of that permit, then all of the terms and conditions of the permit shall remain in effect until fin al administrative action has been taken on the applicati on for the renewal of the permit. (y) The Agency may issue permits exclusively under this sub section to persons owning or operating a CCR surface imp oundment subject to Section 22.59. (z) If a mass animal mortality event is declare d by the Department of Agriculture in accordance with the Ani mal Mortality Act: (1) the owner or operat or responsible for the disposal of dead animals is exempt ed from the following: (i) obtaining a permit for the construction, installation, or operation of any type of facility or equipment issued in accordance with subsecti on (a) of this Section; (ii) obtaining a permit for open burning in accordance with the rules adopted by the Board; and (iii) registering the disposal of dead animals as an elig ible small source with the Agency in accordance with Sectio n 9.14 of this Act; (2) as applicable, the owner or operator responsibl e for the disposal of dead animals is required to obtain the f ollowing permits: (i) an NPDES permit in accordance with subsection (b) o f this Section; (i i) a PSD permit or an NA NSR permit in accordance with Se ction 9.1 of this Act; (iii) a lifetime State operating permit or a federally enforceabl e State operating permit, in accordance with subsection (a) of this Section; or (iv) a CAAPP permit, in accordan ce with Section 39.5 of this Act. All CCR su rface impoundment permits shall contain those terms and conditions, including, but not limited to, schedules of com pliance, which may be required to accomplish the purposes and provisions of this Act, Board regulations, the Illinois Gro undwater Protection Act and regulations pursuant thereto, an d the Resource Conservation and Recovery Act and regulations pursuant thereto, and may include schedules for achieving complian ce therewith as soon as possible. The Boa rd shall adopt filing requirements and procedures that are nec essary and appropriate for the issuance of CCR surface impoundm ent permits and that are consistent with this Act or regulati ons adopted by the Board, and with the RCRA, as amend ed, and regulations pursuant thereto. The applicant shall make available to the public for inspection al l documents submitted by the applicant to the Agency in furthera nce of an application, with the exception of trade s ecrets, on its public internet website as well as at the offi ce of the county board or governing body of the municipalit y where CCR from the CCR surface impoundment will be perma nently disposed. Such documents may be copied upon pay ment of the actual cost of reproduction during regular busi ness hours of the local office. The Agency sh all issue a written stat ement concurrent with its grant or denial of the permit explaining the basis for its decision.(Source: P.A. 101-171, eff. 7-30-19; 102-216, eff. 1-1-22; 102-558, eff. 8-20-21; 102-813, eff. 5-13-22.) Section 90-50. The Electric Vehicle Rebate Act is amended by changing Sections 35, 40, and 45 as follows: (415 ILCS 120/35) Sec. 35. User fees. (a) The Office of the Secretary of State shall collect annual user fees from any individual, partnership, association , corporation, or agency of the United States government th at registers any combination of 10 or more of the following types of motor vehicles in the Covered Area: (1) vehicles of the First Division, as defined in the Illinois Vehic le Code; (2) vehicles of the Second Division registered under the B, C, D, F, H, MD, MF, MG, MH and MJ plate categories, a s defined in the Illinois Vehicle Code; and (3) commut er vans and livery vehicles as defined in the Illinois Vehi cle Code. This Section does not apply to vehicles registered unde r the International Registration Plan under Section 3-4 02.1 of the Illinois Vehicle Code. The user fee shall be $2 0 for each vehicle registered in the Covered Area for each fiscal year. The Office of the Secretary of State shall collect the $20 wh en a vehicle's registration fee is paid. (b) O wners of State, county, and local government vehicles, re ntal vehicles, antique vehicles, expanded-use antique vehicles, electric vehicles, and motorcycles are exempt from paying the user fees on such vehicles. (c) The Office of the Secretary of State shall deposit the user fees collected i nto the Electric Vehicle and Charging Rebate Fund.(Source: P.A. 101-505, eff. 1- 1-20; 102-662, eff. 9-15-21.) (415 ILCS 120/40) Sec. 40. Appropriations from the Electric Vehicle and Charging Rebate Fund. (a) The Agency shall estimate the amount of user fees expected t o be collected under Section 35 of this Act for each fiscal year. User fee funds shall be deposited into an d distributed from the Electric Vehicle and Ch arging Rebate Fund in the following manner: (1) Through fiscal year 2023, an annual amount not to exceed $225,000 may be appropriated to the Agency fro m the Electric Vehicle and Charging Rebate Fund to pay its costs of admin istering the programs authorized by Section 27 of this Ac t. Beginning in fiscal year 2024 and in each fiscal year thereafter, an annual amount not to exceed $600,000 may be appropriated to the Agency from t he Electric Vehicle and Charging Rebate Fund to pay its costs of administering the programs authorized by Section 27 o f this Act. An amount not to exceed $225,000 may be appropriated to the Secretary of State from the E lectric Vehicle and Charging Rebate Fund to pay the Secre tary of State's costs of administering the programs authorized under this Act.

(2) In fiscal year 2022 and each fiscal year thereafter, after appropriation of the amounts authoriz ed by item (1) of subsection (a) of this Section, the remaining m oneys estimated to be collected during each fisca l year shall be appropriated. (3) (Blank). (4) Moneys appropriated to fund the programs a uthorized in Sections 25 and 30 shall be expended only after they have been collected and deposited into the Electric Vehicle and Charging Rebate Fund. (b) Amounts appropriated to and deposited int o the Electric Vehicle and Charging Rebate Fund from the General Revenue Fund, or any other fund, shall be distributed from t he Electric Vehicle and Chargin g Rebate Fund to fund the program authorized in Section 27 .(Source: P.A. 103-8, eff. 6-7-23; 103-363, eff. 7-28-23; 103-605, eff. 7-1-24; 104-6, eff. 7-1-25.) (415 ILCS 120/45) Sec. 45. Electric Vehicle and Charging

Rebate Fund; creation; deposit of user fees. A separate fund in the State treasury Treasury called the Electric Vehicle and Charging Rebate Fund is cre ated, into which shall be transferred the user fees as provided in Section 35, funds as provided in Section 605-1075 of the Department of Commerce and Economic Opportunity Law of the Civil Administrative Code of Illinois, and any o ther revenues, deposits, State appropriations, contributio ns, grants, gifts, bequests, legacies of money and s ecurities, or transfers as provided by law from, without limi tation, governmental entities, private sources, foundati ons, trade associations, industry organizations, and not-for-profit organizations.(Source: P.A. 102-662, eff . 9-15-21.) ARTICLE 99. Secti on 99-97. Severability. The provisions of this Act are severabl e under Section 1.3 1 of the Statute on Statutes.