HB5021 103RD GENERAL ASSEMBLY

LRB103 36729 LNS 66839 b

103RD GENERAL ASSEMBLY
State of Illinois
2023 and 2024
HB5021

Introduced 2/8/2024, by Rep. Janet Yang Rohr

SYNOPSIS AS INTRODUCED:

See Index

Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Sets forth legislative findings and objectives. Provides that beginning on November 1, 2024, and every 3 years thereafter on November 1, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Includes provisions regarding the purposes and available resources for the integrated resource plan and rulemaking powers of the Agency. Requires the Agency to maintain a list of qualified experts or expert consulting firms for the purpose of developing integrated resource plans. Sets forth meeting requirements for an electric cooperative and publishing and posting requirements for specific information related to an electric cooperative. Amends the Open Meetings Act. Provides that a public body may hold closed meetings to consider 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 certain topics. Amends the Illinois Municipal Code. Allows any additional municipality which operates an electric utility system to join a municipal power agency consistent with the bylaws of the municipal power agency, and upon payment of any termination obligations. Outlines a number of requirements for a municipal power agency. Makes other changes. Amends the Public Utilities Act. In a provision regarding net electricity metering, defines "electricity provider" and "electric utility". Makes other changes. Amends the Eminent Domain Act. Provides that for all acquisitions where the property, or any right or interest in property, is to be used for utility purposes, and where the condemning authority is an entity required to submit an integrated resource plan under the Municipal and Cooperative Electric Utility Planning and Transparency Act, the rebuttable presumption that such acquisition of that property is primarily for the benefit, use, or enjoyment of the public and necessary for a public purpose shall only apply if the most recent integrated resource plan filed by the condemning authority identified the facility or articulated a need for a facility similar capacity and type to the facility for which the property or right or interest is sought. Effective immediately.

A BILL FOR

AN ACT concerning regulation.

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

Section 1. Short title. This Act may be cited as the Municipal and Cooperative Electric Utility Planning and Transparency Act.

Section 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) These utilities are managed by elected officials, elected board members, or their appointees. Due to their governance structures, municipal and cooperative electric utilities are exempt from certain regulatory requirements and oversight under State and federal law.

(3) State residents who are served by these utilities, and who pay rates for electricity set by these utilities, often lack access to important information about these utilities' generation portfolios, procurement, management practices, and budgets. Because democratic elections by member-ratepayers or customers are the ultimate guarantor of the integrity and cost-effectiveness of these utilities' operations, access to this information is crucial to ensuring management of these utilities is prudent and responsive.

(4) Good utility practice entails long-term planning on the part of a utility, including anticipating retirement of existing generation resources, planning new generation build or purchase well in advance of any capacity shortfall, and developing rigorous estimates of future load to inform procurement, construction, and retirement decisions.

(5) In many other states, integrated resource planning processes have been used to avoid capacity shortfalls, minimize ratepayer costs, and increase public participation in and knowledge of electric generation portfolio choices, even where the planning utility is not otherwise subject to rate approval by the state.

(6) It is in the best interests of State electricity customers and member-ratepayers that electricity is provided by a portfolio of generation and storage resources and demand-side programs that minimizes both cost and environmental impacts and that long-term utility planning can and should facilitate the achievement of such portfolios.

(7) With the enactment of the Inflation Reduction Act of 2022, municipal and cooperative electric utilities have access to a variety of federal funding streams designed to facilitate transition from fossil fuel to renewable generation. Consistent with Congress's intent, municipal and cooperative electric utilities should perform a comprehensive analysis of their existing portfolio and have a duty, as utility managers, to identify opportunities to minimize member-ratepayer and customer costs.

(8) To ensure utilities minimize ratepayer costs, maximize opportunities for transition from fossil fuels to renewable resources, and to increase transparency and democratic participation, it is important that municipal and cooperative electric utilities participate in an integrated resource planning process with public participation and Illinois Power Agency oversight.

Section 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.

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

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

"Renewable generation resource" means a resource for generating electricity that uses wind, solar, 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.

Section 15. Purpose and contents of integrated resource plan.

(a) Beginning on November 1, 2024, and every 3 years thereafter on November 1, all electric cooperatives with members in this State, municipal power agencies, and municipalities shall file with the Agency an integrated resource plan, except that municipalities and electric cooperatives that are members of, and have a full requirements contract with, a municipal power agency or electric cooperative subject to this Act may file a statement adopting such other utility's integrated resource plan.

(b) The purposes of the integrated resource plan are to provide a comprehensive description of the utility's current portfolio of electrical generation, storage, demand-side programs, and transmission resources, to forecast future load changes to facilitate prudent planning with respect to resource procurement and retirement, to determine what resource portfolio will meet ratepayers' needs while minimizing cost and environmental impact, and to articulate steps the utility will take to reduce customer costs and environmental impacts through changes to its current generation portfolio through construction, procurement, retirement, or demand-side programs.

(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 20-year planning period, taking into account both supply-side and demand-side electric power resources.

(d) An integrated resource plan shall include, at a minimum:

(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 10 years, and an explanation of the reason for the retirement;

(G) nameplate and peak available 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 compliance obligations, or compliance obligations expected to apply within the next 10 years, and any proposed or 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 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 energy or capacity to any purchaser.

(4) A list of any demand-side programs and total distributed generation.

(5) A narrative description of all existing transmission facilities owned by the utility, in whole or in part, that identifies any transmission constraints or critical contingencies, and identification of the regional transmission organization, if any, which exercises operational control over the transmission facility.

(6) A list of all capital expenditures exceeding $1,000,000 in the previous calendar year that includes a brief description of the expenditure, the total amount expended, and whether the expenditure was required to conform with State or federal law, rule, or regulation;

(7) A description of all transmission costs, disaggregated by expenditure, that identifies all capital expenditures on physical infrastructure and contracts for rights costing greater than $1,000,000 over the term of the agreement.

(8) 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 complete a FERC Form 1 for the prior calendar year.

(9) A range of load forecasts for the 5-year planning period that includes hourly data representing a high-load, low-load, and expected-load scenario for all retail customers, consistent with the requirements of paragraph (1) of subsection (d) of Section 16-111.5 of the Public Utilities Act and any associated rules or regulations. Such forecasts shall include:

(A) all underlying assumptions;

(B) an hourly load analysis consistent with the requirements of paragraph (1) of subsection (b) of Section 16-111.5 of the Public Utilities Act;

(C) analysis of the impact of any demand-side programs, consistent with paragraph (2) of subsection (b) of Section 16-111.5 of the Public Utilities Act;

(D) any reserve margin or other obligations placed on the utility by regional transmission organizations to which it is a member; and

(E) to the extent the information is available, an assessment of the accuracy of any past load forecasts submitted pursuant to this Section and an explanation of any deviation of greater than 10% in either direction from the forecasted load.

(10) The results of an all-source request for proposals for generation resources and capacity contracts.

(11) A 5-year action plan for meeting the forecasted load that minimizes customer cost and adverse environmental impacts. As part of the action plan, the utility shall:

(A) Identify any generation or storage resources anticipated to be removed from service in the 5 years following the date on which the integrated resource plan is submitted.

(B) Determine whether given forecasted load growth or unit retirements, or both, the utility will need to procure additional 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 this additional capacity and energy.

(D) Provide a narrative description of the utility's processes for assessing the present economic value of existing generation and state whether, consistent with this methodology, any currently operating units, if any, could be replaced by other resources at lower cost to ratepayers.

(E) Identify a preferred portfolio of generation, storage, and demand-side programs that, in the utility's judgment, meets its forecasted load while minimizing the ratepayer cost and environmental impacts to the extent reasonably achievable in the 5 years covered by the action plan. The portfolio shall incorporate any capacity or other reliability requirements of any regional transmission organization of which the utility is a member.

(F) If the preferred portfolio includes the construction of new generation or storage resources or transmission facilities, identify the preferred site for all new construction of generation, storage, or transmission facilities.

(G) If the utility states that it intends to remove a generation resource from service, include in the integrated resource plan a statement describing the utility's plan to minimize economic impacts to workers due to facility retirement. This statement shall include a description of:

(i) the utility's efforts to collaborate with the workers and their designated representatives, if any;

(ii) a transition timeline or date certain on which such a transition timeline shall be made available to ensure certainty for workers;

(iii) the utility's efforts to protect pension benefits and extend or replace health insurance, life insurance, and other employment benefits;

(iv) all training and skill development programs to be made available for workers who will see their employment reduced or eliminated as a result of the retirement; and

(v) any agreements with local governments regarding continuing tax or other transfer payments following the facility's retirement intended to minimize the impact on local services.

(H) Describe any anticipated capital expenditures in excess of $1,000,000 at existing generation facilities and the reason for such expenditures.

(12) A description of all models and methodologies used in performing the integrated resource planning process. The utility shall provide to the Agency, upon request, reasonable access to any computer models used in the analysis and workpapers, in electronic form, relied on in preparation of the report.

(e) As part of all integrated resource plans submitted in 2024, the utility shall identify all programs, grants, loans, or tax benefits for which the utility is eligible pursuant to the Inflation Reduction Act of 2022, and state whether the utility has applied for or otherwise used the program, grant, loan, or tax benefit. If the utility has not yet applied for or utilized the benefit, the utility shall state whether it intends to do so.

(f) Each utility shall submit, as part of its integrated resource plan, a least cost plan for constructing or procuring renewable energy resources to meet a minimum percentage of its load for all retail customers as follows: 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.

(g) Beginning in 2031, each utility shall submit, as part of its integrated resource plan, a least cost plan for supplying 100% of its total projected load through renewable generation resources in combination with storage resources and demand-side programs by 2045. This least cost plan shall provide for the retirement of all coal and gas generation resources by January 1, 2045.

(h) The Agency may adopt rules establishing additional requirements as to the form and content of integrated resource plans, including, but not limited to, specifying forecast methodologies.

Section 20. Stakeholder process. Prior to the submission of an integrated resource plan, a municipality, municipal power agency, or electric cooperative required to submit an integrated resource plan shall hold at least 2 stakeholders meetings open to all ratepayers and members of the public. Notice of the meetings shall be sent to all customers not less than 30 days prior to the meeting. During the meetings the utility shall describe its processes for developing the integrated resource plan and its core assumptions and constraints, 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 allow time for public comment and the utility shall provide attendees with a means of providing public comment in writing following the meeting.

Section 25. Procedures for submission of integrated resource plan.

(a) Each municipality, municipal power agency, and electric cooperative shall submit its integrated resource plan, as set forth in this Act, to the Agency by October 1 of the calendar year.

(b) The Agency may request further information from the utility. Any such requests shall be made in writing. If the Agency requests additional information, the utility shall provide responses no later than 15 days following the request.

(c) The Agency shall facilitate public comment on the integrated resource plan, as follows:

(1) upon submission of the integrated resource plan, the Agency shall post the integrated resource plan publicly on its website. The plan shall remain publicly accessible for at least 60 days.

(2) the utility shall hold at least 2 public meetings, one in person and one remotely, where it shall make a representative available to address questions about the resource plan. The meetings shall be held no sooner than 15 days, and no later than 45 days, after the integrated resource plan is made available to the public.

(3) the Agency shall accept public comments on the integrated resource plan for 60 days following its public posting via website, email, or mail. The Agency may extend this public comment period by an additional 60 days upon request by members of the public; and

(4) after the conclusion of the public comment period, as determined by the Agency, the Agency shall transmit copies of all public comments received to the utility.

(d) The utility shall review public comments and provide responses that reasonably address all issues or questions raised by such comments. The utility may modify its integrated resource plan in response to these comments. The utility shall prepare a document with responses to public comments and submit this response document to the Agency no later than 90 days after receiving the comments from the agency. This response document shall be posted publicly on the Agency's website along with the original integrated resource plan, as submitted, and any revisions made by the utility in response to public comments.

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

Section 30. Use of independent expert.

(a) The Agency shall maintain a list of qualified experts or expert consulting firms for the purpose of developing integrated resource plans on behalf of municipalities, municipal power agencies, and cooperatives. In order to qualify an expert or expert consulting firm must have:

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

(2) 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, including those established by the federal Energy Regulatory Commission and regional transmission organizations; and

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

(b) The Agency may assemble the list as part of the process for developing a list of qualified experts for experts to develop procurement plans, as set forth in subsection (a) of Section 1-75 of the Illinois Power Agency Act.

(c) 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 prepare the integrated resource plan on behalf of the utility. The Agency shall also provide each qualified expert's or expert consulting firm's response to the request for qualifications. A utility shall, within 5 business days, notify the Agency in writing if it objects to any experts or expert consulting firms on the lists. Objections shall be based on:

(1) the failure to satisfy qualification criteria;

(2) the identification of a conflict of interest; or

(3) the 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 the list, the objecting utility may withdraw its application and develop its integrated resource plan without agency assistance.

(d) A utility required to submit an integrated resource plan may elect to rely on an expert or expert consulting firm selected by the Agency to develop the plan and conduct stakeholder processes.

(e) A utility may submit a request to the Agency, not less than 6 months prior to the date on which the integrated resource plan is due, for such an expert or expert consulting firm.

(f) Upon receipt of such a request, the Agency shall issue requests for proposals to the qualified experts on the list assembled as set forth in subsections (a) through (c) to develop an integrated resource plan for that utility. The Agency shall select an expert or expert consulting firm to develop the integrated resource plan on behalf of the utility based on the proposals submitted.

(g) Subject to appropriation, if a utility elects to rely on an expert or expert consulting firm selected by the Agency, 90% of the costs assessed by the expert for development of the integrated resource plan shall be paid by the Agency, up to $250,000, and the remainder paid by the utility.

Section 35. Electric cooperatives member access.

(a) As used in this Section, "meeting" has the meaning given to that term in Section 1.02 of the Open Meetings Act.

(b) As used in this Section, except for subsection (j), "member" includes all members of an electric cooperative in accordance with the cooperative's bylaws. Where a generation and transmission electric cooperative's members are electric cooperatives rather than individuals, members of those member-cooperatives are members of the generation and transmission electric cooperative for purposes of this Section. As used in subsection (j), "member" includes only members of an electric cooperative with individual members.

(c) All meetings of an electric cooperative shall be open to all members, except that a cooperative, by a two-thirds affirmative vote of the board members present, may go into executive session for consideration of documents or information deemed to be confidential for legal, commercial, or personnel purposes.

(1) Before a board of directors convenes in executive session, the board shall announce the general topic of the executive session.

(2) Notice of all meetings of an electric cooperative shall be posted on the website of the electric cooperative at least 15 days prior to the meeting. Minutes of all meetings of an electric cooperative shall be posted on the website of the electric cooperative as soon as they have been approved and shall remain posted for at least one year after the date of the meeting. Upon request of a member, the electric cooperative shall make minutes of any meeting held after the effective date of this Act available. Minutes shall include the votes of each member of the board on all items for which approval was not unanimous.

(3) At every regular meeting of the governing body of an electric cooperative, members of the cooperative shall be given an opportunity to address the board on any matter concerning the policies and businesses of the cooperative. The board may place reasonable, viewpoint-neutral restrictions on the amount and duration of member comment.

(d) Each electric cooperative shall post on its website its current rates. The electric cooperative shall keep and make available to any member, upon request, all financial audits of the electric cooperative conducted in the last 3 fiscal years.

(e) Each electric cooperative shall adopt and post a written policy governing the election of directors on its website. The electric cooperative shall provide notice of the policy at the time a person becomes a member, as a bill insert at least once per year, and on request. The policy shall contain true and complete information on the following:

(1) Who is entitled to vote in an election, including how member-cooperatives may vote.

(2) How a member may obtain and cast a ballot.

(3) How a member may become a candidate for the board or any other elected leadership positions.

(f) At least 60 days before each board election, the electric cooperative shall post a list of candidates and deadline to return ballots on its website and leave the information posted until the election has concluded. The same information shall be included as part of a bill insert for a billing cycle occurring at no more than 60 but no fewer than 15 days prior to the deadline to return ballots.

(g) Each candidate for a position on the board of directors who has qualified under the electric cooperative's bylaws is entitled to receive a membership list in electronic format upon receipt and verification of any candidacy requirements. The membership list must include the names and addresses of all members as they appear in the electric cooperative's records.

Section 40. Conflict of interest disclosures.

(a) Each electric cooperative, municipality, and municipal power agency shall adopt, and post publicly on its website, written policies concerning:

(1) The compensation provided to a director on the board of directors, including information on any authorized per diem amounts, and the values of other benefits, services, or goods that a director receives.

(2) The disclosure of any gifts received by a director in excess of a de minimis amount.

(3) The requirements and procedures for a director on the board of directors to disclose in writing any conflicts of interest. At a minimum, the policy must require disclosure when a decision before the board could provide directly and as a proximate result of the decision a financial or other material benefit to:

(A) The director, if the benefit is unique to that director and not shared by similarly situated cooperative members.

(B) A parent, grandparent, spouse, partner in a civil union, child, or sibling of the director, if the benefit is unique to that director and not shared by similarly situated cooperative members.

(C) An entity in which the director is an officer or director or has a financial interest not shared by similarly situated cooperative members.

(b) Each electric cooperative shall disclose on its website all lobbying activities as defined by Section 2 of the Lobbyist Registration Act and the amount of expenditures on such activities on an annual basis. Where the electric cooperative is a member of a trade association or other organization that engages in lobbying activities, the electric cooperative shall post the amount of dues or other expenditures paid by the cooperative to such an organization and what percentage of the organization or association's budget is spent on lobbying activities.

Section 45. 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, (ii) 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, or (iii) information prohibited from disclosure by a regional transmission organization to ensure the integrity of competitive markets 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) Those meetings or portions of meetings of a fatality review team or the Illinois Fatality Review Team Advisory Council during which a review of the death of an eligible adult in which abuse or neglect is suspected, alleged, or substantiated is conducted pursuant to Section 15 of the Adult Protective Services Act.

(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.)

Section 50. The Illinois Municipal Code is amended by changing Sections 11-119.1-4 and 11-119.1-10 and by adding Section 11-119.1-5.5 as follows:

(65 ILCS 5/11-119.1-4) (from Ch. 24, par. 11-119.1-4)

Sec. 11-119.1-4. Municipal Power Agencies.

A. Any 2 or more municipalities, contiguous or noncontiguous, and which operate an electric utility system, may form a municipal power agency by the execution of an agency agreement authorized by an ordinance adopted by the governing body of each municipality. The agency agreement may state:

(1) that the municipal power agency is created and incorporated under the provisions of this Division as a body politic and corporate, municipal corporation and unit of local government of the State of Illinois;

(2) the name of the agency and the date of its establishment;

(3) that names of the municipalities which have adopted the agency agreement and constitute the initial members of the municipal power agency;

(4) the names and addresses of the persons initially appointed in the ordinances adopting the agency agreement to serve on the Board of Directors and act as the representatives of the municipalities, respectively, in the exercise of their powers as members;

(5) the limitations, if any, upon the terms of office of the directors, provided that such directors shall always be selected and vacancies in their offices declared and filled by ordinances adopted by the governing body of the respective municipalities;

(6) the location by city, village or incorporated town in the State of Illinois of the principal office of the municipal power agency;

(7) provisions for the disposition, division or distribution of obligations, property and assets of the municipal power agency upon dissolution; and

(8) any other provisions for regulating the business of the municipal power agency or the conduct of its affairs which may be agreed to by the member municipalities, consistent with this Division, including, without limitation, any provisions for weighted voting among the member municipalities or by the directors.

B. The presiding officer of the Board of Directors of any municipal power agency established pursuant to this Division or such other officer selected by the Board of Directors, within 3 months after establishment, shall file a certified copy of the agency agreement and a list of the municipalities which have adopted the agreement with the recorder of deeds of the county in which the principal office is located. The recorder of deeds shall record this certified copy and list and shall immediately transmit the certified copy and list to the Secretary of State, together with his certificate of recordation. The Secretary of State shall file these documents and issue his certificate of approval over his signature and the Great Seal of the State. The Secretary of State shall make and keep a register of municipal power agencies established under this Division.

C. Each municipality which becomes a member of the municipal power agency shall appoint a representative to serve on the Board of Directors, which representative may be a member of the governing body of the municipality. Each appointment shall be made by the mayor, or president, subject to the confirmation of the governing body. The directors so appointed shall hold office for a term of 3 years, or until a successor has been duly appointed and qualified, except that the directors first appointed shall determine by lot at their initial meeting the respective directors which shall serve for a term of one, 2 or 3 years from the date of that meeting. A vacancy shall be filled for the balance of the unexpired term in the same manner as the original appointment.

The Board of Directors is the corporate authority of the municipal power agency and shall exercise all the powers and manage and control all of the affairs and property of the agency. The Board of Directors shall have full power to pass all necessary ordinances, resolutions, rules and regulations for the proper management and conduct of the business of the board, and for carrying into effect the objects for which the agency was established.

At the initial meeting of the Board of Directors to be held within 30 days after the date of establishment of the municipal power agency, the directors shall elect from their members a presiding officer to preside over the meetings of the Board of Directors and an alternative presiding officer and may elect an executive board. The Board of Directors shall determine and designate in the agency's bylaws the titles for the presiding officers. The directors shall also elect a secretary and treasurer, who need not be directors. The board may select such other officers, employees and agents as deemed to be necessary, who need not be directors or residents of any of the municipalities which are members of the municipal power agency. The board may designate appropriate titles for all other officers, employees, and agents. All persons selected by the board shall hold their respective offices during the pleasure of the board, and give such bond as may be required by the board.

D. The bylaws of the municipal power agency, and any amendments thereto, shall be adopted by the Board of Directors by a majority vote (adjusted for weighted voting, if provided in the Agency Agreement) to provide the following:

(1) the conditions and obligations of membership, if any;

(2) the manner and time of calling regular and special meetings of the Board of Directors;

(3) the procedural rules of the Board of Directors;

(4) the composition, powers and responsibilities of any committee or executive board;

(5) the rights and obligations of new members, conditions for the termination of membership, including a formula for the determination of required termination payments, if any, and the disposition of rights and obligations upon termination of membership; and

(6) such other rules or provisions for regulating the affairs of the municipal power agency as the board shall determine to be necessary.

E. Every municipal power agency shall maintain an office in the State of Illinois to be known as its principal office. When a municipal power agency desires to change the location of such office, it shall file with the Secretary of State a certificate of change of location, stating the new address and the effective date of change. Meetings of the Board of Directors may be held at any place within the State of Illinois, designated by the Board of Directors, after notice. Unless otherwise provided by the bylaws, an act of the majority of the directors present at a meeting at which a quorum is present is the act of the Board of Directors.

F. The Board of Directors shall hold at least one meeting each year for the election of officers and for the transaction of any other business. Special meetings of the Board of Directors may be called for any purpose upon written request to the presiding officer of the Board of Directors or secretary to call the meeting. Such officer shall give notice of the meeting to be held not less than 10 days and not more than 60 days after receipt of such request. Unless the bylaws provide for a different percentage, a quorum for a meeting of the Board of Directors is a majority of all members then in office. All meetings of the board shall be held in compliance with the provisions of "An Act in relation to meetings", approved July 11, 1957, as amended.

G. The agency agreement may be amended as proposed at any meeting of the Board of Directors for which notice, stating the purpose, shall be given to each director and, unless the bylaws prescribe otherwise, such amendment shall become effective when ratified by ordinances adopted by a majority of the governing bodies of the member municipalities. Each amendment, duly certified, shall be recorded and filed in the same manner as for the original agreement.

H. Each member municipality shall have full power and authority, subject to the provisions of its charter and laws regarding local finance, to appropriate money for the payment of the expenses of the municipal power agency and of its representative in exercising its functions as a member of the municipal power agency.

I. Any additional municipality which operates an electric utility system may join the municipal power agency, or any member municipality may withdraw therefrom consistent with the bylaws of the municipal power agency, and upon payment of any termination obligations as described in subsection D upon the approval by ordinance adopted by the governing body of the majority of the municipalities which are then members of the municipal power agency. Any new member shall agree to assume its proportionate share of the outstanding obligations of the municipal power agency and any member permitted to withdraw shall remain obligated to make payments under any outstanding contract or agreement with the municipal power agency or to comply with any exit or early termination provisions set forth in that contract or agreement. Any such change in membership shall be recorded and filed in the same manner as for the original agreement.

J. Any 2 or more municipal power agencies organized pursuant to this Division may consolidate to form a new municipal power agency when approved by ordinance adopted by the governing body of each municipality which is a member of the respective municipal power agency and by the execution of an agency agreement as provided in this Section.

(Source: P.A. 96-204, eff. 1-1-10.)

(65 ILCS 5/11-119.1-5.5 new)

Sec. 11-119.1-5.5. Agency records, budgets, and quarterly reports.

(a) A municipal power agency shall keep accurate accounts and records of its assets, liabilities, revenues, and expenditures in accordance with generally accepted accounting principles. Such accounts and records shall include, but are not limited to, depreciation, operating and maintenance expenses for all generation and transmission assets, fuel costs, cost and revenue from the purchase or sale of environmental compliance credits, revenue from energy, capacity, and ancillary market sales, all payments received from member municipalities, membership dues or other payments made to trade associations or industry organizations, and lobbying expenditures. Such records shall be audited on an annual basis by an independent auditor using generally accepted auditing standards and shall include contents as set forth in Section 8-8-5, and shall be filed with the Comptroller as described by Section 8-8-7.

(b) A municipal power agency shall, on an annual basis, prepare one-year and 5-year budgets that include all revenues and expenses, including, but not limited to, those categories described in subsection (a). As part of each one-year budget, the municipal power agency shall include a report identifying and explaining any variance from the previous annual budget of 5% or greater in any expenditure or revenue line item. Such budgets shall be provided to member municipalities no less than 60 days prior to any meeting of the municipal power agency during which action on the budget is or will be part of the agency agenda.

(c) The municipal power agency shall post, on a publicly available website, all one-year and 5-year budgets required under subsection (b) and the annual audited financial statements required under subsection (a).

(d) The municipal power agency shall make available, upon request to any of its member municipalities, access to all municipal power agency all records and accounts and all financial information relating to ownership and operation of agency assets and the generation, procurement, and delivery of electricity to which the agency has access, including, but not limited to, unit scheduling information, market revenue and off-system sales data, and fuel and other variable cost information. Such information shall be provided in a timely manner and through reasonable means, and members shall be permitted to make copies of any documents retained solely by the agency. Such access shall be provided without regard to any nondisclosure agreement that has been or may be adopted by the municipal power agency.

(e) The municipal power agency shall prepare, on a quarterly basis, a report to its member municipalities describing all expenditures made for the purpose of lobbying, as both terms are defined by Section 2 of the Lobbyist Registration Act, and a brief summary of the topics and positions on which lobbying activities were undertaken. Where the municipal power agency is a member of an organization or trade association that expends some or all of membership dues on lobbying activities, the municipal power agency shall include in this report the amount of those membership dues, what proportion of those dues were spent on lobbying activities, and the topics and positions on which lobbying activities were undertaken by the organization or trade association of which the municipal power agency is a member.

(65 ILCS 5/11-119.1-10) (from Ch. 24, par. 11-119.1-10)

Sec. 11-119.1-10. Exercise of powers. A municipal power agency may exercise any and all of the powers enumerated in this Division, except the power of eminent domain, without the consent and approval of the Illinois Commerce Commission. The exercise of the power of eminent domain by a municipal power agency shall be subject to the consent and approval of the Illinois Commerce Commission in the same manner and to the same extent as public utilities under the Public Utilities Act, including the issuance of a certificate of public convenience and necessity as provided for in Section 8-406 of that Act. During the consideration of any petition for authority to exercise the power of eminent domain the Illinois Commerce Commission shall evaluate and give due consideration to whether the project for which eminent domain is sought is part of the preferred portfolio as described in subsection (d) of Section 15 of the Municipal and Cooperative Electric Utility Planning and Transparency Act, or least cost plans for procuring renewable resources as described in subsections (f) and (g) of Section 20 of the Municipal and Cooperative Electric Utility Planning and Transparency Act and to the impact of the acquisition on farmlands in the State with the goal of preserving the land to the fullest extent reasonably possible.

(Source: P.A. 90-416, eff. 1-1-98.)

Section 55. The Public Utilities Act is amended by changing Sections 16-107.5 and 17-500 as follows:

(220 ILCS 5/16-107.5)

Sec. 16-107.5. Net electricity metering.

(a) The General Assembly finds and declares that a program to provide net electricity metering, as defined in this Section, for eligible customers can encourage private investment in renewable energy resources, stimulate economic growth, enhance the continued diversification of Illinois' energy resource mix, and protect the Illinois environment. Further, to achieve the goals of this Act that robust options for customer-site distributed generation continue to thrive in Illinois, the General Assembly finds that a predictable transition must be ensured for customers between full net metering at the retail electricity rate to the distribution generation rebate described in Section 16-107.6.

(b) As used in this Section, (i) "community renewable generation project" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act; (ii) "eligible customer" means a retail customer that owns, hosts, or operates, including any third-party owned systems, a solar, wind, or other eligible renewable electrical generating facility that is located on the customer's premises or customer's side of the billing meter and is intended primarily to offset the customer's own current or future electrical requirements; (iii) "electricity provider" means an electric utility or alternative retail electric supplier; (iv) "eligible renewable electrical generating facility" means a generator, which may include the co-location of an energy storage system, that is interconnected under rules adopted by the Commission and is powered by solar electric energy, wind, dedicated crops grown for electricity generation, agricultural residues, untreated and unadulterated wood waste, livestock manure, anaerobic digestion of livestock or food processing waste, fuel cells or microturbines powered by renewable fuels, or hydroelectric energy; (v) "net electricity metering" (or "net metering") means the measurement, during the billing period applicable to an eligible customer, of the net amount of electricity supplied by an electricity provider to the customer or provided to the electricity provider by the customer or subscriber; (vi) "subscriber" shall have the meaning as set forth in Section 1-10 of the Illinois Power Agency Act; (vii) "subscription" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act; (viii) "energy storage system" means commercially 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 limited to, electrochemical, thermal, and electromechanical technologies, and may be interconnected behind the customer's meter or interconnected behind its own meter; and (ix) "future electrical requirements" means modeled electrical requirements upon occupation of a new or vacant property, and other reasonable expectations of future electrical use, as well as, for occupied properties, a reasonable approximation of the annual load of 2 electric vehicles and, for non-electric heating customers, a reasonable approximation of the incremental 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 each individual eligible customer. The utility shall submit these approximations to the Commission for review, modification, and approval; and (x) "electricity provider" and "electric utility" includes municipalities and municipal power agencies as defined in Section 11-119.3-1 of the Illinois Municipal Code and electric cooperatives as defined in Section 3-119 of this Act.

(c) A net metering facility shall be equipped with metering equipment that can measure the flow of electricity in both directions at the same rate.

(1) For eligible customers whose electric service has not been declared 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 basis and electric supply service is not provided based on hourly pricing, this shall typically be accomplished through use of a single, bi-directional meter. If the eligible customer's existing electric revenue meter does not meet this requirement, the electricity provider shall arrange for the local electric utility or a meter service provider to install and maintain a new revenue meter at the electricity 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 declared 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 demand basis and electric supply service is not provided based on hourly pricing, this shall typically be accomplished through use of a dual channel meter capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio. If such customer's existing electric revenue meter does not meet this requirement, then the electricity provider shall arrange for the local electric utility or a meter service provider to install and maintain a new revenue meter at the electricity 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 local 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 electric utility or a meter service provider to install and maintain metering equipment capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio, typically through the use of a dual channel meter. If the eligible customer's existing electric revenue meter does not meet this requirement, then the costs of installing such equipment shall be paid for by the customer.

(d) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric service has not been declared 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 basis and electric supply service is not provided based on hourly pricing in the following manner:

(1) If the amount of electricity used by the customer during the billing period exceeds the amount of electricity produced by the customer, the electricity provider 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 customer during the billing period exceeds the amount of electricity used by the customer during that billing period, the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue 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 billing 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 period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.

(d-5) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric service has not been declared 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 basis and electric supply service is provided based on hourly pricing or time-of-use rates in the following manner:

(1) If the amount of electricity used by the customer during any hourly period or time-of-use period exceeds the amount of electricity produced by the customer, the electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer.

(2) If the amount of electricity produced by a customer during any hourly period or time-of-use period exceeds the amount of electricity used by the customer during that hourly period or time-of-use period, the energy provider shall apply a credit for the net kilowatt-hours produced in such period. The credit shall consist of an energy credit and a delivery service credit. The energy 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 net 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 service rate, excluding energy charges.

(e) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers whose electric service has not been declared 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 demand basis and electric supply service is not provided based on hourly pricing in the following manner:

(1) If the amount of electricity used by the customer during the billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e-5) of this Section. The customer shall remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer.

(2) If the amount of electricity produced by a customer during the billing period exceeds 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 credit that reflects the kilowatt-hour based charges in the customer's electric service rate to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue 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 billing 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 period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.

(e-5) An electricity provider shall provide electric service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer will remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer. Subsections (c) through (e) of this Section shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers.

(f) Notwithstanding the requirements of subsections (c) through (e-5) of this Section, an electricity provider must require dual-channel metering for customers operating eligible renewable electrical generating facilities to whom the provisions of neither 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 and the customer remains responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the gross amount of kilowatt-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 shall 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 otherwise 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 electricity provider under contracts or tariffs employing hourly or time-of-use rates, any monthly consumption of electricity shall be calculated according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer. When those same customer-generators are net generators during any discrete hourly or time-of-use period, the net kilowatt-hours produced shall be valued at the same price per kilowatt-hour as the electric service provider would charge 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 customer shall be treated as owning and having title to the renewable energy attributes, renewable energy credits, and greenhouse gas emission credits related to any electricity produced by the qualified generating unit. The electricity provider may not condition participation in a net metering program on the signing over of a customer's renewable energy credits; provided, however, this subsection (g) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth the ownership or title of the credits.

(h) Within 120 days after the effective date of this amendatory Act of the 95th General Assembly, the Commission shall establish standards for net metering and, if the Commission has not already acted on its own initiative, standards for the interconnection of eligible renewable generating equipment to the utility system. The interconnection 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 and Electronics Engineers (IEEE) Standard 1547 and the issues of (i) reasonable and fair fees and costs, (ii) clear timelines for major milestones in the interconnection process, (iii) nondiscriminatory terms of agreement, and (iv) any best practices for interconnection of distributed generation.

(h-5) Within 90 days after the effective date of this amendatory Act of the 102nd General Assembly, the Commission shall:

(1) establish an Interconnection Working Group. The working group shall include representatives from electric utilities, developers of renewable electric generating facilities, other industries that regularly apply for interconnection with the electric utilities, representatives of distributed generation customers, the Commission Staff, and such other stakeholders with a substantial interest in the topics addressed by the Interconnection Working Group. The Interconnection 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) predictability of the queue management process and enforcement of timelines;

(E) benefits and challenges associated with group studies and cost sharing;

(F) minimum requirements for application to the interconnection process and throughout the interconnection process to avoid queue clogging behavior;

(G) process and customer service for interconnecting customers adopting distributed energy resources, including energy storage;

(H) options for 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 Level 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 customer service as determined by the Interconnection Working Group.

The Commission may create subcommittees of the Interconnection Working Group to focus on specific issues of importance, as appropriate. The Interconnection Working Group shall report to the Commission on recommended improvements to interconnection rules and tariffs and policies as determined by the Interconnection Working Group at least every 6 months. Such reports shall include consensus recommendations of the Interconnection Working Group and, if applicable, additional recommendations for which 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) create or contract for an Ombudsman to resolve interconnection 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 shall not exceed $200.

(i) All electricity providers shall begin to offer net metering no later than April 1, 2008.

(j) An electricity provider shall provide net metering to eligible customers according to subsections (d), (d-5), and (e). Eligible renewable electrical generating facilities for which eligible customers registered for net metering before January 1, 2025 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 customers change electricity providers or whether the retail customer benefiting from the system changes. On and after January 1, 2025, any eligible customer that applies for net metering and previously would have qualified under subsections (d), (d-5), or (e) shall only be eligible for net metering as described in subsection (n).

(k) Each electricity provider shall maintain records and report annually to the Commission the total number of net metering customers served by the provider, as well as the type, capacity, and energy sources of the generating systems used by the net metering customers. Nothing in this Section shall limit the ability of an electricity provider to request the redaction of information deemed by the Commission to be confidential business information.

(l)(1) Notwithstanding the definition of "eligible customer" in item (ii) of subsection (b) of this Section, each electricity provider shall allow net metering as set forth in this subsection (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 102nd General Assembly:

(A) properties owned or leased by multiple customers that contribute to the operation of an eligible renewable electrical generating facility through an ownership or leasehold interest of at least 200 watts in such facility, such as a community-owned wind project, a community-owned biomass project, a community-owned solar project, or a community methane digester processing livestock waste from multiple sources, provided that the facility is also located within the utility's service territory;

(B) individual units, apartments, or properties located in a single building that are owned or leased by multiple customers and collectively served by a common eligible renewable electrical generating facility, such as an office or apartment building, a shopping center or strip mall served by photovoltaic panels on the roof; and

(C) subscriptions to community renewable generation projects, including community renewable generation projects on the customer's side of the billing meter of a host facility and partially used for the customer's own load.

In addition, the nameplate capacity of the eligible renewable electric generating facility that serves the demand of the properties, 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 renewable electrical generating facility or community renewable generation 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 person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

(2) Notwithstanding anything to the contrary, an electricity provider shall provide credits for the electricity produced by the projects described in paragraph (1) of this subsection (l). The electricity provider shall provide credits that include at least energy supply, capacity, transmission, and, if applicable, the purchased energy adjustment on the subscriber's monthly bill equal to the subscriber's share of the production of electricity from the project, as determined by paragraph (3) of this subsection (l). For customers with transmission or capacity charges not charged on a kilowatt-hour basis, the electricity provider shall prepare a reasonable approximation of the kilowatt-hour equivalent value and provide that value as a monetary credit. The electricity provider shall submit these approximation methodologies to the Commission for review, modification, and approval. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis.

(3) Notwithstanding anything to the contrary and regardless of whether a subscriber to an eligible community renewable generation project receives power and energy service from the electric utility or an alternative retail electric supplier, for projects eligible under paragraph (C) of subparagraph (1) of this subsection (l), electric utilities serving more than 200,000 customers as of January 1, 2021 shall provide the monetary credits to a subscriber's subsequent bill for the electricity produced by community renewable generation 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 the production of electricity from the project, as determined by paragraph (5) of this subsection (l). For the purposes of this subsection, "total price to compare" means the rate or rates published by the Illinois Commerce Commission for energy supply for eligible customers receiving supply service from the electric utility, and shall include energy, capacity, transmission, and the purchased energy adjustment. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis. Any applicable 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 electric 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 described 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 customers as of January 1, 2021 shall only provide the monetary credits to a subscriber's subsequent bill for the electricity produced by community renewable generation projects if the subscriber receives power and energy service from the electric utility. Alternative retail electric suppliers providing 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 monetary credits to the subscriber's subsequent bill for the electricity produced by community renewable generation projects.

(4) If requested by the owner or operator of a community renewable generating project, an electric utility serving more than 200,000 customers as of January 1, 2021 shall enter into a net crediting agreement with the owner or operator to include a subscriber's subscription fee on the subscriber's monthly electric bill and provide the subscriber with a net credit equivalent to the total bill credit value for that generation period minus the subscription fee, provided the subscription fee is structured 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 renewable generating project, and the electric utility may charge a net crediting fee to the owner or operator of a community renewable generating project that may not exceed 2% of the bill credit value. Notwithstanding anything to the contrary, 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 community renewable generating project.

(5) For the purposes of facilitating net metering, the owner or operator of the eligible renewable electrical generating facility or community renewable generation project shall be responsible for determining the amount of the credit that each customer or subscriber participating in a project under this subsection (l) is to receive in the following manner:

(A) The owner or operator shall, on a monthly basis, provide to the electric utility the kilowatthours of generation attributable to each of the utility's retail customers and subscribers participating in projects under this subsection (l) in accordance with the customer's or subscriber's share of the eligible renewable electric generating facility's or community renewable generation project's output of power and energy for such month. The owner or operator shall electronically transmit such calculations and associated documentation to the electric utility, in a format or method set forth in the applicable tariff, on a monthly basis so that the electric utility can reflect the monetary credits on customers' and subscribers' electric utility bills. The electric utility shall be permitted to revise its tariffs to implement the provisions of this amendatory Act of the 102nd General Assembly. The owner or operator shall separately provide the electric utility with the documentation detailing the calculations supporting the credit in the manner set forth in the applicable tariff.

(B) For those participating customers and subscribers who receive their energy supply from an alternative retail electric supplier, the electric utility shall remit to the applicable alternative retail electric supplier the information provided under subparagraph (A) of this paragraph (3) for such customers and subscribers in a manner set forth in such alternative retail electric supplier's net metering program, or as otherwise agreed between the utility and the alternative retail electric supplier. The alternative retail electric supplier shall then submit to the utility the amount of the charges for power and energy to be applied to such customers and subscribers, including the amount of the credit associated with net metering.

(C) A participating customer or subscriber may provide authorization as required by applicable law that directs the electric utility to submit information to the owner or operator of the eligible renewable electrical generating facility or community renewable generation project to which the customer or subscriber has an ownership or leasehold interest or a subscription. Such information shall be limited to the components of the net metering credit calculated under this subsection (l), including the bill credit rate, total kilowatthours, and total monetary credit value applied to the customer's or subscriber's bill for 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 to this Section shall file a tariff or tariffs to implement the provisions of subsection (l) of this Section, which shall, consistent with the provisions of subsection (l), describe the terms and conditions under which owners or operators of qualifying properties, units, or apartments may participate in net metering. The Commission shall approve, or approve with modification, the tariff within 120 days after the effective date of this amendatory Act of the 102nd General Assembly.

(m) Nothing in this Section shall affect the right of an electricity provider to continue to provide, or the right of a retail customer to continue to receive service pursuant to a contract for electric service between the electricity provider and the retail customer in accordance with the prices, terms, and conditions provided for in that contract. Either the electricity provider or the customer may require compliance with the prices, terms, and conditions of the contract.

(n) On and after January 1, 2025, the net metering services described in subsections (d), (d-5), and (e) of this Section shall no longer be offered, except as to those eligible renewable electrical generating facilities for which retail customers are receiving net metering service under these subsections at the time the net metering services under those subsections are no longer offered; those systems shall continue to receive net metering services described in subsections (d), (d-5), and (e) of this Section for the lifetime of the system, regardless of if those retail customers change electricity providers or whether the retail customer benefiting from the system changes. The electric utility serving more than 200,000 customers as of January 1, 2021 is responsible for ensuring the billing credits continue without lapse for the lifetime of systems, as required in subsection (o). Those retail customers that begin taking net metering service after the date that net metering services are no longer offered under such subsections shall be subject to the provisions set forth in the following paragraphs (1) through (3) of this subsection (n):

(1) An electricity provider shall charge or credit for 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 charges reflected in the customer's electric service rate supplied to 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 the monthly billing period exceeds 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 supply 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 charges" means the kilowatt-hour equivalent values for energy, capacity, transmission, and the purchased energy adjustment, if applicable. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis. The electricity provider shall continue to carry over any excess kilowatt-hour or monetary energy credits earned and apply those credits to subsequent billing periods. For customers with transmission or capacity charges not charged on a kilowatt-hour basis, the electricity provider shall prepare a reasonable approximation of the kilowatt-hour equivalent value and provide that value as a monetary credit. The electricity provider shall submit these approximation methodologies to the Commission for review, modification, and approval.

(C) (Blank).

(2) An electricity provider shall charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric supply service is provided based on hourly pricing in the following manner:

(A) If the amount of electricity used by the customer during any hourly period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to 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 period, the energy provider shall calculate an energy credit for the net kilowatt-hours produced in such period, and shall apply that credit as a monetary credit to the customer's subsequent bill. The value of the energy credit shall be calculated using the same price per kilowatt-hour as the electric service provider would charge for kilowatt-hour energy sales during that same hourly period and shall also include values for capacity and transmission. For customers with transmission or capacity charges not charged on a kilowatt-hour basis, the electricity provider shall prepare a reasonable approximation of the kilowatt-hour equivalent value and provide that value as a monetary credit. The electricity provider shall submit these approximation methodologies to the Commission for review, modification, and approval. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis.

(3) An electricity provider shall provide electric service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned or be eligible for if the customer was not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer remains responsible for the gross amount of delivery services charges, supply-related charges that are kilowatt based, and all taxes and fees related to such charges. The customer also remains responsible for all taxes and fees that would otherwise be applicable to the net amount of electricity used by the customer. Paragraphs (1) and (2) of this subsection (n) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers. Nothing in this paragraph (3) shall be interpreted to mandate that a utility that is only required to provide delivery services to a given customer must also 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 subject to this Section shall file a tariff, which shall, consistent with the provisions of this Section, propose the terms and conditions under which a customer may participate in net metering. The tariff for electric utilities serving more than 200,000 customers as of January 1, 2021 shall also provide a streamlined and transparent bill crediting system for net metering to be managed by the electric utilities. The terms and conditions shall include, but are not limited to, that an electric utility shall manage and maintain billing of net metering credits and charges regardless 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 metering applications, even if an eligible customer is served by an alternative retail electric supplier; and the utility shall forward application approval to the appropriate alternative retail electric supplier. Eligibility for net metering shall remain with the owner of the utility billing address such that, if an eligible renewable electrical generating facility changes ownership, the net metering eligibility transfers to the new owner. The electric utility serving more 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 limited to, ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if an eligible customer switches from an electric utility to alternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a valid billing address. All transfers referenced in the preceding sentence shall include transfer of all banked credits. All electric utilities serving 200,000 or fewer customers as of January 1, 2021 shall manage net metering billing for eligible customers receiving power and energy service from the electric utility to ensure full crediting occurs on electricity bills, ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if an eligible customer switches from an electric utility to alternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a valid billing address. Alternative retail electric suppliers providing power and energy service to eligible customers located within the service territory of an electric utility serving 200,000 or fewer 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 limited to, ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if an eligible customer switches from an electric utility to alternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a valid billing address.

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

(220 ILCS 5/17-500)

Sec. 17-500. Jurisdiction. Except as provided in the Electric Supplier Act, the Illinois Municipal Code, the Municipal and Cooperative Electric Utility Planning and Transparency Act, and this Article XVII, the Commission, or any other agency or subdivision thereof of the State of Illinois or any private entity shall have no jurisdiction over any electric cooperative or municipal system regardless of whether any election or elections as provided for herein have been made, and all control regarding an electric cooperative or municipal system shall be vested in the electric cooperative's board of directors or trustees or the applicable governing body of the municipal system.

(Source: P.A. 90-561, eff. 12-16-97.)

Section 60. The Eminent Domain Act is amended by changing Section 5-5-5 as follows:

(735 ILCS 30/5-5-5)

Sec. 5-5-5. Exercise of the power of eminent domain; public use; blight.

(a) In addition to all other limitations and requirements, a condemning authority may not take or damage property by the exercise of the power of eminent domain unless it is for a public use, as set forth in this Section.

(a-5) Subsections (b), (c), (d), (e), and (f) of this Section do not apply to the acquisition of property under the O'Hare Modernization Act. A condemning authority may exercise the power of eminent domain for the acquisition or damaging of property under the O'Hare Modernization Act as provided for by law in effect prior to the effective date of this Act.

(a-10) Subsections (b), (c), (d), (e), and (f) of this Section do not apply to the acquisition or damaging of property in furtherance of the goals and objectives of an existing tax increment allocation redevelopment plan. A condemning authority may exercise the power of eminent domain for the acquisition of property in furtherance of an existing tax increment allocation redevelopment plan as provided for by law in effect prior to the effective date of this Act.

As used in this subsection, "existing tax increment allocation redevelopment plan" means a redevelopment plan that was adopted under the Tax Increment Allocation Redevelopment Act (Article 11, Division 74.4 of the Illinois Municipal Code) prior to April 15, 2006 and for which property assembly costs were, before that date, included as a budget line item in the plan or described in the narrative portion of the plan as part of the redevelopment project, but does not include (i) any additional area added to the redevelopment project area on or after April 15, 2006, (ii) any subsequent extension of the completion date of a redevelopment plan beyond the estimated completion date established in that plan prior to April 15, 2006, (iii) any acquisition of property in a conservation area for which the condemnation complaint is filed more than 12 years after the effective date of this Act, or (iv) any acquisition of property in an industrial park conservation area.

As used in this subsection, "conservation area" and "industrial park conservation area" have the same meanings as under Section 11-74.4-3 of the Illinois Municipal Code.

(b) If the exercise of eminent domain authority is to acquire property for public ownership and control, then the condemning authority must prove that (i) the acquisition of the property is necessary for a public purpose and (ii) the acquired property will be owned and controlled by the condemning authority or another governmental entity.

(c) Except when the acquisition is governed by subsection (b) or is primarily for one of the purposes specified in subsection (d), (e), or (f) and the condemning authority elects to proceed under one of those subsections, if the exercise of eminent domain authority is to acquire property for private ownership or control, or both, then the condemning authority must prove by clear and convincing evidence that the acquisition of the property for private ownership or control is (i) primarily for the benefit, use, or enjoyment of the public and (ii) necessary for a public purpose.

An acquisition of property primarily for the purpose of the elimination of blight is rebuttably presumed to be for a public purpose and primarily for the benefit, use, or enjoyment of the public under this subsection.

Any challenge to the existence of blighting factors alleged in a complaint to condemn under this subsection shall be raised within 6 months of the filing date of the complaint to condemn, and if not raised within that time the right to challenge the existence of those blighting factors shall be deemed waived.

Evidence that the Illinois Commerce Commission has granted a certificate or otherwise made a finding of public convenience and necessity for an acquisition of property (or any right or interest in property) for private ownership or control (including, without limitation, an acquisition for which the use of eminent domain is authorized under the Public Utilities Act, the Telephone Company Act, or the Electric Supplier Act) to be used for utility purposes creates a rebuttable presumption that such acquisition of that property (or right or interest in property) is (i) primarily for the benefit, use, or enjoyment of the public and (ii) necessary for a public purpose.

In the case of an acquisition of property (or any right or interest in property) for private ownership or control to be used for utility, pipeline, or railroad purposes for which no certificate or finding of public convenience and necessity by the Illinois Commerce Commission is required, evidence that the acquisition is one for which the use of eminent domain is authorized under one of the following laws creates a rebuttable presumption that the acquisition of that property (or right or interest in property) is (i) primarily for the benefit, use, or enjoyment of the public and (ii) necessary for a public purpose:

(1) the Public Utilities Act,

(2) the Telephone Company Act,

(3) the Electric Supplier Act,

(4) the Railroad Terminal Authority Act,

(5) the Grand Avenue Railroad Relocation Authority Act,

(6) the West Cook Railroad Relocation and Development Authority Act,

(7) Section 4-505 of the Illinois Highway Code,

(8) Section 17 or 18 of the Railroad Incorporation Act,

(9) Section 18c-7501 of the Illinois Vehicle Code.

(d) If the exercise of eminent domain authority is to acquire property for private ownership or control and if the primary basis for the acquisition is the elimination of blight and the condemning authority elects to proceed under this subsection, then the condemning authority must: (i) prove by a preponderance of the evidence that acquisition of the property for private ownership or control is necessary for a public purpose; (ii) prove by a preponderance of the evidence that the property to be acquired is located in an area that is currently designated as a blighted area or conservation area under an applicable statute; (iii) if the existence of blight or blighting factors is challenged in an appropriate motion filed within 6 months after the date of filing of the complaint to condemn, prove by a preponderance of the evidence that the required blighting factors existed in the area so designated (but not necessarily in the particular property to be acquired) at the time of the designation under item (ii) or at any time thereafter; and (iv) prove by a preponderance of the evidence at least one of the following:

(A) that it has entered into an express written agreement in which a private person or entity agrees to undertake a development project within the blighted area that specifically details the reasons for which the property or rights in that property are necessary for the development project;

(B) that the exercise of eminent domain power and the proposed use of the property by the condemning authority are consistent with a regional plan that has been adopted within the past 5 years in accordance with Section 5-14001 of the Counties Code or Section 11-12-6 of the Illinois Municipal Code or with a local land resource management plan adopted under Section 4 of the Local Land Resource Management Planning Act; or

(C) that (1) the acquired property will be used in the development of a project that is consistent with the land uses set forth in a comprehensive redevelopment plan prepared in accordance with the applicable statute authorizing the condemning authority to exercise the power of eminent domain and is consistent with the goals and purposes of that comprehensive redevelopment plan, and (2) an enforceable written agreement, deed restriction, or similar encumbrance has been or will be executed and recorded against the acquired property to assure that the project and the use of the property remain consistent with those land uses, goals, and purposes for a period of at least 40 years, which execution and recording shall be included as a requirement in any final order entered in the condemnation proceeding.

The existence of an ordinance, resolution, or other official act designating an area as blighted is not prima facie evidence of the existence of blight. A finding by the court in a condemnation proceeding that a property or area has not been proven to be blighted does not apply to any other case or undermine the designation of a blighted area or conservation area or the determination of the existence of blight for any other purpose or under any other statute, including without limitation under the Tax Increment Allocation Redevelopment Act (Article 11, Division 74.4 of the Illinois Municipal Code).

Any challenge to the existence of blighting factors alleged in a complaint to condemn under this subsection shall be raised within 6 months of the filing date of the complaint to condemn, and if not raised within that time the right to challenge the existence of those blighting factors shall be deemed waived.

(e) If the exercise of eminent domain authority is to acquire property for private ownership or control and if the primary purpose of the acquisition is one of the purposes specified in item (iii) of this subsection and the condemning authority elects to proceed under this subsection, then the condemning authority must prove by a preponderance of the evidence that: (i) the acquisition of the property is necessary for a public purpose; (ii) an enforceable written agreement, deed restriction, or similar encumbrance has been or will be executed and recorded against the acquired property to assure that the project and the use of the property remain consistent with the applicable purpose specified in item (iii) of this subsection for a period of at least 40 years, which execution and recording shall be included as a requirement in any final order entered in the condemnation proceeding; and (iii) the acquired property will be one of the following:

(1) included in the project site for a residential project, or a mixed-use project including residential units, where not less than 20% of the residential units in the project are made available, for at least 15 years, by deed restriction, long-term lease, regulatory agreement, extended use agreement, or a comparable recorded encumbrance, to low-income households and very low-income households, as defined in Section 3 of the Illinois Affordable Housing Act;

(2) used primarily for public airport, road, parking, or mass transportation purposes and sold or leased to a private party in a sale-leaseback, lease-leaseback, or similar structured financing;

(3) owned or used by a public utility or electric cooperative for utility purposes;

(4) owned or used by a railroad for passenger or freight transportation purposes;

(5) sold or leased to a private party that operates a water supply, waste water, recycling, waste disposal, waste-to-energy, or similar facility;

(6) sold or leased to a not-for-profit corporation whose purposes include the preservation of open space, the operation of park space, and similar public purposes;

(7) used as a library, museum, or related facility, or as infrastructure related to such a facility;

(8) used by a private party for the operation of a charter school open to the general public; or

(9) a historic resource, as defined in Section 3 of the Illinois State Agency Historic Resources Preservation Act, a landmark designated as such under a local ordinance, or a contributing structure within a local landmark district listed on the National Register of Historic Places, that is being acquired for purposes of preservation or rehabilitation.

(f) If the exercise of eminent domain authority is to acquire property for public ownership and private control and if the primary purpose of the acquisition is one of the purposes specified in item (iii) of this subsection and the condemning authority elects to proceed under this subsection, then the condemning authority must prove by a preponderance of the evidence that: (i) the acquisition of the property is necessary for a public purpose; (ii) the acquired property will be owned by the condemning authority or another governmental entity; and (iii) the acquired property will be controlled by a private party that operates a business or facility related to the condemning authority's operation of a university, medical district, hospital, exposition or convention center, mass transportation facility, or airport, including, but not limited to, a medical clinic, research and development center, food or commercial concession facility, social service facility, maintenance or storage facility, cargo facility, rental car facility, bus facility, taxi facility, flight kitchen, fixed based operation, parking facility, refueling facility, water supply facility, and railroad tracks and stations.

(f-5) For all acquisitions governed by subsection (c) where the property, or any right or interest in property, is to be used for utility purposes, and where the condemning authority is an entity required to submit an integrated resource plan under the Municipal and Cooperative Electric Utility Planning and Transparency Act, the rebuttable presumption described in subsection (c) shall only apply if the most recent integrated resource plan filed by the condemning authority identified the facility or articulated a need for a facility of similar capacity and type to the facility for which the property or right or interest is sought.

(g) This Article is a limitation on the exercise of the power of eminent domain, but is not an independent grant of authority to exercise the power of eminent domain.

(Source: P.A. 94-1055, eff. 1-1-07.)

Section 99. Effective date. This Act takes effect upon becoming law.