SB3637 103RD GENERAL ASSEMBLY

LRB103 38841 CES 68978 b

103RD GENERAL ASSEMBLY
State of Illinois
2023 and 2024
SB3637

Introduced 2/9/2024, by Sen. Bill Cunningham

SYNOPSIS AS INTRODUCED:

See Index

Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2024, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2024 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.

A BILL FOR

AN ACT concerning regulation.

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

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 Congressional 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) By November 1, 2024, and by November 1 every 3 years thereafter, 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) Identify, if the preferred portfolio includes the construction of new generation or storage resources or transmission facilities, 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. Cost of Service Study.

(a) All electric cooperatives with members in this State, municipal power agencies, and municipalities with $5,000,000 or more in total retail electricity revenues shall submit to the Agency an embedded cost-of-service study on November 1, 2024 and on November 1 every 3 years thereafter.

(b) The format and contents of such study shall be consistent with those set forth in any rules or regulations by the Illinois Commerce Commission for cost-of-service studies by electric utilities subject to retail rate approval by the Commerce Commission.

Section 35. 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 40. 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 30 days prior to the meeting, except for any annual meeting, which shall be posted at least 120 days prior. 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) The postmark deadline for any ballots submitted by mail.

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

(f) Electric cooperatives shall enable their members to vote in any election for one or more directors by mail-in ballot, as follows:

(1) The electric cooperative shall affirmatively mail each of its members a ballot no later than 30 days before ballots are due. Ballots may be mailed separately and clearly marked as such or included as a bill insert.

(2) The electric cooperative shall accept ballots by mail if postmarked by the date indicated in the cooperative's written policy.

(3) The electric cooperative may allow for in-person voting in addition to mail.

(g) Electric cooperatives may establish a system for online voting in addition to a mail-in option.

(h) At least 120 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 120 but no fewer than 15 days prior to the deadline to return ballots.

(i) 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. Such a list shall be provided to a candidate no later than 15 days after requested by the candidate. The membership list must include the names, phone numbers, and addresses of all members as they appear in the electric cooperative's records.

Section 45. Conflict of interest.

(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.

(c) Notwithstanding any other law to the contrary, if an individual is a director on the board of directors of both a distribution cooperative electric association and a generation and transmission cooperative association, the director owes fiduciary duties to both associations and shall not be required to give priority to a fiduciary duty the director owes to one association over the duties the director owes to the other association.

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

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

Sec. 2. Open meetings.

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

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

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

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

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

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

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

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

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

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

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

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

(9) Student disciplinary cases.

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

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

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

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

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

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

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

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

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

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

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

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

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

(23) The operation by a municipality of a municipal utility or the operation of a municipal power agency or municipal natural gas agency when the discussion involves (i) trade secrets, (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 95. The Illinois Power Agency Act is amended by changing Sections 1-5 and 1-20 as follows:

(20 ILCS 3855/1-5)

Sec. 1-5. Legislative declarations and findings. The General Assembly finds and declares:

(1) The health, welfare, and prosperity of all Illinois residents require the provision of adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.

(1.5) To provide the highest quality of life for the residents of Illinois and to provide for a clean and healthy environment, it is the policy of this State to rapidly transition to 100% clean energy by 2050.

(2) (Blank).

(3) (Blank).

(4) It is necessary to improve the process of procuring electricity to serve Illinois residents, to promote investment in energy efficiency and demand-response measures, and to maintain and support development of clean coal technologies, generation resources that operate at all hours of the day and under all weather conditions, zero emission facilities, and renewable resources.

(5) Procuring a diverse electricity supply portfolio will ensure the lowest total cost over time for adequate, reliable, efficient, and environmentally sustainable electric service.

(6) Including renewable resources and zero emission credits from zero emission facilities in that portfolio will reduce long-term direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. Developing new renewable energy resources in Illinois, including brownfield solar projects and community solar projects, will help to diversify Illinois electricity supply, avoid and reduce pollution, reduce peak demand, and enhance public health and well-being of Illinois residents.

(7) Developing community solar projects in Illinois will help to expand access to renewable energy resources to more Illinois residents.

(8) Developing brownfield solar projects in Illinois will help return blighted or contaminated land to productive use while enhancing public health and the well-being of Illinois residents, including those in environmental justice communities.

(9) Energy efficiency, demand-response measures, zero emission energy, and renewable energy are resources currently underused in Illinois. These resources should be used, when cost effective, to reduce costs to consumers, improve reliability, and improve environmental quality and public health.

(10) The State should encourage the use of advanced clean coal technologies that capture and sequester carbon dioxide emissions to advance environmental protection goals and to demonstrate the viability of coal and coal-derived fuels in a carbon-constrained economy.

(10.5) The State should encourage the development of interregional high voltage direct current (HVDC) transmission lines that benefit Illinois. All ratepayers in the State served by the regional transmission organization where the HVDC converter station is interconnected benefit from the long-term price stability and market access provided by interregional HVDC transmission facilities. The benefits to Illinois include: reduction in wholesale power prices; access to lower-cost markets; enabling the integration of additional renewable generating units within the State through near instantaneous dispatchability and the provision of ancillary services; creating good-paying union jobs in Illinois; and, enhancing grid reliability and climate resilience via HVDC facilities that are installed underground.

(10.6) The health, welfare, and safety of the people of the State are advanced by developing new HVDC transmission lines predominantly along transportation rights-of-way, with an HVDC converter station that is located in the service territory of a public utility as defined in Section 3-105 of the Public Utilities Act serving more than 3,000,000 retail customers, and with a project labor agreement as defined in Section 1-10 of this Act.

(11) The General Assembly enacted Public Act 96-0795 to reform the State's purchasing processes, recognizing that government procurement is susceptible to abuse if structural and procedural safeguards are not in place to ensure independence, insulation, oversight, and transparency.

(12) The principles that underlie the procurement reform legislation apply also in the context of power purchasing.

(13) To ensure that the benefits of installing renewable resources are available to all Illinois residents and located across the State, subject to appropriation, it is necessary for the Agency to provide public information and educational resources on how residents can benefit from the expansion of renewable energy in Illinois and participate in the Illinois Solar for All Program established in Section 1-56, the Adjustable Block program established in Section 1-75, the job training programs established by paragraph (1) of subsection (a) of Section 16-108.12 of the Public Utilities Act, and the programs and resources established by the Energy Transition Act.

(14) To ensure the State's clean energy goals are timely met and that reliable clean energy is produced and available when customers need it, the Agency should begin to procure clean power and encourage storage, including through long-term contracts. Where the comparison shows that clean products can be procured at or near the cost of non-renewable products, the clean products should be procured. This requirement will limit the State's dependence on fossil generation and reduce the potential need to import fossil-fueled power.

The General Assembly therefore finds that it is necessary to create the Illinois Power Agency and that the goals and objectives of that Agency are to accomplish each of the following:

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

(B) Conduct the competitive procurement processes identified in this Act.

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

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

(E) Ensure that the process of power procurement is conducted in an ethical and transparent fashion, immune from improper influence.

(F) Continue to review its policies and practices to determine how best to meet its mission of providing the lowest cost power to the greatest number of people, at any given point in time, in accordance with applicable law.

(G) Operate in a structurally insulated, independent, and transparent fashion so that nothing impedes the Agency's mission to secure power at the best prices the market will bear, provided that the Agency meets all applicable legal requirements.

(H) Implement renewable energy procurement and training programs throughout the State to diversify Illinois electricity supply, improve reliability, avoid and reduce pollution, reduce peak demand, and enhance public health and well-being of Illinois residents, including low-income residents.

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

(20 ILCS 3855/1-20)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(21) To accept and expend appropriations.

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

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

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

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

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

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

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

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

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

Section 100. 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 105. The Public Utilities Act is amended by changing Sections 3-105, 8-103B, 16-107.5, 16-111.5, 16-115A, 16-115D, and 17-500 and by adding Section 16-107.8 as follows:

(220 ILCS 5/3-105) (from Ch. 111 2/3, par. 3-105)

Sec. 3-105. Public utility.

(a) "Public utility" means and includes, except where otherwise expressly provided in this Section, every corporation, company, limited liability company, association, joint stock company or association, firm, partnership or individual, their lessees, trustees, or receivers appointed by any court whatsoever now or hereafter that owns, controls, operates or manages, within this State, directly or indirectly, for public use, any plant, equipment or property used or to be used for or in connection with, or owns or controls or seeks Commission approval to own or control any franchise, license, permit or right to engage in:

(1) the production, storage, transmission, sale, delivery or furnishing of heat, cold, power, electricity, water, or light, except when used solely for communications purposes;

(2) the disposal of sewerage; or

(3) the conveyance of oil or gas by pipe line.

(b) "Public utility" does not include, however:

(1) public utilities that are owned and operated by any political subdivision, public institution of higher education or municipal corporation of this State, or public utilities that are owned by such political subdivision, public institution of higher education, or municipal corporation and operated by any of its lessees or operating agents;

(2) water companies which are purely mutual concerns, having no rates or charges for services, but paying the operating expenses by assessment upon the members of such a company and no other person;

(3) electric cooperatives as defined in Section 3-119;

(4) the following natural gas cooperatives:

(A) residential natural gas cooperatives that are not-for-profit corporations established for the purpose of administering and operating, on a cooperative basis, the furnishing of natural gas to residences for the benefit of their members who are residential consumers of natural gas. For entities qualifying as residential natural gas cooperatives and recognized by the Illinois Commerce Commission as such, the State shall guarantee legally binding contracts entered into by residential natural gas cooperatives for the express purpose of acquiring natural gas supplies for their members. The Illinois Commerce Commission shall establish rules and regulations providing for such guarantees. The total liability of the State in providing all such guarantees shall not at any time exceed $1,000,000, nor shall the State provide such a guarantee to a residential natural gas cooperative for more than 3 consecutive years; and

(B) natural gas cooperatives that are not-for-profit corporations operated for the purpose of administering, on a cooperative basis, the furnishing of natural gas for the benefit of their members and that, prior to 90 days after the effective date of this amendatory Act of the 94th General Assembly, either had acquired or had entered into an asset purchase agreement to acquire all or substantially all of the operating assets of a public utility or natural gas cooperative with the intention of operating those assets as a natural gas cooperative;

(5) sewage disposal companies which provide sewage disposal services on a mutual basis without establishing rates or charges for services, but paying the operating expenses by assessment upon the members of the company and no others;

(6) (blank);

(7) cogeneration facilities, small power production facilities, and other qualifying facilities, as defined in the Public Utility Regulatory Policies Act and regulations promulgated thereunder, except to the extent State regulatory jurisdiction and action is required or authorized by federal law, regulations, regulatory decisions or the decisions of federal or State courts of competent jurisdiction;

(8) the ownership or operation of a facility that sells compressed natural gas at retail to the public for use only as a motor vehicle fuel and the selling of compressed natural gas at retail to the public for use only as a motor vehicle fuel;

(9) alternative retail electric suppliers as defined in Article XVI; and

(10) the Illinois Power Agency.

(c) An entity that furnishes the service of charging electric vehicles does not and shall not be deemed to sell electricity and is not and shall not be deemed a public utility notwithstanding the basis on which the service is provided or billed. If, however, the entity is otherwise deemed a public utility under this Act, or is otherwise subject to regulation under this Act, then that entity is not exempt from and remains subject to the otherwise applicable provisions of this Act. The installation, maintenance, and repair of an electric vehicle charging station shall comply with the requirements of subsection (a) of Section 16-128 and Section 16-128A of this Act.

For purposes of this subsection, the term "electric vehicles" has the meaning ascribed to that term in Section 10 of the Electric Vehicle Act.

(Source: P.A. 97-1128, eff. 8-28-12.)

(220 ILCS 5/8-103B)

Sec. 8-103B. Energy efficiency and demand-response measures.

(a) It is the policy of the State that electric utilities are required to use cost-effective energy efficiency and demand-response measures to reduce delivery load. Requiring investment in cost-effective energy efficiency and demand-response measures will reduce direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. It serves the public interest to allow electric utilities to recover costs for reasonably and prudently incurred expenditures for energy efficiency and demand-response measures. As used in this Section, "cost-effective" means that the measures satisfy the total resource cost test. The low-income measures described in subsection (c) of this Section shall not be required to meet the total resource cost test. For purposes of this Section, the terms "energy-efficiency", "demand-response", "electric utility", and "total resource cost test" have the meanings set forth in the Illinois Power Agency Act. "Black, indigenous, and people of color" and "BIPOC" means people who are members of the groups described in subparagraphs (a) through (e) of paragraph (A) of subsection (1) of Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act.

(a-5) This Section applies to electric utilities serving more than 500,000 retail customers in the State for those multi-year plans commencing after December 31, 2017.

(b) For purposes of this Section, through calendar year 2025, electric utilities subject to this Section that serve more than 3,000,000 retail customers in the State shall be deemed to have achieved a cumulative persisting annual savings of 6.6% from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and ending December 31, 2017, which percent is based on the deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs. For the purposes of this subsection (b) and subsection (b-5), the 88,000,000 MWhs of deemed electric power and energy sales shall be reduced by the number of MWhs equal to the sum of the annual consumption of customers that have opted out of subsections (a) through (j) of this Section under paragraph (1) of subsection (l) of this Section, as averaged across the calendar years 2014, 2015, and 2016. After 2017, the deemed value of cumulative persisting annual savings from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and ending December 31, 2017, shall be reduced each year, as follows, and the applicable value shall be applied to and count toward the utility's achievement of the cumulative persisting annual savings goals set forth in subsection (b-5):

(1) 5.8% deemed cumulative persisting annual savings for the year ending December 31, 2018;

(2) 5.2% deemed cumulative persisting annual savings for the year ending December 31, 2019;

(3) 4.5% deemed cumulative persisting annual savings for the year ending December 31, 2020;

(4) 4.0% deemed cumulative persisting annual savings for the year ending December 31, 2021;

(5) 3.5% deemed cumulative persisting annual savings for the year ending December 31, 2022;

(6) 3.1% deemed cumulative persisting annual savings for the year ending December 31, 2023;

(7) 2.8% deemed cumulative persisting annual savings for the year ending December 31, 2024; and

(8) 2.5% deemed cumulative persisting annual savings for the year ending December 31, 2025. ;

(9) 2.3% deemed cumulative persisting annual savings for the year ending December 31, 2026;

(10) 2.1% deemed cumulative persisting annual savings for the year ending December 31, 2027;

(11) 1.8% deemed cumulative persisting annual savings for the year ending December 31, 2028;

(12) 1.7% deemed cumulative persisting annual savings for the year ending December 31, 2029;

(13) 1.5% deemed cumulative persisting annual savings for the year ending December 31, 2030;

(14) 1.3% deemed cumulative persisting annual savings for the year ending December 31, 2031;

(15) 1.1% deemed cumulative persisting annual savings for the year ending December 31, 2032;

(16) 0.9% deemed cumulative persisting annual savings for the year ending December 31, 2033;

(17) 0.7% deemed cumulative persisting annual savings for the year ending December 31, 2034;

(18) 0.5% deemed cumulative persisting annual savings for the year ending December 31, 2035;

(19) 0.4% deemed cumulative persisting annual savings for the year ending December 31, 2036;

(20) 0.3% deemed cumulative persisting annual savings for the year ending December 31, 2037;

(21) 0.2% deemed cumulative persisting annual savings for the year ending December 31, 2038;

(22) 0.1% deemed cumulative persisting annual savings for the year ending December 31, 2039; and

(23) 0.0% deemed cumulative persisting annual savings for the year ending December 31, 2040 and all subsequent years.

For purposes of this Section, "cumulative persisting annual savings" means the total electric energy savings in a given year from measures installed in that year or in previous years, but no earlier than January 1, 2012, that are still operational and providing savings in that year because the measures have not yet reached the end of their useful lives.

(b-5) Beginning in 2018, through calendar year 2025, electric utilities subject to this Section that serve more than 3,000,000 retail customers in the State shall achieve the following cumulative persisting annual savings goals, as modified by subsection (f) of this Section and as compared to the deemed baseline of 88,000,000 MWhs of electric power and energy sales set forth in subsection (b), as reduced by the number of MWhs equal to the sum of the annual consumption of customers that have opted out of subsections (a) through (j) of this Section under paragraph (1) of subsection (l) of this Section as averaged across the calendar years 2014, 2015, and 2016, through the implementation of energy efficiency measures during the applicable year and in prior years, but no earlier than January 1, 2012:

(1) 7.8% cumulative persisting annual savings for the year ending December 31, 2018;

(2) 9.1% cumulative persisting annual savings for the year ending December 31, 2019;

(3) 10.4% cumulative persisting annual savings for the year ending December 31, 2020;

(4) 11.8% cumulative persisting annual savings for the year ending December 31, 2021;

(5) 13.1% cumulative persisting annual savings for the year ending December 31, 2022;

(6) 14.4% cumulative persisting annual savings for the year ending December 31, 2023;

(7) 15.7% cumulative persisting annual savings for the year ending December 31, 2024; and

(8) 17% cumulative persisting annual savings for the year ending December 31, 2025. ;

(9) 17.9% cumulative persisting annual savings for the year ending December 31, 2026;

(10) 18.8% cumulative persisting annual savings for the year ending December 31, 2027;

(11) 19.7% cumulative persisting annual savings for the year ending December 31, 2028;

(12) 20.6% cumulative persisting annual savings for the year ending December 31, 2029; and

(13) 21.5% cumulative persisting annual savings for the year ending December 31, 2030.

No later than December 31, 2021, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2031 through 2035. No later than December 31, 2024, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2036 through 2040. The Commission shall also establish additional cumulative persisting annual savings goals every 5 years thereafter to ensure that utilities always have goals that extend at least 11 years into the future. The cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 percentage points per year, absent a Commission decision to initiate a proceeding to consider establishing goals that increase by more or less than that amount. Such a proceeding must be conducted in accordance with the procedures described in subsection (f) of this Section. If such a proceeding is initiated, the cumulative persisting annual savings goals established by the Commission through that proceeding shall reflect the Commission's best estimate of the maximum amount of additional savings that are forecast to be cost-effectively achievable unless such best estimates would result in goals that represent less than 0.5 percentage point annual increases in total cumulative persisting annual savings. The Commission may only establish goals that represent less than 0.5 percentage point annual increases in cumulative persisting annual savings if it can demonstrate, based on clear and convincing evidence and through independent analysis, that 0.5 percentage point increases are not cost-effectively achievable. The Commission shall inform its decision based on an energy efficiency potential study that conforms to the requirements of this Section.

(b-10) For purposes of this Section, through calendar year 2025, electric utilities subject to this Section that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall be deemed to have achieved a cumulative persisting annual savings of 6.6% from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and ending December 31, 2017, which is based on the deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs. For the purposes of this subsection (b-10) and subsection (b-15), the 36,900,000 MWhs of deemed electric power and energy sales shall be reduced by the number of MWhs equal to the sum of the annual consumption of customers that have opted out of subsections (a) through (j) of this Section under paragraph (1) of subsection (l) of this Section, as averaged across the calendar years 2014, 2015, and 2016. After 2017, the deemed value of cumulative persisting annual savings from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and ending December 31, 2017, shall be reduced each year, as follows, and the applicable value shall be applied to and count toward the utility's achievement of the cumulative persisting annual savings goals set forth in subsection (b-15):

(1) 5.8% deemed cumulative persisting annual savings for the year ending December 31, 2018;

(2) 5.2% deemed cumulative persisting annual savings for the year ending December 31, 2019;

(3) 4.5% deemed cumulative persisting annual savings for the year ending December 31, 2020;

(4) 4.0% deemed cumulative persisting annual savings for the year ending December 31, 2021;

(5) 3.5% deemed cumulative persisting annual savings for the year ending December 31, 2022;

(6) 3.1% deemed cumulative persisting annual savings for the year ending December 31, 2023;

(7) 2.8% deemed cumulative persisting annual savings for the year ending December 31, 2024; and

(8) 2.5% deemed cumulative persisting annual savings for the year ending December 31, 2025. ;

(9) 2.3% deemed cumulative persisting annual savings for the year ending December 31, 2026;

(10) 2.1% deemed cumulative persisting annual savings for the year ending December 31, 2027;

(11) 1.8% deemed cumulative persisting annual savings for the year ending December 31, 2028;

(12) 1.7% deemed cumulative persisting annual savings for the year ending December 31, 2029;

(13) 1.5% deemed cumulative persisting annual savings for the year ending December 31, 2030;

(14) 1.3% deemed cumulative persisting annual savings for the year ending December 31, 2031;

(15) 1.1% deemed cumulative persisting annual savings for the year ending December 31, 2032;

(16) 0.9% deemed cumulative persisting annual savings for the year ending December 31, 2033;

(17) 0.7% deemed cumulative persisting annual savings for the year ending December 31, 2034;

(18) 0.5% deemed cumulative persisting annual savings for the year ending December 31, 2035;

(19) 0.4% deemed cumulative persisting annual savings for the year ending December 31, 2036;

(20) 0.3% deemed cumulative persisting annual savings for the year ending December 31, 2037;

(21) 0.2% deemed cumulative persisting annual savings for the year ending December 31, 2038;

(22) 0.1% deemed cumulative persisting annual savings for the year ending December 31, 2039; and

(23) 0.0% deemed cumulative persisting annual savings for the year ending December 31, 2040 and all subsequent years.

(b-15) Beginning in 2018, electric utilities subject to this Section that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall achieve the following cumulative persisting annual savings goals, as modified by subsection (b-20) and subsection (f) of this Section and as compared to the deemed baseline as reduced by the number of MWhs equal to the sum of the annual consumption of customers that have opted out of subsections (a) through (j) of this Section under paragraph (1) of subsection (l) of this Section as averaged across the calendar years 2014, 2015, and 2016, through the implementation of energy efficiency measures during the applicable year and in prior years, but no earlier than January 1, 2012:

(1) 7.4% cumulative persisting annual savings for the year ending December 31, 2018;

(2) 8.2% cumulative persisting annual savings for the year ending December 31, 2019;

(3) 9.0% cumulative persisting annual savings for the year ending December 31, 2020;

(4) 9.8% cumulative persisting annual savings for the year ending December 31, 2021;

(5) 10.6% cumulative persisting annual savings for the year ending December 31, 2022;

(6) 11.4% cumulative persisting annual savings for the year ending December 31, 2023;

(7) 12.2% cumulative persisting annual savings for the year ending December 31, 2024;

(8) 13% cumulative persisting annual savings for the year ending December 31, 2025;

(9) 13.6% cumulative persisting annual savings for the year ending December 31, 2026;

(10) 14.2% cumulative persisting annual savings for the year ending December 31, 2027;

(11) 14.8% cumulative persisting annual savings for the year ending December 31, 2028;

(12) 15.4% cumulative persisting annual savings for the year ending December 31, 2029; and

(13) 16% cumulative persisting annual savings for the year ending December 31, 2030.

No later than December 31, 2021, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2031 through 2035. No later than December 31, 2024, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2036 through 2040. The Commission shall also establish additional cumulative persisting annual savings goals every 5 years thereafter to ensure that utilities always have goals that extend at least 11 years into the future. The cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 0.6 percentage points per year, absent a Commission decision to initiate a proceeding to consider establishing goals that increase by more or less than that amount. Such a proceeding must be conducted in accordance with the procedures described in subsection (f) of this Section. If such a proceeding is initiated, the cumulative persisting annual savings goals established by the Commission through that proceeding shall reflect the Commission's best estimate of the maximum amount of additional savings that are forecast to be cost-effectively achievable unless such best estimates would result in goals that represent less than 0.5 0.4 percentage point annual increases in total cumulative persisting annual savings. The Commission may only establish goals that represent less than 0.5 0.4 percentage point annual increases in cumulative persisting annual savings if it can demonstrate, based on clear and convincing evidence and through independent analysis, that 0.5 0.4 percentage point increases are not cost-effectively achievable. The Commission shall inform its decision based on an energy efficiency potential study that conforms to the requirements of this Section.

(b-16) Beginning in 2026, and in every subsequent year, each electric utility subject to this Section shall achieve incremental annual savings equal to 2.25% of the utility's average annual electricity sales in the second, third, and fourth years prior to the start of each applicable multi-year energy efficiency planning period referenced in subsection (f), with an average savings life of at least 13 years. For the purposes of this Section, "incremental annual savings" means the total electric savings from all measures installed in a calendar year that will be realized within 12 months of each measure's installation. In no event can more than one-fifth of the incremental annual savings counted towards a utility's annual savings goal in any given year be derived from efficiency measures with average savings lives of less than 5 years.

(b-20) Each electric utility subject to this Section may include cost-effective voltage optimization measures in its plans submitted under subsections (f) and (g) of this Section, and the costs incurred by a utility to implement the measures under a Commission-approved plan shall be recovered under the provisions of Article IX or Section 16-108.5 of this Act. For purposes of this Section, the measure life of voltage optimization measures shall be 15 years. The measure life period is independent of the depreciation rate of the voltage optimization assets deployed. Utilities may claim savings from voltage optimization on circuits for more than 15 years if they can demonstrate that they have made additional investments necessary to enable voltage optimization savings to continue beyond 15 years. Such demonstrations must be subject to the review of independent evaluation.

Within 270 days after June 1, 2017 (the effective date of Public Act 99-906), an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall file a plan with the Commission that identifies the cost-effective voltage optimization investment the electric utility plans to undertake through December 31, 2024. The Commission, after notice and hearing, shall approve or approve with modification the plan within 120 days after the plan's filing and, in the order approving or approving with modification the plan, the Commission shall adjust the applicable cumulative persisting annual savings goals set forth in subsection (b-15) to reflect any amount of cost-effective energy savings approved by the Commission that is greater than or less than the following cumulative persisting annual savings values attributable to voltage optimization for the applicable year:

(1) 0.0% of cumulative persisting annual savings for the year ending December 31, 2018;

(2) 0.17% of cumulative persisting annual savings for the year ending December 31, 2019;

(3) 0.17% of cumulative persisting annual savings for the year ending December 31, 2020;

(4) 0.33% of cumulative persisting annual savings for the year ending December 31, 2021;

(5) 0.5% of cumulative persisting annual savings for the year ending December 31, 2022;

(6) 0.67% of cumulative persisting annual savings for the year ending December 31, 2023;

(7) 0.83% of cumulative persisting annual savings for the year ending December 31, 2024; and

(8) 1.0% of cumulative persisting annual savings for the year ending December 31, 2025 and all subsequent years.

(b-25) In the event an electric utility jointly offers an energy efficiency measure or program with a gas utility under plans approved under this Section and Section 8-104 of this Act, the electric utility may continue offering the program, including the gas energy efficiency measures, in the event the gas utility discontinues funding the program. In that event, the energy savings value associated with such other fuels shall be converted to electric energy savings on an equivalent Btu basis for the premises. However, the electric utility shall prioritize programs for low-income residential customers to the extent practicable. An electric utility may recover the costs of offering the gas energy efficiency measures under this subsection (b-25).

For those energy efficiency measures or programs that save both electricity and other fuels but are not jointly offered with a gas utility under plans approved under this Section and Section 8-104 or not offered with an affiliated gas utility under paragraph (6) of subsection (f) of Section 8-104 of this Act, the electric utility may count savings of fuels other than electricity toward the achievement of its annual savings goal, and the energy savings value associated with such other fuels shall be converted to electric energy savings on an equivalent Btu basis at the premises.

In no event shall more than 10% of each year's applicable annual total savings requirement as defined in paragraph (7.5) of subsection (g) of this Section, or more than 10% of each year's incremental annual savings as defined in subsection (b-16) be met through savings of fuels other than electricity.

(b-27) Beginning in 2022, an electric utility may offer and promote measures that electrify space heating, water heating, cooling, drying, cooking, industrial processes, and other building and industrial end uses that would otherwise be served by combustion of fossil fuel at the premises, provided that the electrification measures reduce total energy consumption at the premises. The electric utility may count the reduction in energy consumption at the premises toward achievement of its annual savings goals. The reduction in energy consumption at the premises shall be calculated as the difference between: (A) the reduction in Btu consumption of fossil fuels as a result of electrification, converted to kilowatt-hour equivalents by dividing by 3,412 Btus per kilowatt hour; and (B) the increase in kilowatt hours of electricity consumption resulting from the displacement of fossil fuel consumption as a result of electrification. An electric utility may recover the costs of offering and promoting electrification measures under this subsection (b-27). At least 40% of all such costs must be for supporting installation of electrification measures in low income housing.

In no event shall electrification savings counted toward each year's applicable annual total savings requirement, as defined in paragraph (7.5) of subsection (g) of this Section, be greater than:

(1) 5% per year for each year from 2022 through 2025;

(2) 10% per year for each year from 2026 through 2029; and

(3) 15% per year for 2030 and all subsequent years. In addition, a minimum of 25% of all electrification savings counted toward a utility's applicable annual total savings requirement must be from electrification of end uses in low-income housing. The limitations on electrification savings that may be counted toward a utility's annual savings goals are separate from and in addition to the subsection (b-25) limitations governing the counting of the other fuel savings resulting from efficiency measures and programs.

As part of the annual informational filing to the Commission that is required under paragraph (9) of subsection (g) of this Section, each utility shall identify the specific electrification measures offered under this subsection (b-27); the quantity of each electrification measure that was installed by its customers; the average total cost, average utility cost, average reduction in fossil fuel consumption, and average increase in electricity consumption associated with each electrification measure; the portion of installations of each electrification measure that were in low-income single-family housing, low-income multifamily housing, non-low-income single-family housing, non-low-income multifamily housing, commercial buildings, and industrial facilities; and the quantity of savings associated with each measure category in each customer category that are being counted toward the utility's applicable annual total savings requirement or the utility's incremental annual savings as defined in subsection (b-16). Prior to installing an electrification measure, the utility shall provide a customer with an estimate of the impact of the new measure on the customer's average monthly electric bill and total annual energy expenses.

(c) Electric utilities shall be responsible for overseeing the design, development, and filing of energy efficiency plans with the Commission and may, as part of that implementation, outsource various aspects of program development and implementation. A minimum of 10%, for electric utilities that serve more than 3,000,000 retail customers in the State, and a minimum of 7%, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, of the utility's entire portfolio funding level for a given year shall be used to procure cost-effective energy efficiency measures from units of local government, municipal corporations, school districts, public housing, and community college districts, provided that a minimum percentage of available funds shall be used to procure energy efficiency from public housing, which percentage shall be equal to public housing's share of public building energy consumption.

The utilities shall also implement energy efficiency measures targeted at low-income households, which, for purposes of this Section, shall be defined as households at or below 80% of area median income, and expenditures to implement the measures shall be no less than $1,000,000 $40,000,000 per year for electric utilities that serve more than 3,000,000 retail customers in the State and no less than $30,000 $13,000,000 per year for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State. The ratio of spending on efficiency programs targeted at low-income multifamily buildings to spending on efficiency programs targeted at low-income single-family buildings shall be designed to achieve levels of savings from each building type that are approximately proportional to the magnitude of cost-effective lifetime savings potential in each building type. Investment in low-income whole-building weatherization programs shall constitute a minimum of 80% of a utility's total budget specifically dedicated to serving low-income customers.

The utilities shall work to bundle low-income energy efficiency offerings with other programs that serve low-income households to maximize the benefits going to these households. The utilities shall market and implement low-income energy efficiency programs in coordination with low-income assistance programs, the Illinois Solar for All Program, and weatherization whenever practicable. The program implementer shall walk the customer through the enrollment process for any programs for which the customer is eligible. The utilities shall also pilot targeting customers with high arrearages, high energy intensity (ratio of energy usage divided by home or unit square footage), or energy assistance programs with energy efficiency offerings, and then track reduction in arrearages as a result of the targeting. This targeting and bundling of low-income energy programs shall be offered to both low-income single-family and multifamily customers (owners and residents).

The utilities shall invest in health and safety measures appropriate and necessary for comprehensively weatherizing a home or multifamily building, and shall implement a health and safety fund of at least 15% of the total income-qualified weatherization budget that shall be used for the purpose of making grants for technical assistance, construction, reconstruction, improvement, or repair of buildings to facilitate their participation in the energy efficiency programs targeted at low-income single-family and multifamily households. These funds may also be used for the purpose of making grants for technical assistance, construction, reconstruction, improvement, or repair of the following buildings to facilitate their participation in the energy efficiency programs created by this Section: (1) buildings that are owned or operated by registered 501(c)(3) public charities; and (2) day care centers, day care homes, or group day care homes, as defined under 89 Ill. Adm. Code Part 406, 407, or 408, respectively.

Each electric utility shall assess opportunities to implement cost-effective energy efficiency measures and programs through a public housing authority or authorities located in its service territory. If such opportunities are identified, the utility shall propose such measures and programs to address the opportunities. Expenditures to address such opportunities shall be credited toward the minimum procurement and expenditure requirements set forth in this subsection (c).

Implementation of energy efficiency measures and programs targeted at low-income households should be contracted, when it is practicable, to independent third parties that have demonstrated capabilities to serve such households, with a preference for not-for-profit entities and government agencies that have existing relationships with or experience serving low-income communities in the State.

Each electric utility shall develop and implement reporting procedures that address and assist in determining the amount of energy savings that can be applied to the low-income procurement and expenditure requirements set forth in this subsection (c). Each electric utility shall also track the types and quantities or volumes of insulation and air sealing materials, and their associated energy saving benefits, installed in energy efficiency programs targeted at low-income single-family and multifamily households.

The electric utilities shall participate in a low-income energy efficiency accountability committee ("the committee"), which will directly inform the design, implementation, and evaluation of the low-income and public-housing energy efficiency programs. The committee shall be comprised of the electric utilities subject to the requirements of this Section, the gas utilities subject to the requirements of Section 8-104 of this Act, the utilities' low-income energy efficiency implementation contractors, nonprofit organizations, community action agencies, advocacy groups, State and local governmental agencies, public-housing organizations, and representatives of community-based organizations, especially those living in or working with environmental justice communities and BIPOC communities. The committee shall be composed of 2 geographically differentiated subcommittees: one for stakeholders in northern Illinois and one for stakeholders in central and southern Illinois. The subcommittees shall meet together at least twice per year.

There shall be one statewide leadership committee led by and composed of community-based organizations that are representative of BIPOC and environmental justice communities and that includes equitable representation from BIPOC communities. The leadership committee shall be composed of an equal number of representatives from the 2 subcommittees. The subcommittees shall address specific programs and issues, with the leadership committee convening targeted workgroups as needed. The leadership committee may elect to work with an independent facilitator to solicit and organize feedback, recommendations and meeting participation from a wide variety of community-based stakeholders. If a facilitator is used, they shall be fair and responsive to the needs of all stakeholders involved in the committee.

All committee meetings must be accessible, with rotating locations if meetings are held in-person, virtual participation options, and materials and agendas circulated in advance.

There shall also be opportunities for direct input by committee members outside of committee meetings, such as via individual meetings, surveys, emails and calls, to ensure robust participation by stakeholders with limited capacity and ability to attend committee meetings. Committee meetings shall emphasize opportunities to bundle and coordinate delivery of low-income energy efficiency with other programs that serve low-income communities, such as the Illinois Solar for All Program and bill payment assistance programs. Meetings shall include educational opportunities for stakeholders to learn more about these additional offerings, and the committee shall assist in figuring out the best methods for coordinated delivery and implementation of offerings when serving low-income communities. The committee shall directly and equitably influence and inform utility low-income and public-housing energy efficiency programs and priorities. Participating utilities shall implement recommendations from the committee whenever possible.

Participating utilities shall track and report how input from the committee has led to new approaches and changes in their energy efficiency portfolios. This reporting shall occur at committee meetings and in quarterly energy efficiency reports to the Stakeholder Advisory Group and Illinois Commerce Commission, and other relevant reporting mechanisms. Participating utilities shall also report on relevant equity data and metrics requested by the committee, such as energy burden data, geographic, racial, and other relevant demographic data on where programs are being delivered and what populations programs are serving.

The Illinois Commerce Commission shall oversee and have relevant staff participate in the committee. The committee shall have a budget of 0.25% of each utility's entire efficiency portfolio funding for a given year. The budget shall be overseen by the Commission. The budget shall be used to provide grants for community-based organizations serving on the leadership committee, stipends for community-based organizations participating in the committee, grants for community-based organizations to do energy efficiency outreach and education, and relevant meeting needs as determined by the leadership committee. The education and outreach shall include, but is not limited to, basic energy efficiency education, information about low-income energy efficiency programs, and information on the committee's purpose, structure, and activities.

(d) Notwithstanding any other provision of law to the contrary, a utility providing approved energy efficiency measures and, if applicable, demand-response measures in the State shall be permitted to recover all reasonable and prudently incurred costs of those measures from all retail customers, except as provided in subsection (l) of this Section, as follows, provided that nothing in this subsection (d) permits the double recovery of such costs from customers:

(1) The utility may recover its costs through an automatic adjustment clause tariff filed with and approved by the Commission. The tariff shall be established outside the context of a general rate case. Each year the Commission shall initiate a review to reconcile any amounts collected with the actual costs and to determine the required adjustment to the annual tariff factor to match annual expenditures. To enable the financing of the incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, the utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% of the total capital structure shall be deemed reasonable and used to set rates.

(2) A utility may recover its costs through an energy efficiency formula rate approved by the Commission under a filing under subsections (f) and (g) of this Section, which shall specify the cost components that form the basis of the rate charged to customers with sufficient specificity to operate in a standardized manner and be updated annually with transparent information that reflects the utility's actual costs to be recovered during the applicable rate year, which is the period beginning with the first billing day of January and extending through the last billing day of the following December. The energy efficiency formula rate shall be implemented through a tariff filed with the Commission under subsections (f) and (g) of this Section that is consistent with the provisions of this paragraph (2) and that shall be applicable to all delivery services customers. The Commission shall conduct an investigation of the tariff in a manner consistent with the provisions of this paragraph (2), subsections (f) and (g) of this Section, and the provisions of Article IX of this Act to the extent they do not conflict with this paragraph (2). The energy efficiency formula rate approved by the Commission shall remain in effect at the discretion of the utility and shall do the following:

(A) Provide for the recovery of the utility's actual costs incurred under this Section that are prudently incurred and reasonable in amount consistent with Commission practice and law. The sole fact that a cost differs from that incurred in a prior calendar year or that an investment is different from that made in a prior calendar year shall not imply the imprudence or unreasonableness of that cost or investment.

(B) Reflect the utility's actual year-end capital structure for the applicable calendar year, excluding goodwill, subject to a determination of prudence and reasonableness consistent with Commission practice and law. To enable the financing of the incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, a participating electric utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% of the total capital structure shall be deemed reasonable and used to set rates.

(C) Include a cost of equity, which shall be calculated as the sum of the following:

(i) the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and

(ii) 580 basis points.

At such time as the Board of Governors of the Federal Reserve System ceases to include the monthly average yields of 30-year U.S. Treasury bonds in its weekly H.15 Statistical Release or successor publication, the monthly average yields of the U.S. Treasury bonds then having the longest duration published by the Board of Governors in its weekly H.15 Statistical Release or successor publication shall instead be used for purposes of this paragraph (2).

(D) Permit and set forth protocols, subject to a determination of prudence and reasonableness consistent with Commission practice and law, for the following:

(i) recovery of incentive compensation expense that is based on the achievement of operational metrics, including metrics related to budget controls, outage duration and frequency, safety, customer service, efficiency and productivity, and environmental compliance; however, this protocol shall not apply if such expense related to costs incurred under this Section is recovered under Article IX or Section 16-108.5 of this Act; incentive compensation expense that is based on net income or an affiliate's earnings per share shall not be recoverable under the energy efficiency formula rate;

(ii) recovery of pension and other post-employment benefits expense, provided that such costs are supported by an actuarial study; however, this protocol shall not apply if such expense related to costs incurred under this Section is recovered under Article IX or Section 16-108.5 of this Act;

(iii) recovery of existing regulatory assets over the periods previously authorized by the Commission;

(iv) as described in subsection (e), amortization of costs incurred under this Section; and

(v) projected, weather normalized billing determinants for the applicable rate year.

(E) Provide for an annual reconciliation, as described in paragraph (3) of this subsection (d), less any deferred taxes related to the reconciliation, with interest at an annual rate of return equal to the utility's weighted average cost of capital, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return, of the energy efficiency revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its energy efficiency formula rate tariff under this paragraph (2), with what the revenue requirement would have been had the actual cost information for the applicable calendar year been available at the filing date.

The utility shall file, together with its tariff, the projected costs to be incurred by the utility during the rate year under the utility's multi-year plan approved under subsections (f) and (g) of this Section, including, but not limited to, the projected capital investment costs and projected regulatory asset balances with correspondingly updated depreciation and amortization reserves and expense, that shall populate the energy efficiency formula rate and set the initial rates under the formula.

The Commission shall review the proposed tariff in conjunction with its review of a proposed multi-year plan, as specified in paragraph (5) of subsection (g) of this Section. The review shall be based on the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, the Commission applies in a hearing to review a filing for a general increase in rates under Article IX of this Act. The initial rates shall take effect beginning with the January monthly billing period following the Commission's approval.

The tariff's rate design and cost allocation across customer classes shall be consistent with the utility's automatic adjustment clause tariff in effect on June 1, 2017 (the effective date of Public Act 99-906); however, the Commission may revise the tariff's rate design and cost allocation in subsequent proceedings under paragraph (3) of this subsection (d).

If the energy efficiency formula rate is terminated, the then current rates shall remain in effect until such time as the energy efficiency costs are incorporated into new rates that are set under this subsection (d) or Article IX of this Act, subject to retroactive rate adjustment, with interest, to reconcile rates charged with actual costs.

(3) The provisions of this paragraph (3) shall only apply to an electric utility that has elected to file an energy efficiency formula rate under paragraph (2) of this subsection (d). Subsequent to the Commission's issuance of an order approving the utility's energy efficiency formula rate structure and protocols, and initial rates under paragraph (2) of this subsection (d), the utility shall file, on or before June 1 of each year, with the Chief Clerk of the Commission its updated cost inputs to the energy efficiency formula rate for the applicable rate year and the corresponding new charges, as well as the information described in paragraph (9) of subsection (g) of this Section. Each such filing shall conform to the following requirements and include the following information:

(A) The inputs to the energy efficiency formula rate for the applicable rate year shall be based on the projected costs to be incurred by the utility during the rate year under the utility's multi-year plan approved under subsections (f) and (g) of this Section, including, but not limited to, projected capital investment costs and projected regulatory asset balances with correspondingly updated depreciation and amortization reserves and expense. The filing shall also include a reconciliation of the energy efficiency revenue requirement that was in effect for the prior rate year (as set by the cost inputs for the prior rate year) with the actual revenue requirement for the prior rate year (determined using a year-end rate base) that uses amounts reflected in the applicable FERC Form 1 that reports the actual costs for the prior rate year. Any over-collection or under-collection indicated by such reconciliation shall be reflected as a credit against, or recovered as an additional charge to, respectively, with interest calculated at a rate equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, the charges for the applicable rate year. Such over-collection or under-collection shall be adjusted to remove any deferred taxes related to the reconciliation, for purposes of calculating interest at an annual rate of return equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return. Each reconciliation shall be certified by the participating utility in the same manner that FERC Form 1 is certified. The filing shall also include the charge or credit, if any, resulting from the calculation required by subparagraph (E) of paragraph (2) of this subsection (d).

Notwithstanding any other provision of law to the contrary, the intent of the reconciliation is to ultimately reconcile both the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its energy efficiency formula rate tariff under paragraph (2) of this subsection (d), with what the revenue requirement determined using a year-end rate base for the applicable calendar year would have been had the actual cost information for the applicable calendar year been available at the filing date.

For purposes of this Section, "FERC Form 1" means the Annual Report of Major Electric Utilities, Licensees and Others that electric utilities are required to file with the Federal Energy Regulatory Commission under the Federal Power Act, Sections 3, 4(a), 304 and 209, modified as necessary to be consistent with 83 Ill. Adm. Code Part 415 as of May 1, 2011. Nothing in this Section is intended to allow costs that are not otherwise recoverable to be recoverable by virtue of inclusion in FERC Form 1.

(B) The new charges shall take effect beginning on the first billing day of the following January billing period and remain in effect through the last billing day of the next December billing period regardless of whether the Commission enters upon a hearing under this paragraph (3).

(C) The filing shall include relevant and necessary data and documentation for the applicable rate year. Normalization adjustments shall not be required.

Within 45 days after the utility files its annual update of cost inputs to the energy efficiency formula rate, the Commission shall with reasonable notice, initiate a proceeding concerning whether the projected costs to be incurred by the utility and recovered during the applicable rate year, and that are reflected in the inputs to the energy efficiency formula rate, are consistent with the utility's approved multi-year plan under subsections (f) and (g) of this Section and whether the costs incurred by the utility during the prior rate year were prudent and reasonable. The Commission shall also have the authority to investigate the information and data described in paragraph (9) of subsection (g) of this Section, including the proposed adjustment to the utility's return on equity component of its weighted average cost of capital. During the course of the proceeding, each objection shall be stated with particularity and evidence provided in support thereof, after which the utility shall have the opportunity to rebut the evidence. Discovery shall be allowed consistent with the Commission's Rules of Practice, which Rules of Practice shall be enforced by the Commission or the assigned administrative law judge. The Commission shall apply the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, during the proceeding as it would apply in a proceeding to review a filing for a general increase in rates under Article IX of this Act. The Commission shall not, however, have the authority in a proceeding under this paragraph (3) to consider or order any changes to the structure or protocols of the energy efficiency formula rate approved under paragraph (2) of this subsection (d). In a proceeding under this paragraph (3), the Commission shall enter its order no later than the earlier of 195 days after the utility's filing of its annual update of cost inputs to the energy efficiency formula rate or December 15. The utility's proposed return on equity calculation, as described in paragraphs (7) through (9) of subsection (g) of this Section, shall be deemed the final, approved calculation on December 15 of the year in which it is filed unless the Commission enters an order on or before December 15, after notice and hearing, that modifies such calculation consistent with this Section. The Commission's determinations of the prudence and reasonableness of the costs incurred, and determination of such return on equity calculation, for the applicable calendar year shall be final upon entry of the Commission's order and shall not be subject to reopening, reexamination, or collateral attack in any other Commission proceeding, case, docket, order, rule, or regulation; however, nothing in this paragraph (3) shall prohibit a party from petitioning the Commission to rehear or appeal to the courts the order under the provisions of this Act.

(e) Beginning on June 1, 2017 (the effective date of Public Act 99-906), a utility subject to the requirements of this Section may elect to defer, as a regulatory asset, up to the full amount of its expenditures incurred under this Section for each annual period, including, but not limited to, any expenditures incurred above the funding level set by subsection (f) of this Section for a given year. The total expenditures deferred as a regulatory asset in a given year shall be amortized and recovered over a period that is equal to the weighted average of the energy efficiency measure lives implemented for that year that are reflected in the regulatory asset. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the unamortized balances of all of the energy efficiency regulatory assets, less any deferred taxes related to those unamortized balances, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end capital structure, the utility's actual cost of debt for the applicable calendar year and a cost of equity, which shall be calculated as the sum of the (i) the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and (ii) 580 basis points, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return. Capital investment costs shall be depreciated and recovered over their useful lives consistent with generally accepted accounting principles. The weighted average cost of capital shall be applied to the capital investment cost balance, less any accumulated depreciation and accumulated deferred income taxes, as of December 31 for a given year.

When an electric utility creates a regulatory asset under the provisions of this Section, the costs are recovered over a period during which customers also receive a benefit which is in the public interest. Accordingly, it is the intent of the General Assembly that an electric utility that elects to create a regulatory asset under the provisions of this Section shall recover all of the associated costs as set forth in this Section. After the Commission has approved the prudence and reasonableness of the costs that comprise the regulatory asset, the electric utility shall be permitted to recover all such costs, and the value and recoverability through rates of the associated regulatory asset shall not be limited, altered, impaired, or reduced.

(f) Beginning in 2017, each electric utility shall file an energy efficiency plan with the Commission to meet the energy efficiency standards for the next applicable multi-year period beginning January 1 of the year following the filing, according to the schedule set forth in paragraphs (1) through (3) of this subsection (f). If a utility does not file such a plan on or before the applicable filing deadline for the plan, it shall face a penalty of $100,000 per day until the plan is filed.

(1) No later than 30 days after June 1, 2017 (the effective date of Public Act 99-906), each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2018 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (1) through (4) of subsection (b-5) of this Section or in paragraphs (1) through (4) of subsection (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if the utility's expenditures are limited pursuant to subsection (m) of this Section or, for a utility that serves less than 3,000,000 retail customers, if each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate that achievement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan.

(2) No later than March 1, 2021, each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2022 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (5) through (8) of subsection (b-5) of this Section or in paragraphs (5) through (8) of subsection (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if either (1) clear and convincing evidence demonstrates, through independent analysis, that the expenditure limits in subsection (m) of this Section preclude full achievement of the goals or (2) each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate by clear and convincing evidence and through independent analysis that achievement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. If there is not clear and convincing evidence that achieving the savings goals specified in paragraph (b-5) or (b-15) of this Section is possible both cost-effectively and within the expenditure limits in subsection (m), such savings goals shall not be reduced. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan.

(3) No later than March 1, 2025, each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2026 that is designed to achieve the incremental annual savings as defined by subsection (b-16) the cumulative persisting annual savings goals specified in paragraphs (9) through (12) of subsection (b-5) of this Section or in paragraphs (9) through (12) of subsection (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if either (1) clear and convincing evidence demonstrates, through independent analysis, that the expenditure limits in subsection (m) of this Section preclude full achievement of the goals or (2) each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate by clear and convincing evidence and through independent analysis that achievement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. If there is not clear and convincing evidence that achieving the savings goals specified in subsection (b-16) paragraphs (b-5) or (b-15) of this Section is possible both cost-effectively and within the expenditure limits in subsection (m), such savings goals shall not be reduced. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan.

(4) No later than March 1, 2029, and every 4 years thereafter, each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2030, and every 4 years thereafter, respectively, that is designed to achieve the incremental annual savings as defined by subsection (b-16) cumulative persisting annual savings goals established by the Illinois Commerce Commission pursuant to direction of subsections (b-5) and (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if either (1) clear and convincing evidence and independent analysis demonstrates that the expenditure limits in subsection (m) of this Section preclude full achievement of the goals or (2) each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate by clear and convincing evidence and through independent analysis that achievement of such goals is not cost-effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. If there is not clear and convincing evidence that achieving the savings goals specified in paragraphs (b-5) or (b-15) of this Section is possible both cost-effectively and within the expenditure limits in subsection (m), such savings goals shall not be reduced. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan.

Each utility's plan shall set forth the utility's proposals to meet the energy efficiency standards identified in subsection (b-5), or (b-15), or (b-16) as applicable and as such standards may have been modified under this subsection (f), taking into account the unique circumstances of the utility's service territory. For those plans commencing on January 1, 2018, the Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan no later than 105 days after June 1, 2017 (the effective date of Public Act 99-906). For those plans commencing after December 31, 2021, the Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 6 months after its submission. If the Commission disapproves a plan, the Commission shall, within 30 days, describe in detail the reasons for the disapproval and describe a path by which the utility may file a revised draft of the plan to address the Commission's concerns satisfactorily. If the utility does not refile with the Commission within 60 days, the utility shall be subject to penalties at a rate of $100,000 per day until the plan is filed. This process shall continue, and penalties shall accrue, until the utility has successfully filed a portfolio of energy efficiency and demand-response measures. Penalties shall be deposited into the Energy Efficiency Trust Fund.

(g) In submitting proposed plans and funding levels under subsection (f) of this Section to meet the savings goals identified in subsection (b-5), or (b-15), or (b-16) of this Section, as applicable, the utility shall:

(1) Demonstrate that its proposed energy efficiency measures will achieve the applicable requirements that are identified in subsection (b-5), or (b-15), or (b-16) of this Section, as modified by subsection (f) of this Section.

(2) (Blank).

(2.5) Demonstrate consideration of program options for (A) advancing new building codes, appliance standards, and municipal regulations governing existing and new building efficiency improvements and (B) supporting efforts to improve compliance with new building codes, appliance standards and municipal regulations, as potentially cost-effective means of acquiring energy savings to count toward savings goals.

(3) Demonstrate that its overall portfolio of measures, not including low-income programs described in subsection (c) of this Section, is cost-effective using the total resource cost test or complies with paragraphs (1) through (3) of subsection (f) of this Section and represents a diverse cross-section of opportunities for customers of all rate classes, other than those customers described in subsection (l) of this Section, to participate in the programs. Individual measures need not be cost effective.

(3.5) Demonstrate that the utility's plan integrates the delivery of energy efficiency programs with natural gas efficiency programs, programs promoting distributed solar, programs promoting demand response and other efforts to address bill payment issues, including, but not limited to, LIHEAP and the Percentage of Income Payment Plan, to the extent such integration is practical and has the potential to enhance customer engagement, minimize market confusion, or reduce administrative costs.

(4) Present a third-party energy efficiency implementation program subject to the following requirements:

(A) beginning with the year commencing January 1, 2019, electric utilities that serve more than 3,000,000 retail customers in the State shall fund third-party energy efficiency programs in an amount that is no less than $25,000,000 per year, and electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall fund third-party energy efficiency programs in an amount that is no less than $8,350,000 per year;

(B) during 2018, the utility shall conduct a solicitation process for purposes of requesting proposals from third-party vendors for those third-party energy efficiency programs to be offered during one or more of the years commencing January 1, 2019, January 1, 2020, and January 1, 2021; for those multi-year plans commencing on January 1, 2022 and January 1, 2026, the utility shall conduct a solicitation process during 2021 and 2025, respectively, for purposes of requesting proposals from third-party vendors for those third-party energy efficiency programs to be offered during one or more years of the respective multi-year plan period; for each solicitation process, the utility shall identify the sector, technology, or geographical area for which it is seeking requests for proposals; the solicitation process must be either for programs that fill gaps in the utility's program portfolio and for programs that target low-income customers, business sectors, building types, geographies, or other specific parts of its customer base with initiatives that would be more effective at reaching these customer segments than the utilities' programs filed in its energy efficiency plans;

(C) the utility shall propose the bidder qualifications, performance measurement process, and contract structure, which must include a performance payment mechanism and general terms and conditions; the proposed qualifications, process, and structure shall be subject to Commission approval; and

(D) the utility shall retain an independent third party to score the proposals received through the solicitation process described in this paragraph (4), rank them according to their cost per lifetime kilowatt-hours saved, and assemble the portfolio of third-party programs.

The electric utility shall recover all costs associated with Commission-approved, third-party administered programs regardless of the success of those programs.

(4.5) Implement cost-effective demand-response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers, as defined in Section 16-111.5 of this Act, and for customers that elect hourly service from the utility pursuant to Section 16-107 of this Act, provided those customers have not been declared competitive. This requirement continues until December 31, 2026.

(5) Include a proposed or revised cost-recovery tariff mechanism, as provided for under subsection (d) of this Section, to fund the proposed energy efficiency and demand-response measures and to ensure the recovery of the prudently and reasonably incurred costs of Commission-approved programs.

(6) Provide for an annual independent evaluation of the performance of the cost-effectiveness of the utility's portfolio of measures, as well as a full review of the multi-year plan results of the broader net program impacts and, to the extent practical, for adjustment of the measures on a going-forward basis as a result of the evaluations. The resources dedicated to evaluation shall not exceed 3% of portfolio resources in any given year.

(7) For electric utilities that serve more than 500,000 3,000,000 retail customers in the State:

(A) Through December 31, 2025, provide for an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section:

(i) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is less than the applicable annual incremental goal, then the return on equity component shall be reduced by a maximum of 200 basis points in the event that the utility achieved no more than 75% of such goal. If the utility achieved more than 75% of the applicable annual incremental goal but less than 100% of such goal, then the return on equity component shall be reduced by 8 basis points for each percent by which the utility failed to achieve the goal.

(ii) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is more than the applicable annual incremental goal, then the return on equity component shall be increased by a maximum of 200 basis points in the event that the utility achieved at least 125% of such goal. If the utility achieved more than 100% of the applicable annual incremental goal but less than 125% of such goal, then the return on equity component shall be increased by 8 basis points for each percent by which the utility achieved above the goal. If the applicable annual incremental goal was reduced under paragraph (1) or (2) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in this item (ii):

(aa) the calculation for determining achievement that is at least 125% of the applicable annual incremental goal shall use the unreduced applicable annual incremental goal to set the value; and

(bb) the calculation for determining achievement that is less than 125% but more than 100% of the applicable annual incremental goal shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 8 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% achievement.

(B) For the period January 1, 2026 through December 31, 2029 and in all subsequent 4-year periods, provide for an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section:

(i) If the incremental annual savings goal specified in subsection (b-16) of this Section is unmodified, and if the independent evaluator determines that the utility achieved lifetime energy savings that is less than the product of the incremental annual savings goal and minimum average savings life specified in subsection (b-16) of this Section, then the return on equity component shall be reduced by a maximum of 200 basis points if the utility achieved no more than 66% of such lifetime savings goal. If the utility achieved more than 66% but less than 100% of such goal, then the return on equity component shall be reduced by 6 basis points for each percent by which the utility failed to achieve the goal If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is less than the applicable annual incremental goal, then the return on equity component shall be reduced by a maximum of 200 basis points in the event that the utility achieved no more than 66% of such goal. If the utility achieved more than 66% of the applicable annual incremental goal but less than 100% of such goal, then the return on equity component shall be reduced by 6 basis points for each percent by which the utility failed to achieve the goal.

(ii) If the incremental annual savings goal specified in subsection(b-16) of this Section is unmodified, and if the independent evaluator determines that the utility achieved lifetime energy savings that is more than the product of the incremental annual savings goal and minimum average savings life specified in subsection (b-16) of this Section, then the return on equity component shall be increased by a maximum of 200 basis points if the utility achieved at least 134% of such lifetime savings goal. If the utility achieved more than 100% but less than 134% of such goal, then the return on equity component shall be increased by 6 basis points for each percent by which the utility achieved above the goal. If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is more than the applicable annual incremental goal, then the return on equity component shall be increased by a maximum of 200 basis points in the event that the utility achieved at least 134% of such goal. If the utility achieved more than 100% of the applicable annual incremental goal but less than 134% of such goal, then the return on equity component shall be increased by 6 basis points for each percent by which the utility achieved above the goal. If the applicable annual incremental goal was reduced under paragraph (3) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in this item (ii):

(iii) If the incremental annual savings goal specified in subsection (b-16) of this Section is reduced pursuant to paragraphs (3) or (4) of subsection (f), then the return on equity shall be reduced by 10 basis points for every percent by which the utility fails to achieved the modified goal, up to a maximum of a 200 basis point reduction. (aa) the calculation for determining achievement that is at least 134% of the applicable annual incremental goal shall use the unreduced applicable annual incremental goal to set the value; and

(iv) If the incremental annual savings goal specified in subsection (b-16) of this Section is reduced pursuant to paragraphs (3) or (4) of subsection (f), the return on equity component shall be increased by a maximum of 200 basis points if the utility achieved at least 134% of the unmodified lifetime savings goal. If the utility achieved more than 100% of the modified goal but less than 134% of the unmodified goal, then the return on equity component shall be linearly interpolated between 0 increase for just meeting 100% of the modified goal and a 200 basis point increase for achieving 134% of the unmodified goal (bb) the calculation for determining achievement that is less than 134% but more than 100% of the applicable annual incremental goal shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 134% achievement. The 6 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 134% achievement.

(C) Notwithstanding the provisions of subparagraphs (A) and (B) of this paragraph (7), if the applicable annual incremental goal for an electric utility is ever less than 0.6% of deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015, and 2016, an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section shall be made as follows:

(i) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is less than would have been achieved had the applicable annual incremental goal been achieved, then the return on equity component shall be reduced by a maximum of 200 basis points if the utility achieved no more than 75% of its applicable annual total savings requirement as defined in paragraph (7.5) of this subsection. If the utility achieved more than 75% of the applicable annual total savings requirement but less than 100% of such goal, then the return on equity component shall be reduced by 8 basis points for each percent by which the utility failed to achieve the goal.

(ii) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is more than would have been achieved had the applicable annual incremental goal been achieved, then the return on equity component shall be increased by a maximum of 200 basis points if the utility achieved at least 125% of its applicable annual total savings requirement. If the utility achieved more than 100% of the applicable annual total savings requirement but less than 125% of such goal, then the return on equity component shall be increased by 8 basis points for each percent by which the utility achieved above the applicable annual total savings requirement. If the applicable annual incremental goal was reduced under paragraph (1) or (2) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in this item (ii):

(aa) the calculation for determining achievement that is at least 125% of the applicable annual total savings requirement shall use the unreduced applicable annual incremental goal to set the value; and

(bb) the calculation for determining achievement that is less than 125% but more than 100% of the applicable annual total savings requirement shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 8 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% achievement.

(7.5) For purposes of this Section, the term "applicable annual incremental goal" means the difference between the cumulative persisting annual savings goal for the calendar year that is the subject of the independent evaluator's determination and the cumulative persisting annual savings goal for the immediately preceding calendar year, as such goals are defined in subsections (b-5) and (b-15) of this Section and as these goals may have been modified as provided for under subsection (b-20) and paragraphs (1) and (2) through (3) of subsection (f) of this Section. Under subsections (b), (b-5), (b-10), and (b-15) of this Section, a utility must first replace energy savings from measures that have expired before any progress towards achievement of its applicable annual incremental goal may be counted. Savings may expire because measures installed in previous years have reached the end of their lives, because measures installed in previous years are producing lower savings in the current year than in the previous year, or for other reasons identified by independent evaluators. Notwithstanding anything else set forth in this Section, the difference between the actual annual incremental savings achieved in any given year, including the replacement of energy savings that have expired, and the applicable annual incremental goal shall not affect adjustments to the return on equity for subsequent calendar years under this subsection (g).

In this Section, "applicable annual total savings requirement" means the total amount of new annual savings that the utility must achieve in any given year to achieve the applicable annual incremental goal. This is equal to the applicable annual incremental goal plus the total new annual savings that are required to replace savings that expired in or at the end of the previous year.

(8) (Blank). For electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State:

(A) Through December 31, 2025, the applicable annual incremental goal shall be compared to the annual incremental savings as determined by the independent evaluator.

(i) The return on equity component shall be reduced by 8 basis points for each percent by which the utility did not achieve 84.4% of the applicable annual incremental goal.

(ii) The return on equity component shall be increased by 8 basis points for each percent by which the utility exceeded 100% of the applicable annual incremental goal.

(iii) The return on equity component shall not be increased or decreased if the annual incremental savings as determined by the independent evaluator is greater than 84.4% of the applicable annual incremental goal and less than 100% of the applicable annual incremental goal.

(iv) The return on equity component shall not be increased or decreased by an amount greater than 200 basis points pursuant to this subparagraph (A).

(B) For the period of January 1, 2026 through December 31, 2029 and in all subsequent 4-year periods, the applicable annual incremental goal shall be compared to the annual incremental savings as determined by the independent evaluator.

(i) The return on equity component shall be reduced by 6 basis points for each percent by which the utility did not achieve 100% of the applicable annual incremental goal.

(ii) The return on equity component shall be increased by 6 basis points for each percent by which the utility exceeded 100% of the applicable annual incremental goal.

(iii) The return on equity component shall not be increased or decreased by an amount greater than 200 basis points pursuant to this subparagraph (B).

(C) Notwithstanding provisions in subparagraphs (A) and (B) of paragraph (7) of this subsection, if the applicable annual incremental goal for an electric utility is ever less than 0.6% of deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015 and 2016, an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section shall be made as follows:

(i) The return on equity component shall be reduced by 8 basis points for each percent by which the utility did not achieve 100% of the applicable annual total savings requirement.

(ii) The return on equity component shall be increased by 8 basis points for each percent by which the utility exceeded 100% of the applicable annual total savings requirement.

(iii) The return on equity component shall not be increased or decreased by an amount greater than 200 basis points pursuant to this subparagraph (C).

(D) If the applicable annual incremental goal was reduced under paragraph (1), (2), (3), or (4) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in subparagraphs (A), (B), and (C) of this paragraph (8):

(i) The calculation for determining achievement that is at least 125% or 134%, as applicable, of the applicable annual incremental goal or the applicable annual total savings requirement, as applicable, shall use the unreduced applicable annual incremental goal to set the value.

(ii) For the period through December 31, 2025, the calculation for determining achievement that is less than 125% but more than 100% of the applicable annual incremental goal or the applicable annual total savings requirement, as applicable, shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 8 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% achievement.

(iii) For the period of January 1, 2026 through December 31, 2029 and all subsequent 4-year periods, the calculation for determining achievement that is less than 125% or 134%, as applicable, but more than 100% of the applicable annual incremental goal or the applicable annual total savings requirement, as applicable, shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 6 basis-point value or 8 basis-point value, as applicable, shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% or between 100% and 134% achievement, as applicable.

(9) The utility shall submit the energy savings data to the independent evaluator no later than 30 days after the close of the plan year. The independent evaluator shall determine the cumulative persisting annual savings for a given plan year, as well as an estimate of job impacts and other macroeconomic impacts of the efficiency programs for that year, no later than 120 days after the close of the plan year. The utility shall submit an informational filing to the Commission no later than 160 days after the close of the plan year that attaches the independent evaluator's final report identifying the cumulative persisting annual savings for the year and calculates, under paragraph (7) or (8) of this subsection (g), as applicable, any resulting change to the utility's return on equity component of the weighted average cost of capital applicable to the next plan year beginning with the January monthly billing period and extending through the December monthly billing period. However, if the utility recovers the costs incurred under this Section under paragraphs (2) and (3) of subsection (d) of this Section, then the utility shall not be required to submit such informational filing, and shall instead submit the information that would otherwise be included in the informational filing as part of its filing under paragraph (3) of such subsection (d) that is due on or before June 1 of each year.

For those utilities that must submit the informational filing, the Commission may, on its own motion or by petition, initiate an investigation of such filing, provided, however, that the utility's proposed return on equity calculation shall be deemed the final, approved calculation on December 15 of the year in which it is filed unless the Commission enters an order on or before December 15, after notice and hearing, that modifies such calculation consistent with this Section.

The adjustments to the return on equity component described in paragraph paragraphs (7) and (8) of this subsection (g) shall be applied as described in such paragraphs through a separate tariff mechanism, which shall be filed by the utility under subsections (f) and (g) of this Section.

(9.5) The utility must demonstrate how it will ensure that program implementation contractors and energy efficiency installation vendors will promote workforce equity and quality jobs.

(9.6) Utilities shall collect data necessary to ensure compliance with paragraph (9.5) no less than quarterly and shall communicate progress toward compliance with paragraph (9.5) to program implementation contractors and energy efficiency installation vendors no less than quarterly. Utilities shall work with relevant vendors, providing education, training, and other resources needed to ensure compliance and, where necessary, adjusting or terminating work with vendors that cannot assist with compliance.

(10) Utilities required to implement efficiency programs under subsections (b-5), and (b-10), and (b-16) shall report annually to the Illinois Commerce Commission and the General Assembly on how hiring, contracting, job training, and other practices related to its energy efficiency programs enhance the diversity of vendors working on such programs. These reports must include data on vendor and employee diversity, including data on the implementation of paragraphs (9.5) and (9.6). If the utility is not meeting the requirements of paragraphs (9.5) and (9.6), the utility shall submit a plan to adjust their activities so that they meet the requirements of paragraphs (9.5) and (9.6) within the following year.

(h) No more than 4% of energy efficiency and demand-response program revenue may be allocated for research, development, or pilot deployment of new equipment or measures. Electric utilities shall work with interested stakeholders to formulate a plan for how these funds should be spent, incorporate statewide approaches for these allocations, and file a 4-year plan that demonstrates that collaboration. If a utility files a request for modified annual energy savings goals with the Commission, then a utility shall forgo spending portfolio dollars on research and development proposals.

(i) When practicable, electric utilities shall incorporate advanced metering infrastructure data into the planning, implementation, and evaluation of energy efficiency measures and programs, subject to the data privacy and confidentiality protections of applicable law.

(j) The independent evaluator shall follow the guidelines and use the savings set forth in Commission-approved energy efficiency policy manuals and technical reference manuals, as each may be updated from time to time. Until such time as measure life values for energy efficiency measures implemented for low-income households under subsection (c) of this Section are incorporated into such Commission-approved manuals, the low-income measures shall have the same measure life values that are established for same measures implemented in households that are not low-income households.

(k) Notwithstanding any provision of law to the contrary, an electric utility subject to the requirements of this Section may file a tariff cancelling an automatic adjustment clause tariff in effect under this Section or Section 8-103, which shall take effect no later than one business day after the date such tariff is filed. Thereafter, the utility shall be authorized to defer and recover its expenditures incurred under this Section through a new tariff authorized under subsection (d) of this Section or in the utility's next rate case under Article IX or Section 16-108.5 of this Act, with interest at an annual rate equal to the utility's weighted average cost of capital as approved by the Commission in such case. If the utility elects to file a new tariff under subsection (d) of this Section, the utility may file the tariff within 10 days after June 1, 2017 (the effective date of Public Act 99-906), and the cost inputs to such tariff shall be based on the projected costs to be incurred by the utility during the calendar year in which the new tariff is filed and that were not recovered under the tariff that was cancelled as provided for in this subsection. Such costs shall include those incurred or to be incurred by the utility under its multi-year plan approved under subsections (f) and (g) of this Section, including, but not limited to, projected capital investment costs and projected regulatory asset balances with correspondingly updated depreciation and amortization reserves and expense. The Commission shall, after notice and hearing, approve, or approve with modification, such tariff and cost inputs no later than 75 days after the utility filed the tariff, provided that such approval, or approval with modification, shall be consistent with the provisions of this Section to the extent they do not conflict with this subsection (k). The tariff approved by the Commission shall take effect no later than 5 days after the Commission enters its order approving the tariff.

No later than 60 days after the effective date of the tariff cancelling the utility's automatic adjustment clause tariff, the utility shall file a reconciliation that reconciles the moneys collected under its automatic adjustment clause tariff with the costs incurred during the period beginning June 1, 2016 and ending on the date that the electric utility's automatic adjustment clause tariff was cancelled. In the event the reconciliation reflects an under-collection, the utility shall recover the costs as specified in this subsection (k). If the reconciliation reflects an over-collection, the utility shall apply the amount of such over-collection as a one-time credit to retail customers' bills.

(l) (Blank). For the calendar years covered by a multi-year plan commencing after December 31, 2017, subsections (a) through (j) of this Section do not apply to eligible large private energy customers that have chosen to opt out of multi-year plans consistent with this subsection (1).

(1) For purposes of this subsection (l), "eligible large private energy customer" means any retail customers, except for federal, State, municipal, and other public customers, of an electric utility that serves more than 3,000,000 retail customers, except for federal, State, municipal and other public customers, in the State and whose total highest 30 minute demand was more than 10,000 kilowatts, or any retail customers of an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State and whose total highest 15 minute demand was more than 10,000 kilowatts. For purposes of this subsection (l), "retail customer" has the meaning set forth in Section 16-102 of this Act. However, for a business entity with multiple sites located in the State, where at least one of those sites qualifies as an eligible large private energy customer, then any of that business entity's sites, properly identified on a form for notice, shall be considered eligible large private energy customers for the purposes of this subsection (l). A determination of whether this subsection is applicable to a customer shall be made for each multi-year plan beginning after December 31, 2017. The criteria for determining whether this subsection (l) is applicable to a retail customer shall be based on the 12 consecutive billing periods prior to the start of the first year of each such multi-year plan.

(2) Within 45 days after September 15, 2021 (the effective date of Public Act 102-662), the Commission shall prescribe the form for notice required for opting out of energy efficiency programs. The notice must be submitted to the retail electric utility 12 months before the next energy efficiency planning cycle. However, within 120 days after the Commission's initial issuance of the form for notice, eligible large private energy customers may submit a form for notice to an electric utility. The form for notice for opting out of energy efficiency programs shall include all of the following:

(A) a statement indicating that the customer has elected to opt out;

(B) the account numbers for the customer accounts to which the opt out shall apply;

(C) the mailing address associated with the customer accounts identified under subparagraph (B);

(D) an American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) level 2 or higher audit report conducted by an independent third-party expert identifying cost-effective energy efficiency project opportunities that could be invested in over the next 10 years. A retail customer with specialized processes may utilize a self-audit process in lieu of the ASHRAE audit;

(E) a description of the customer's plans to reallocate the funds toward internal energy efficiency efforts identified in the subparagraph (D) report, including, but not limited to: (i) strategic energy management or other programs, including descriptions of targeted buildings, equipment and operations; (ii) eligible energy efficiency measures; and (iii) expected energy savings, itemized by technology. If the subparagraph (D) audit report identifies that the customer currently utilizes the best available energy efficient technology, equipment, programs, and operations, the customer may provide a statement that more efficient technology, equipment, programs, and operations are not reasonably available as a means of satisfying this subparagraph (E); and

(F) the effective date of the opt out, which will be the next January 1 following notice of the opt out.

(3) Upon receipt of a properly and timely noticed request for opt out submitted by an eligible large private energy customer, the retail electric utility shall grant the request, file the request with the Commission and, beginning January 1 of the following year, the opted out customer shall no longer be assessed the costs of the plan and shall be prohibited from participating in that 4-year plan cycle to give the retail utility the certainty to design program plan proposals.

(4) Upon a customer's election to opt out under paragraphs (1) and (2) of this subsection (l) and commencing on the effective date of said opt out, the account properly identified in the customer's notice under paragraph (2) shall not be subject to any cost recovery and shall not be eligible to participate in, or directly benefit from, compliance with energy efficiency cumulative persisting savings requirements under subsections (a) through (j).

(5) A utility's cumulative persisting annual savings targets will exclude any opted out load.

(6) The request to opt out is only valid for the requested plan cycle. An eligible large private energy customer must also request to opt out for future energy plan cycles, otherwise the customer will be included in the future energy plan cycle.

(m) Notwithstanding the requirements of this Section, as part of a proceeding to approve a multi-year plan under subsections (f) and (g) of this Section if the multi-year plan has been designed to maximize savings, but does not meet the cost cap limitations of this Section, the Commission shall reduce the amount of energy efficiency measures implemented for any single year, and whose costs are recovered under subsection (d) of this Section, by an amount necessary to limit the estimated average net increase due to the cost of the measures to no more than

(1) 3.5% for each of the 4 years beginning January 1, 2018,

(2) (blank),

(3) 4% for each of the 4 years beginning January 1, 2022,

(4) 4.25% for the 4 years beginning January 1, 2026, and

(5) 4.25% plus an increase sufficient to account for the rate of inflation between January 1, 2026 and January 1 of the first year of each subsequent 4-year plan cycle, of the average amount paid per kilowatthour by residential eligible retail customers during calendar year 2015. An electric utility may plan to spend up to 10% more in any year during an applicable multi-year plan period to cost-effectively achieve additional savings so long as the average over the applicable multi-year plan period does not exceed the percentages defined in items (1) through (5). To determine the total amount that may be spent by an electric utility in any single year, the applicable percentage of the average amount paid per kilowatthour shall be multiplied by the total amount of energy delivered by such electric utility in the calendar year 2015, adjusted to reflect the proportion of the utility's load attributable to customers that have opted out of subsections (a) through (j) of this Section under subsection (l) of this Section. For purposes of this subsection (m), the amount paid per kilowatthour includes, without limitation, estimated amounts paid for supply, transmission, distribution, surcharges, and add-on taxes. For purposes of this Section, "eligible retail customers" shall have the meaning set forth in Section 16-111.5 of this Act. Once the Commission has approved a plan under subsections (f) and (g) of this Section, no subsequent rate impact determinations shall be made.

(n) A utility shall take advantage of the efficiencies available through existing Illinois Home Weatherization Assistance Program infrastructure and services, such as enrollment, marketing, quality assurance and implementation, which can reduce the need for similar services at a lower cost than utility-only programs, subject to capacity constraints at community action agencies, for both single-family and multifamily weatherization services, to the extent Illinois Home Weatherization Assistance Program community action agencies provide multifamily services. A utility's plan shall demonstrate that in formulating annual weatherization budgets, it has sought input and coordination with community action agencies regarding agencies' capacity to expand and maximize Illinois Home Weatherization Assistance Program delivery using the ratepayer dollars collected under this Section.

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

(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 5/16-107.8 new)

Sec. 16-107.8. Residential time-of-use pricing.

(a) The General Assembly finds that time-of-use rates and pricing plans can lower energy costs for consumers and reduce grid costs as well as help the State achieve its energy policy goals by improving load shape, encouraging energy conservation, and shifting usage away from periods where fossil fuels are used to meet peak demand. Further, by providing consumers information relating the costs of service to the time of energy usage, time-of-use rates can help consumers reduce their energy bills by using electricity when it is less costly. Time-of-use rates can help allocate electricity system costs more accurately and thus equitably to those who cause costs. Such rates can reduce the need for ramping resources and increase the grid's ability to cost-effectively integrate greater quantities of variable renewable energy and distributed energy resources.

(b) An electric utility that has a tariff approved under subsection (d) of Section 16-108.18 within one year of this amendatory Act of the 103rd General Assembly shall also offer at least one market-based, residential rate for eligible retail customers that choose to take power and energy supply service from the utility. If the utility has a pending request for approval of a Multi-Year Integrated Grid Plan, the utility shall update its filing in that docket to reflect the likely impacts of the time-of-use rate offering. The utility shall file its time-of-use rate tariff no later than 120 days after the effective date of this amendatory Act of the 103rd General Assembly, and each utility subject to this requirement shall implement the requirements of this subsection by filing a tariff with the Commission. The tariff or tariffs shall be subject to the following provisions:

(1) If more than one tariff is proposed, at least one tariff shall include at least 3 time blocks: a peak time block, defined as 2 p.m. to 7 p.m. on nonholiday weekdays or the 5 consecutive hours best reflecting the highest system peak demands; an off-peak time block, defined as 10 a.m. to 2 p.m. and 7 p.m. to 10 p.m. on nonholiday weekdays or the 7 total hours occurring in some combination before and after the peak period, which reflect the next highest system peak demands; and a super-off-peak time block, defined as all other hours and including weekend days.

(2) This tariff shall strive to achieve price ratios between the blocks as follows: the super-off-peak time block price shall be no less than zero but no greater than one-half of the price of the off-peak time block price, and the off-peak time block price shall be no greater than one-half of the price of the peak time block price.

(3) The time-of-use rate shall include the costs of electric capacity, costs of transmission services, and charges for network integration transmission service, transmission enhancement, and locational reliability, as these terms are defined in the PJM Interconnection LLC Open Access Transmission Tariff and manuals on January 1, 2019, within the prices for each time block and seasonal block in which the associated costs generally are incurred. If the Open Access Transmission Tariff or manuals subsequently renames those terms, the services reflected under those terms shall continue to be included in the time-of-use rate described in this paragraph.

(4) Adjustments to the charges set by the tariff may be made on a semi-annual basis, as follows: each May and November, the utility shall submit to the Commission, through an informational filing, its updated charges, and such charges shall take effect beginning with the June monthly billing period and December monthly billing period, respectively.

(5) The tariff shall include a purchased energy adjustment to fully recover the supply costs for the customers taking service under this tariff.

As used in this subsection, "eligible residential customers" includes, but is not limited to, customers participating in net electricity metering under the terms of Section 16-107.5.

(c) The Commission shall, after notice and hearing, approve the tariff or tariffs with modifications the Commission finds necessary to improve the program design, customer participation in the program, or coordination with existing utility pricing programs, energy efficiency programs, demand-response programs, and any other programs supporting State energy policy goals and the integration of distributed energy resources. The Commission shall also consider how the proposed time-of-use rate design reflects the system costs and usage patterns of the utility. A proceeding under this subsection may not exceed 120 days in length.

(d) If the Commission issues an order pursuant to this subsection, the affected electric utility shall contract with an entity not affiliated with the electric utility to serve as a program administrator to develop and implement a program to provide consumer outreach, enrollment, and education concerning time-of-use pricing and to establish and administer an information system and technical and other customer assistance that is necessary to enable customers to manage electricity use. The program administrator: (i) shall be selected and compensated by the electric utility, subject to Commission approval; (ii) shall have demonstrated technical and managerial competence in the development and administration of demand management programs; and (iii) may develop and implement risk management, energy efficiency, and other services related to energy use management for which the program administrator shall be compensated by participants in the program receiving such services. The electric utility shall provide the program administrator with all information and assistance necessary to perform the program administrator's duties, including, but not limited to, customer, account, and energy use data. The electric utility shall permit the program administrator to include inserts in residential customer bills 2 times per year to assist with customer outreach and enrollment. The program administrator shall submit an annual report to the electric utility no later than April 1 of each year describing the operation and results of the program, including information concerning the number and types of customers using the program, changes in customers' energy use patterns, an assessment of the value of the program to both participants and nonparticipants, and recommendations concerning modification of the program and the tariff or tariffs filed under this Section. This report shall be filed by the electric utility with the Commission within 30 days after receipt and shall be available to the public on the Commission's website.

(e) Once the tariff or tariffs has been in effect for 12 months, the Commission may, upon complaint, petition, or its own initiative, open a proceeding to investigate whether changes or modifications to the tariff or tariffs, program administration and any other program design element is necessary to achieve the goals described in subsection (a) and to shifting usage away from periods where fossil fuels are used to meet peak demand and realign usage to periods when renewable generation is available. Such a proceeding may not last more than 180 days from the date upon which the investigation is opened by Commission order. Thereafter, the Commission may, upon complaint, petition, or its own initiative, open a proceeding to investigate changes or modifications to the tariff or tariffs at any time the Commission deems reasonable in order to achieve these objectives.

(f) An electric utility shall be entitled to recover reasonable costs incurred in complying with this Section, if the recovery of the costs is fairly apportioned among its residential customers.

(g) The electric utility's tariff or tariffs filed pursuant to this Section shall be subject to the provisions of Article IX of this Act insofar as they do not conflict with this Section.

(h) This Section does not apply to any electric utility providing service to 100,000 or fewer customers.

(220 ILCS 5/16-111.5)

Sec. 16-111.5. Provisions relating to procurement.

(a) An electric utility that on December 31, 2005 served at least 100,000 customers in Illinois shall procure power and energy for its eligible retail customers in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning with the delivery year commencing on June 1, 2017, such electric utility shall also procure zero emission credits from zero emission facilities in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act, and, for years beginning on or after June 1, 2017, the utility shall procure renewable energy resources in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning with the delivery year commencing on June 1, 2022, an electric utility serving over 3,000,000 customers shall also procure carbon mitigation credits from carbon-free energy resources in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. A small multi-jurisdictional electric utility that on December 31, 2005 served less than 100,000 customers in Illinois may elect to procure power and energy for all or a portion of its eligible Illinois retail customers in accordance with the applicable provisions set forth in this Section and Section 1-75 of the Illinois Power Agency Act. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Illinois Power Agency to prepare a procurement plan for its eligible retail customers. "Eligible retail customers" for the purposes of this Section means those retail customers that purchase power and energy from the electric utility under fixed-price bundled service tariffs, other than those retail customers whose service is declared or deemed competitive under Section 16-113 and those other customer groups specified in this Section, including self-generating customers, customers electing hourly pricing, or those customers who are otherwise ineligible for fixed-price bundled tariff service. For those customers that are excluded from the procurement plan's electric supply service requirements, and the utility shall procure any supply requirements, including capacity, ancillary services, and hourly priced energy, in the applicable markets as needed to serve those customers, provided that the utility may include in its procurement plan load requirements for the load that is associated with those retail customers whose service has been declared or deemed competitive pursuant to Section 16-113 of this Act to the extent that those customers are purchasing power and energy during one of the transition periods identified in subsection (b) of Section 16-113 of this Act.

(b) A procurement plan shall be prepared for each electric utility consistent with the applicable requirements of the Illinois Power Agency Act and this Section. For purposes of this Section, Illinois electric utilities that are affiliated by virtue of a common parent company are considered to be a single electric utility. Small multi-jurisdictional utilities may request a procurement plan for a portion of or all of its Illinois load. Each procurement plan shall analyze the projected balance of supply and demand for those retail customers to be included in the plan's electric supply service requirements over a 5-year period, with the first planning year beginning on June 1 of the year following the year in which the plan is filed. The plan shall specifically identify the wholesale products to be procured following plan approval, and shall follow all the requirements set forth in the Public Utilities Act and all applicable State and federal laws, statutes, rules, or regulations, as well as Commission orders. Nothing in this Section precludes consideration of contracts longer than 5 years and related forecast data. Unless specified otherwise in this Section, in the procurement plan or in the implementing tariff, any procurement occurring in accordance with this plan shall be competitively bid through a request for proposals process. Approval and implementation of the procurement plan shall be subject to review and approval by the Commission according to the provisions set forth in this Section. A procurement plan shall include each of the following components:

(1) Hourly load analysis. This analysis shall include:

(i) multi-year historical analysis of hourly loads;

(ii) switching trends and competitive retail market analysis;

(iii) known or projected changes to future loads; and

(iv) growth forecasts by customer class.

(2) Analysis of the impact of any demand side and renewable energy initiatives. This analysis shall include:

(i) the impact of demand response programs and energy efficiency programs, both current and projected; for small multi-jurisdictional utilities, the impact of demand response and energy efficiency programs approved pursuant to Section 8-408 of this Act, both current and projected; and

(ii) supply side needs that are projected to be offset by purchases of renewable energy resources, if any.

(3) A plan for meeting the expected load requirements that will not be met through preexisting contracts. This plan shall include:

(i) definitions of the different Illinois retail customer classes for which supply is being purchased;

(ii) the proposed mix of demand-response products for which contracts will be executed during the next year. For small multi-jurisdictional electric utilities that on December 31, 2005 served fewer than 100,000 customers in Illinois, these shall be defined as demand-response products offered in an energy efficiency plan approved pursuant to Section 8-408 of this Act. The cost-effective demand-response measures shall be procured whenever the cost is lower than procuring comparable capacity products, provided that such products shall:

(A) be procured by a demand-response provider from those retail customers included in the plan's electric supply service requirements;

(B) at least satisfy the demand-response requirements of the regional transmission organization market in which the utility's service territory is located, including, but not limited to, any applicable capacity or dispatch requirements;

(C) provide for customers' participation in the stream of benefits produced by the demand-response products;

(D) provide for reimbursement by the demand-response provider of the utility for any costs incurred as a result of the failure of the supplier of such products to perform its obligations thereunder; and

(E) meet the same credit requirements as apply to suppliers of capacity, in the applicable regional transmission organization market;

(iii) monthly forecasted system supply requirements, including expected minimum, maximum, and average values for the planning period;

(iv) the proposed mix and selection of standard wholesale products for which contracts will be executed during the next year, separately or in combination, to meet that portion of its load requirements not met through pre-existing contracts, including but not limited to monthly 5 x 16 peak period block energy, monthly off-peak wrap energy, monthly 7 x 24 energy, annual 5 x 16 energy, other standardized energy or capacity products designed to provide eligible retail customer benefits from commercially deployed advanced technologies including but not limited to high voltage direct current converter stations, as such term is defined in Section 1-10 of the Illinois Power Agency Act, whether or not such product is currently available in wholesale markets, annual off-peak wrap energy, annual 7 x 24 energy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchase plan, and ancillary services; however, nothing in this item (iv) precludes consideration of long-term contracts with a length up to and including 20 years for clean energy, as defined in Section 1-10 of the Illinois Power Agency Act, with an appropriate portion of the portfolio to be allocated to such long-term contracts;

(v) proposed term structures for each wholesale product type included in the proposed procurement plan portfolio of products; and

(vi) an assessment of the price risk, load uncertainty, and other factors that are associated with the proposed procurement plan; this assessment, to the extent possible, shall include an analysis of the following factors: contract terms, time frames for securing products or services, fuel costs, weather patterns, transmission costs, market conditions, and the governmental regulatory environment; the proposed procurement plan shall also identify alternatives for those portfolio measures that are identified as having significant price risk and mitigation in the form of additional retail customer and ratepayer price, reliability, and environmental benefits from standardized energy products delivered from commercially deployed advanced technologies, including, but not limited to, high voltage direct current converter stations, as such term is defined in Section 1-10 of the Illinois Power Agency Act, whether or not such product is currently available in wholesale markets; and.

(v) for procurement events beginning after May 31, 2025, consideration of whether products offered into the procurement process are renewable energy resources, as defined in Section 1-10 of the Illinois Power Agency Act that might otherwise qualify for the renewable portfolio standard described in subparagraphs (c)(1)(I) and (c)(1)(J) of Section 1-75 of the Illinois Power Agency Act where such product or products can be procured at or near the price of nonrenewable energy after taking account of the social cost of carbon as set forth in subparagraph (B) of paragraph (1) of subsection (d-5) of Section 1-75 of the Illinois Power Agency Act. The Agency shall consider fuel volatility, long-term trends in non-renewable energy resource pricing, and the environmental benefits of renewable energy resources when comparing products and may, in doing so, select products comprised of renewable energy resources that are at a higher fixed price over a longer duration. Each product procured shall include all environmental attributes, including, but not limited to, and renewable energy credits, all as defined in Section 1-10 of the Illinois Power Agency Act, and all credits, characteristics, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation of the product procured or its displacement of generation.

(4) Proposed procedures for balancing loads. The procurement plan shall include, for load requirements included in the procurement plan, the process for (i) hourly balancing of supply and demand and (ii) the criteria for portfolio re-balancing in the event of significant shifts in load.

(5) Long-Term Renewable Resources Procurement Plan. The Agency shall prepare a long-term renewable resources procurement plan for the procurement of renewable energy credits under Sections 1-56 and 1-75 of the Illinois Power Agency Act for delivery beginning in the 2017 delivery year.

(i) The initial long-term renewable resources procurement plan and all subsequent revisions shall be subject to review and approval by the Commission. For the purposes of this Section, "delivery year" has the same meaning as in Section 1-10 of the Illinois Power Agency Act. For purposes of this Section, "Agency" shall mean the Illinois Power Agency.

(ii) The long-term renewable resources planning process shall be conducted as follows:

(A) Electric utilities shall provide a range of load forecasts to the Illinois Power Agency within 45 days of the Agency's request for forecasts, which request shall specify the length and conditions for the forecasts including, but not limited to, the quantity of distributed generation expected to be interconnected for each year.

(B) The Agency shall publish for comment the initial long-term renewable resources procurement plan no later than 120 days after the effective date of this amendatory Act of the 99th General Assembly and shall review, and may revise, the plan at least every 2 years thereafter. To the extent practicable, the Agency shall review and propose any revisions to the long-term renewable energy resources procurement plan in conjunction with the Agency's other planning and approval processes conducted under this Section. The initial long-term renewable resources procurement plan shall:

(aa) Identify the procurement programs and competitive procurement events consistent with the applicable requirements of the Illinois Power Agency Act and shall be designed to achieve the goals set forth in subsection (c) of Section 1-75 of that Act.

(bb) Include a schedule for procurements for renewable energy credits from utility-scale wind projects, utility-scale solar projects, and brownfield site photovoltaic projects consistent with subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.

(cc) Identify the process whereby the Agency will submit to the Commission for review and approval the proposed contracts to implement the programs required by such plan.

Copies of the initial long-term renewable resources procurement plan and all subsequent revisions shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also be provided to each affected electric utility. An affected utility and other interested parties shall have 45 days following the date of posting to provide comment to the Agency on the initial long-term renewable resources procurement plan and all subsequent revisions. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. During this 45-day comment period, the Agency shall hold at least one public hearing within each utility's service area that is subject to the requirements of this paragraph (5) for the purpose of receiving public comment. Within 21 days following the end of the 45-day review period, the Agency may revise the long-term renewable resources procurement plan based on the comments received and shall file the plan with the Commission for review and approval.

(C) Within 14 days after the filing of the initial long-term renewable resources procurement plan or any subsequent revisions, any person objecting to the plan may file an objection with the Commission. Within 21 days after the filing of the plan, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the initial long-term renewable resources procurement plan or any subsequent revisions within 120 days after the filing of the plan by the Illinois Power Agency.

(D) The Commission shall approve the initial long-term renewable resources procurement plan and any subsequent revisions, including expressly the forecast used in the plan and taking into account that funding will be limited to the amount of revenues actually collected by the utilities, if the Commission determines that the plan will reasonably and prudently accomplish the requirements of Section 1-56 and subsection (c) of Section 1-75 of the Illinois Power Agency Act. The Commission shall also approve the process for the submission, review, and approval of the proposed contracts to procure renewable energy credits or implement the programs authorized by the Commission pursuant to a long-term renewable resources procurement plan approved under this Section.

In approving any long-term renewable resources procurement plan after the effective date of this amendatory Act of the 102nd General Assembly, the Commission shall approve or modify the Agency's proposal for minimum equity standards pursuant to subsection (c-10) of Section 1-75 of the Illinois Power Agency Act. The Commission shall consider any analysis performed by the Agency in developing its proposal, including past performance, availability of equity eligible contractors, and availability of equity eligible persons at the time the long-term renewable resources procurement plan is approved.

(iii) The Agency or third parties contracted by the Agency shall implement all programs authorized by the Commission in an approved long-term renewable resources procurement plan without further review and approval by the Commission. Third parties shall not begin implementing any programs or receive any payment under this Section until the Commission has approved the contract or contracts under the process authorized by the Commission in item (D) of subparagraph (ii) of paragraph (5) of this subsection (b) and the third party and the Agency or utility, as applicable, have executed the contract. For those renewable energy credits subject to procurement through a competitive bid process under the plan or under the initial forward procurements for wind and solar resources described in subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act, the Agency shall follow the procurement process specified in the provisions relating to electricity procurement in subsections (e) through (i) of this Section.

(iv) An electric utility shall recover its costs associated with the procurement of renewable energy credits under this Section and pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act through an automatic adjustment clause tariff under subsection (k) or a tariff pursuant to subsection (i-5), as applicable, of Section 16-108 of this Act. A utility shall not be required to advance any payment or pay any amounts under this Section that exceed the actual amount of revenues collected by the utility under paragraph (6) of subsection (c) of Section 1-75 of the Illinois Power Agency Act, subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, and subsection (k) or subsection (i-5), as applicable, of Section 16-108 of this Act, and contracts executed under this Section shall expressly incorporate this limitation.

(v) For the public interest, safety, and welfare, the Agency and the Commission may adopt rules to carry out the provisions of this Section on an emergency basis immediately following the effective date of this amendatory Act of the 99th General Assembly.

(vi) On or before July 1 of each year, the Commission shall hold an informal hearing for the purpose of receiving comments on the prior year's procurement process and any recommendations for change.

(b-5) An electric utility that as of January 1, 2019 served more than 300,000 retail customers in this State shall purchase renewable energy credits from new renewable energy facilities constructed at or adjacent to the sites of coal-fueled electric generating facilities in this State in accordance with subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. Except as expressly provided in this Section, the plans and procedures for such procurements shall not be included in the procurement plans provided for in this Section, but rather shall be conducted and implemented solely in accordance with subsection (c-5) of Section 1-75 of the Illinois Power Agency Act.

(b-10) Capacity procurement.

(1) Definitions. For purposes of this subsection:

"Applicable Local Resource Zone" means the Zone 4 Local Resource Zone as set forth in the MISO Business Practices Manual 011 - Resource Adequacy, or any future successor zone for the same geographic space, as designated by MISO governing documents.

"Applicable locational deliverability area" means the ComEd Locational Deliverability Area as set forth in the PJM Manual, or any future successor area for the same geographic space, as designated by PJM governing documents.

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

"Fixed Resource Adequacy Plan", "Local Clearing Requirement", "Local Resource Zone", "Planning Resource", and "Planning Reserve Margin Requirement" have the meanings given to those terms in the MISO Tariff, including as they may apply to individual Load Serving Entities, as applicable. For avoidance of doubt, these terms shall be interpreted as multiple seasonal values within a given delivery year if MISO's then-prevailing resource adequacy construct has a seasonal component.

"Load Serving Entity" has the meaning given to that term by the regional transmission organization where the entity serves customers, either in the Midcontinent Independent System Operator Tariff or PJM Interconnection, LLC Reliability Assurance Agreement.

(c) The provisions of this subsection (c) shall not apply to procurements conducted pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. However, the Agency may retain a procurement administrator to assist the Agency in planning and carrying out the procurement events and implementing the other requirements specified in such subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, with the costs incurred by the Agency for the procurement administrator to be recovered through fees charged to applicants for selection to sell and deliver renewable energy credits to electric utilities pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. The procurement process set forth in Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section shall be administered by a procurement administrator and monitored by a procurement monitor.

(1) The procurement administrator shall:

(i) design the final procurement process in accordance with Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section following Commission approval of the procurement plan;

(ii) develop benchmarks in accordance with subsection (e)(3) to be used to evaluate bids; these benchmarks shall be submitted to the Commission for review and approval on a confidential basis prior to the procurement event;

(iii) serve as the interface between the electric utility and suppliers;

(iv) manage the bidder pre-qualification and registration process;

(v) obtain the electric utilities' agreement to the final form of all supply contracts and credit collateral agreements;

(vi) administer the request for proposals process;

(vii) have the discretion to negotiate to determine whether bidders are willing to lower the price of bids that meet the benchmarks approved by the Commission; any post-bid negotiations with bidders shall be limited to price only and shall be completed within 24 hours after opening the sealed bids and shall be conducted in a fair and unbiased manner; in conducting the negotiations, there shall be no disclosure of any information derived from proposals submitted by competing bidders; if information is disclosed to any bidder, it shall be provided to all competing bidders;

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

(ix) submit a confidential report to the Commission recommending acceptance or rejection of bids;

(x) notify the utility of contract counterparties and contract specifics; and

(xi) administer related contingency procurement events.

(2) The procurement monitor, who shall be retained by the Commission, shall:

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

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

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

(iv) assess compliance with the procurement plans approved by the Commission for each utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois and for each small multi-jurisdictional utility that on December 31, 2005 served less than 100,000 customers in Illinois;

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

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

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

(d) Except as provided in subsection (j), the planning process shall be conducted as follows:

(1) Beginning in 2008, each Illinois utility procuring power pursuant to this Section shall annually provide a range of load forecasts to the Illinois Power Agency by July 15 of each year, or such other date as may be required by the Commission or Agency. The load forecasts shall cover the 5-year procurement planning period for the next procurement plan and shall include hourly data representing a high-load, low-load, and expected-load scenario for the load of those retail customers included in the plan's electric supply service requirements. The utility shall provide supporting data and assumptions for each of the scenarios.

(2) Beginning in 2008, the Illinois Power Agency shall prepare a procurement plan by August 15th of each year, or such other date as may be required by the Commission. The procurement plan shall identify the portfolio of demand-response and power and energy products to be procured. Cost-effective demand-response measures shall be procured as set forth in item (iii) of subsection (b) of this Section. Copies of the procurement plan shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also be provided to each affected electric utility. An affected utility shall have 30 days following the date of posting to provide comment to the Agency on the procurement plan. Other interested entities also may comment on the procurement plan. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. During this 30-day comment period, the Agency shall hold at least one public hearing within each utility's service area for the purpose of receiving public comment on the procurement plan. Within 14 days following the end of the 30-day review period, the Agency shall revise the procurement plan as necessary based on the comments received and file the procurement plan with the Commission and post the procurement plan on the websites.

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

(4) The Commission shall approve the procurement plan, including expressly the forecast used in the procurement plan, if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.

(4.5) The Commission shall review the Agency's recommendations for the selection of applicants to enter into long-term contracts for the sale and delivery of renewable energy credits from new renewable energy facilities to be constructed at or adjacent to the sites of coal-fueled electric generating facilities in this State in accordance with the provisions of subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, and shall approve the Agency's recommendations if the Commission determines that the applicants recommended by the Agency for selection, the proposed new renewable energy facilities to be constructed, the amounts of renewable energy credits to be delivered pursuant to the contracts, and the other terms of the contracts, are consistent with the requirements of subsection (c-5) of Section 1-75 of the Illinois Power Agency Act.

(e) The procurement process shall include each of the following components:

(1) Solicitation, pre-qualification, and registration of bidders. The procurement administrator shall disseminate information to potential bidders to promote a procurement event, notify potential bidders that the procurement administrator may enter into a post-bid price negotiation with bidders that meet the applicable benchmarks, provide supply requirements, and otherwise explain the competitive procurement process. In addition to such other publication as the procurement administrator determines is appropriate, this information shall be posted on the Illinois Power Agency's and the Commission's websites. The procurement administrator shall also administer the prequalification process, including evaluation of credit worthiness, compliance with procurement rules, and agreement to the standard form contract developed pursuant to paragraph (2) of this subsection (e). The procurement administrator shall then identify and register bidders to participate in the procurement event.

(2) Standard contract forms and credit terms and instruments. The procurement administrator, in consultation with the utilities, the Commission, and other interested parties and subject to Commission oversight, shall develop and provide standard contract forms for the supplier contracts that meet generally accepted industry practices. Standard credit terms and instruments that meet generally accepted industry practices shall be similarly developed. The procurement administrator shall make available to the Commission all written comments it receives on the contract forms, credit terms, or instruments. If the procurement administrator cannot reach agreement with the applicable electric utility as to the contract terms and conditions, the procurement administrator must notify the Commission of any disputed terms and the Commission shall resolve the dispute. The terms of the contracts shall not be subject to negotiation by winning bidders, and the bidders must agree to the terms of the contract in advance so that winning bids are selected solely on the basis of price.

(3) Establishment of a market-based price benchmark. As part of the development of the procurement process, the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor, shall establish benchmarks for evaluating the final prices in the contracts for each of the products that will be procured through the procurement process. The benchmarks shall be based on price data for similar products for the same delivery period and same delivery hub, or other delivery hubs after adjusting for that difference. The price benchmarks may also be adjusted to take into account differences between the information reflected in the underlying data sources and the specific products and procurement process being used to procure power for the Illinois utilities. The benchmarks shall be confidential but shall be provided to, and will be subject to Commission review and approval, prior to a procurement event.

(4) Request for proposals competitive procurement process. The procurement administrator shall design and issue a request for proposals to supply electricity in accordance with each utility's procurement plan, as approved by the Commission. The request for proposals shall set forth a procedure for sealed, binding commitment bidding with pay-as-bid settlement, and provision for selection of bids on the basis of price.

(5) A plan for implementing contingencies in the event of supplier default or failure of the procurement process to fully meet the expected load requirement due to insufficient supplier participation, Commission rejection of results, or any other cause.

(i) Event of supplier default: In the event of supplier default, the utility shall review the contract of the defaulting supplier to determine if the amount of supply is 200 megawatts or greater, and if there are more than 60 days remaining of the contract term. If both of these conditions are met, and the default results in termination of the contract, the utility shall immediately notify the Illinois Power Agency that a request for proposals must be issued to procure replacement power, and the procurement administrator shall run an additional procurement event. If the contracted supply of the defaulting supplier is less than 200 megawatts or there are less than 60 days remaining of the contract term, the utility shall procure power and energy from the applicable regional transmission organization market, including ancillary services, capacity, and day-ahead or real time energy, or both, for the duration of the contract term to replace the contracted supply; provided, however, that if a needed product is not available through the regional transmission organization market it shall be purchased from the wholesale market.

(ii) Failure of the procurement process to fully meet the expected load requirement: If the procurement process fails to fully meet the expected load requirement due to insufficient supplier participation or due to a Commission rejection of the procurement results, the procurement administrator, the procurement monitor, and the Commission staff shall meet within 10 days to analyze potential causes of low supplier interest or causes for the Commission decision. If changes are identified that would likely result in increased supplier participation, or that would address concerns causing the Commission to reject the results of the prior procurement event, the procurement administrator may implement those changes and rerun the request for proposals process according to a schedule determined by those parties and consistent with Section 1-75 of the Illinois Power Agency Act and this subsection. In any event, a new request for proposals process shall be implemented by the procurement administrator within 90 days after the determination that the procurement process has failed to fully meet the expected load requirement.

(iii) In all cases where there is insufficient supply provided under contracts awarded through the procurement process to fully meet the electric utility's load requirement, the utility shall meet the load requirement by procuring power and energy from the applicable regional transmission organization market, including ancillary services, capacity, and day-ahead or real time energy, or both; provided, however, that if a needed product is not available through the regional transmission organization market it shall be purchased from the wholesale market.

(6) The procurement processes described in this subsection and in subsection (c-5) of Section 1-75 of the Illinois Power Agency Act are exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-10 of that Code.

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

(g) Within 3 business days after the Commission decision approving the results of a procurement event, the utility shall enter into binding contractual arrangements with the winning suppliers using the standard form contracts; except that the utility shall not be required either directly or indirectly to execute the contracts if a tariff that is consistent with subsection (l) of this Section has not been approved and placed into effect for that utility.

(h) For the procurement of standard wholesale products, the names of the successful bidders and the load weighted average of the winning bid prices for each contract type and for each contract term shall be made available to the public at the time of Commission approval of a procurement event. For procurements conducted to meet the requirements of subsection (b) of Section 1-56 or subsection (c) of Section 1-75 of the Illinois Power Agency Act governed by the provisions of this Section, the address and nameplate capacity of the new renewable energy generating facility proposed by a winning bidder shall also be made available to the public at the time of Commission approval of a procurement event, along with the business address and contact information for any winning bidder. An estimate or approximation of the nameplate capacity of the new renewable energy generating facility may be disclosed if necessary to protect the confidentiality of individual bid prices.

The Commission, the procurement monitor, the procurement administrator, the Illinois Power Agency, and all participants in the procurement process shall maintain the confidentiality of all other supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs. Confidential information, including the confidential reports submitted by the procurement administrator and procurement monitor pursuant to subsection (f) of this Section, shall not be made publicly available and shall not be discoverable by any party in any proceeding, absent a compelling demonstration of need, nor shall those reports be admissible in any proceeding other than one for law enforcement purposes.

(i) Within 2 business days after a Commission decision approving the results of a procurement event or such other date as may be required by the Commission from time to time, the utility shall file for informational purposes with the Commission its actual or estimated retail supply charges, as applicable, by customer supply group reflecting the costs associated with the procurement and computed in accordance with the tariffs filed pursuant to subsection (l) of this Section and approved by the Commission.

(j) Within 60 days following August 28, 2007 (the effective date of Public Act 95-481), each electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois shall prepare and file with the Commission an initial procurement plan, which shall conform in all material respects to the requirements of the procurement plan set forth in subsection (b); provided, however, that the Illinois Power Agency Act shall not apply to the initial procurement plan prepared pursuant to this subsection. The initial procurement plan shall identify the portfolio of power and energy products to be procured and delivered for the period June 2008 through May 2009, and shall identify the proposed procurement administrator, who shall have the same experience and expertise as is required of a procurement administrator hired pursuant to Section 1-75 of the Illinois Power Agency Act. Copies of the procurement plan shall be posted and made publicly available on the Commission's website. The initial procurement plan may include contracts for renewable resources that extend beyond May 2009.

(i) Within 14 days following filing of the initial procurement plan, any person may file a detailed objection with the Commission contesting the procurement plan submitted by the electric utility. All objections to the electric utility's plan shall be specific, supported by data or other detailed analyses. The electric utility may file a response to any objections to its procurement plan within 7 days after the date objections are due to be filed. Within 7 days after the date the utility's response is due, the Commission shall determine whether a hearing is necessary. If it determines that a hearing is necessary, it shall require the hearing to be completed and issue an order on the procurement plan within 60 days after the filing of the procurement plan by the electric utility.

(ii) The order shall approve or modify the procurement plan, approve an independent procurement administrator, and approve or modify the electric utility's tariffs that are proposed with the initial procurement plan. The Commission shall approve the procurement plan if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.

(k) (Blank).

(k-5) (Blank).

(l) An electric utility shall recover its costs incurred under this Section and subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, including, but not limited to, the costs of procuring power and energy demand-response resources under this Section and its costs for purchasing renewable energy credits pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. The utility shall file with the initial procurement plan its proposed tariffs through which its costs of procuring power that are incurred pursuant to a Commission-approved procurement plan and those other costs identified in this subsection (l), will be recovered. The tariffs shall include a formula rate or charge designed to pass through both the costs incurred by the utility in procuring a supply of electric power and energy for the applicable customer classes with no mark-up or return on the price paid by the utility for that supply, plus any just and reasonable costs that the utility incurs in arranging and providing for the supply of electric power and energy. The formula rate or charge shall also contain provisions that ensure that its application does not result in over or under recovery due to changes in customer usage and demand patterns, and that provide for the correction, on at least an annual basis, of any accounting errors that may occur. A utility shall recover through the tariff all reasonable costs incurred to implement or comply with any procurement plan that is developed and put into effect pursuant to Section 1-75 of the Illinois Power Agency Act and this Section, and for the procurement of renewable energy credits pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, including any fees assessed by the Illinois Power Agency, costs associated with load balancing, and contingency plan costs. The electric utility shall also recover its full costs of procuring electric supply for which it contracted before the effective date of this Section in conjunction with the provision of full requirements service under fixed-price bundled service tariffs subsequent to December 31, 2006. All such costs shall be deemed to have been prudently incurred. The pass-through tariffs that are filed and approved pursuant to this Section shall not be subject to review under, or in any way limited by, Section 16-111(i) of this Act. All of the costs incurred by the electric utility associated with the purchase of zero emission credits in accordance with subsection (d-5) of Section 1-75 of the Illinois Power Agency Act, all costs incurred by the electric utility associated with the purchase of carbon mitigation credits in accordance with subsection (d-10) of Section 1-75 of the Illinois Power Agency Act, and, beginning June 1, 2017, all of the costs incurred by the electric utility associated with the purchase of renewable energy resources in accordance with Sections 1-56 and 1-75 of the Illinois Power Agency Act, and all of the costs incurred by the electric utility in purchasing renewable energy credits in accordance with subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, shall be recovered through the electric utility's tariffed charges applicable to all of its retail customers, as specified in subsection (k) or subsection (i-5), as applicable, of Section 16-108 of this Act, and shall not be recovered through the electric utility's tariffed charges for electric power and energy supply to its eligible retail customers.

(m) The Commission has the authority to adopt rules to carry out the provisions of this Section. For the public interest, safety, and welfare, the Commission also has authority to adopt rules to carry out the provisions of this Section on an emergency basis immediately following August 28, 2007 (the effective date of Public Act 95-481).

(n) Notwithstanding any other provision of this Act, any affiliated electric utilities that submit a single procurement plan covering their combined needs may procure for those combined needs in conjunction with that plan, and may enter jointly into power supply contracts, purchases, and other procurement arrangements, and allocate capacity and energy and cost responsibility therefor among themselves in proportion to their requirements.

(o) On or before June 1 of each year, the Commission shall hold an informal hearing for the purpose of receiving comments on the prior year's procurement process and any recommendations for change.

(p) An electric utility subject to this Section may propose to invest, lease, own, or operate an electric generation facility as part of its procurement plan, provided the utility demonstrates that such facility is the least-cost option to provide electric service to those retail customers included in the plan's electric supply service requirements. If the facility is shown to be the least-cost option and is included in a procurement plan prepared in accordance with Section 1-75 of the Illinois Power Agency Act and this Section, then the electric utility shall make a filing pursuant to Section 8-406 of this Act, and may request of the Commission any statutory relief required thereunder. If the Commission grants all of the necessary approvals for the proposed facility, such supply shall thereafter be considered as a pre-existing contract under subsection (b) of this Section. The Commission shall in any order approving a proposal under this subsection specify how the utility will recover the prudently incurred costs of investing in, leasing, owning, or operating such generation facility through just and reasonable rates charged to those retail customers included in the plan's electric supply service requirements. Cost recovery for facilities included in the utility's procurement plan pursuant to this subsection shall not be subject to review under or in any way limited by the provisions of Section 16-111(i) of this Act. Nothing in this Section is intended to prohibit a utility from filing for a fuel adjustment clause as is otherwise permitted under Section 9-220 of this Act.

(q) If the Illinois Power Agency filed with the Commission, under Section 16-111.5 of this Act, its proposed procurement plan for the period commencing June 1, 2017, and the Commission has not yet entered its final order approving the plan on or before the effective date of this amendatory Act of the 99th General Assembly, then the Illinois Power Agency shall file a notice of withdrawal with the Commission, after the effective date of this amendatory Act of the 99th General Assembly, to withdraw the proposed procurement of renewable energy resources to be approved under the plan, other than the procurement of renewable energy credits from distributed renewable energy generation devices using funds previously collected from electric utilities' retail customers that take service pursuant to electric utilities' hourly pricing tariff or tariffs and, for an electric utility that serves less than 100,000 retail customers in the State, other than the procurement of renewable energy credits from distributed renewable energy generation devices. Upon receipt of the notice, the Commission shall enter an order that approves the withdrawal of the proposed procurement of renewable energy resources from the plan. The initially proposed procurement of renewable energy resources shall not be approved or be the subject of any further hearing, investigation, proceeding, or order of any kind.

This amendatory Act of the 99th General Assembly preempts and supersedes any order entered by the Commission that approved the Illinois Power Agency's procurement plan for the period commencing June 1, 2017, to the extent it is inconsistent with the provisions of this amendatory Act of the 99th General Assembly. To the extent any previously entered order approved the procurement of renewable energy resources, the portion of that order approving the procurement shall be void, other than the procurement of renewable energy credits from distributed renewable energy generation devices using funds previously collected from electric utilities' retail customers that take service under electric utilities' hourly pricing tariff or tariffs and, for an electric utility that serves less than 100,000 retail customers in the State, other than the procurement of renewable energy credits for distributed renewable energy generation devices.

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

(220 ILCS 5/16-115A)

Sec. 16-115A. Obligations of alternative retail electric suppliers.

(a) An alternative retail electric supplier:

(i) shall comply with the requirements imposed on public utilities by Sections 8-201 through 8-207, 8-301, 8-505 and 8-507 of this Act, to the extent that these Sections have application to the services being offered by the alternative retail electric supplier;

(ii) shall continue to comply with the requirements for certification stated in subsection (d) of Section 16-115;

(iii) by May 31, 2020 and every June 30 thereafter, shall submit to the Commission and the Office of the Attorney General the rates the retail electric supplier charged to residential customers in the prior year, including each distinct rate charged and whether the rate was a fixed or variable rate, the basis for the variable rate, and any fees charged in addition to the supply rate, including monthly fees, flat fees, or other service charges; and

(iv) shall make publicly available on its website, without the need for a customer login, rate information for all of its variable, time-of-use, and fixed rate contracts currently available to residential customers, including, but not limited to, fixed monthly charges, early termination fees, and kilowatt-hour charges; and

(v) shall retire all renewable energy credits, as defined in Section 1-10 of the Illinois Power Agency Act, and any other environmental attributes of the energy supply procured from renewable energy resources in compliance with subsection (h) of this Section.

(b) An alternative retail electric supplier shall obtain verifiable authorization from a customer, in a form or manner approved by the Commission consistent with Section 2EE of the Consumer Fraud and Deceptive Business Practices Act, before the customer is switched from another supplier.

(c) No alternative retail electric supplier, or electric utility other than the electric utility in whose service area a customer is located, shall (i) enter into or employ any arrangements which have the effect of preventing a retail customer with a maximum electrical demand of less than one megawatt from having access to the services of the electric utility in whose service area the customer is located or (ii) charge retail customers for such access. This subsection shall not be construed to prevent an arms-length agreement between a supplier and a retail customer that sets a term of service, notice period for terminating service and provisions governing early termination through a tariff or contract as allowed by Section 16-119.

(d) An alternative retail electric supplier that is certified to serve residential or small commercial retail customers shall not:

(1) deny service to a customer or group of customers nor establish any differences as to prices, terms, conditions, services, products, facilities, or in any other respect, whereby such denial or differences are based upon race, gender or income, except as provided in Section 16-115E.

(2) deny service to a customer or group of customers based on locality nor establish any unreasonable difference as to prices, terms, conditions, services, products, or facilities as between localities.

(3) warrant that it has a residential customer or small commercial retail customer's express consent agreement to access interval data as described in subsection (b) of Section 16-122, unless the alternative retail electric supplier has:

(A) disclosed to the consumer at the outset of the offer that the alternative retail electric supplier will access the consumer's interval data from the consumer's utility with the consumer's express agreement and the consumer's option to refuse to provide express agreement to access the consumer's interval data; and

(B) obtained the consumer's express agreement for the alternative retail electric supplier to access the consumer's interval data from the consumer's utility in a separate letter of agency, a distinct response to a third-party verification, or as a separate affirmative consent during a recorded enrollment initiated by the consumer. The disclosure by the alternative retail electric supplier to the consumer in this Section shall be conducted in, translated into, and provided in a language in which the consumer subject to the disclosure is able to understand and communicate.

(4) release, sell, license, or otherwise disclose any customer interval data obtained under Section 16-122 to any third person except as provided for in Section 16-122 and paragraphs (1) through (4) of subsection (d-5) of Section 2EE of the Consumer Fraud and Deceptive Business Practices Act.

(e) An alternative retail electric supplier shall comply with the following requirements with respect to the marketing, offering and provision of products or services to residential and small commercial retail customers:

(i) All marketing materials, including, but not limited to, electronic marketing materials, in-person solicitations, and telephone solicitations, shall contain information that adequately discloses the prices, terms, and conditions of the products or services that the alternative retail electric supplier is offering or selling to the customer and shall disclose the current utility electric supply price to compare applicable at the time the alternative retail electric supplier is offering or selling the products or services to the customer and shall disclose the date on which the utility electric supply price to compare became effective and the date on which it will expire. The utility electric supply price to compare shall be the sum of the electric supply charge and the transmission services charge and shall not include the purchased electricity adjustment. The disclosure shall include a statement that the price to compare does not include the purchased electricity adjustment, and, if applicable, the range of the purchased electricity adjustment. All marketing materials, including, but not limited to, electronic marketing materials, in-person solicitations, and telephone solicitations, shall include the following statement:

"(Name of the alternative retail electric supplier) is not the same entity as your electric delivery company. You are not required to enroll with (name of alternative retail electric supplier). Beginning on (effective date), the electric supply price to compare is (price in cents per kilowatt hour). The electric utility electric supply price will expire on (expiration date). The utility electric supply price to compare does not include the purchased electricity adjustment factor. For more information go to the Illinois Commerce Commission's free website at www.pluginillinois.org.".

If applicable, the statement shall also include the following statement:

"The purchased electricity adjustment factor may range between +.5 cents and -.5 cents per kilowatt hour.".

This paragraph (i) does not apply to goodwill or institutional advertising.

(ii) Before any customer is switched from another supplier, the alternative retail electric supplier shall give the customer written information that adequately discloses, in plain language, the prices, terms and conditions of the products and services being offered and sold to the customer. This written information shall be provided in a language in which the customer subject to the marketing or solicitation is able to understand and communicate, and the alternative retail electric supplier shall not switch a customer who is unable to understand and communicate in a language in which the marketing or solicitation was conducted. The alternative retail electric supplier shall comply with Section 2N of the Consumer Fraud and Deceptive Business Practices Act.

(iii) An alternative retail electric supplier shall provide documentation to the Commission and to customers that substantiates any claims made by the alternative retail electric supplier regarding the technologies and fuel types used to generate the electricity offered or sold to customers.

(iv) The alternative retail electric supplier shall provide to the customer (1) itemized billing statements that describe the products and services provided to the customer and their prices, and (2) an additional statement, at least annually, that adequately discloses the average monthly prices, and the terms and conditions, of the products and services sold to the customer.

(v) All in-person and telephone solicitations shall be conducted in, translated into, and provided in a language in which the consumer subject to the marketing or solicitation is able to understand and communicate. An alternative retail electric supplier shall terminate a solicitation if the consumer subject to the marketing or communication is unable to understand and communicate in the language in which the marketing or solicitation is being conducted. An alternative retail electric supplier shall comply with Section 2N of the Consumer Fraud and Deceptive Business Practices Act.

(vi) Each alternative retail electric supplier shall conduct training for individual representatives engaged in in-person solicitation and telemarketing to residential customers on behalf of that alternative retail electric supplier prior to conducting any such solicitations on the alternative retail electric supplier's behalf. Each alternative retail electric supplier shall submit a copy of its training material to the Commission on an annual basis and the Commission shall have the right to review and require updates to the material. After initial training, each alternative retail electric supplier shall be required to conduct refresher training for its individual representatives every 6 months.

(f) An alternative retail electric supplier may limit the overall size or availability of a service offering by specifying one or more of the following: a maximum number of customers, maximum amount of electric load to be served, time period during which the offering will be available, or other comparable limitation, but not including the geographic locations of customers within the area which the alternative retail electric supplier is certificated to serve. The alternative retail electric supplier shall file the terms and conditions of such service offering including the applicable limitations with the Commission prior to making the service offering available to customers.

(g) Nothing in this Section shall be construed as preventing an alternative retail electric supplier, which is an affiliate of, or which contracts with, (i) an industry or trade organization or association, (ii) a membership organization or association that exists for a purpose other than the purchase of electricity, or (iii) another organization that meets criteria established in a rule adopted by the Commission, from offering through the organization or association services at prices, terms and conditions that are available solely to the members of the organization or association.

(h) For all potentially eligible retail customers, as defined in Section 16-111.5, served by an alternative retail electric supplier, or electric utility other than the electric utility in whose service area a customer is located, such supplier or utility shall purchase products that include the same percentage of renewable energy resources, as defined in Section 1-10 of the Illinois Power Agency Act, as was procured for the utility in whose service area such customers are located for the immediately prior delivery year. Such clean energy shall include all environmental attributes as described in Section 16-111.5 and match the eligibility criteria of resources eligible for the renewable portfolio standard described in subsections (c)(I) and (c)(J) of Section 1-75 of the Illinois Power Agency Act.

(Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)

(220 ILCS 5/16-115D)

Sec. 16-115D. Renewable portfolio standard for alternative retail electric suppliers and electric utilities operating outside their service territories.

(a) An alternative retail electric supplier shall be responsible for procuring cost-effective renewable energy resources as required under item (5) of subsection (d) of Section 16-115 of this Act as outlined herein:

(1) The definition of renewable energy resources contained in Section 1-10 of the Illinois Power Agency Act applies to all renewable energy resources required to be procured by alternative retail electric suppliers.

(2) Through May 31, 2017, the quantity of renewable energy resources shall be measured as a percentage of the actual amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of this subsection (a).

(3) Through May 31, 2017, the quantity of renewable energy resources shall be in amounts at least equal to the annual percentages set forth in item (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. At least 60% of the renewable energy resources procured pursuant to items (1) and (3) of subsection (b) of this Section shall come from wind generation and, starting June 1, 2015, at least 6% of the renewable energy resources procured pursuant to items (1) and (3) of subsection (b) of this Section shall come from solar photovoltaics. If, in any given year, an alternative retail electric supplier does not purchase at least these levels of renewable energy resources, then the alternative retail electric supplier shall make alternative compliance payments, as described in subsection (d) of this Section.

(3.5) For the delivery year commencing June 1, 2017, the quantity of renewable energy resources shall be at least 13.0% of the uncovered amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year, which uncovered amount shall equal 50% of such metered electricity delivered by the alternative retail electric supplier. For the delivery year commencing June 1, 2018, the quantity of renewable energy resources shall be at least 14.5% of the uncovered amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year, which uncovered amount shall equal 25% of such metered electricity delivered by the alternative retail electric supplier. At least 32% of the renewable energy resources procured by the alternative retail electric supplier for its uncovered portion under this paragraph (3.5) shall come from wind or photovoltaic generation. The renewable energy resources procured under this paragraph (3.5) shall not include any resources from a facility whose costs were being recovered through rates regulated by any state or states on or after January 1, 2017.

(4) The quantity and source of renewable energy resources shall be independently verified through the PJM Environmental Information System Generation Attribute Tracking System (PJM-GATS) or the Midwest Renewable Energy Tracking System (M-RETS), which shall document the location of generation, resource type, month, and year of generation for all qualifying renewable energy resources that an alternative retail electric supplier uses to comply with this Section. No later than June 1, 2009, the Illinois Power Agency shall provide PJM-GATS, M-RETS, and alternative retail electric suppliers with all information necessary to identify resources located in Illinois, within states that adjoin Illinois or within portions of the PJM and MISO footprint in the United States that qualify under the definition of renewable energy resources in Section 1-10 of the Illinois Power Agency Act for compliance with this Section 16-115D. Alternative retail electric suppliers shall not be subject to the requirements in item (3) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.

(5) All renewable energy credits used to comply with this Section shall be permanently retired.

(6) The required procurement of renewable energy resources by an alternative retail electric supplier shall apply to all metered electricity delivered to Illinois retail customers by the alternative retail electric supplier pursuant to contracts executed or extended after March 15, 2009.

(b) Compliance obligations.

(1) Through May 31, 2017, an alternative retail electric supplier shall comply with the renewable energy portfolio standards by making an alternative compliance payment, as described in subsection (d) of this Section, to cover at least one-half of the alternative retail electric supplier's compliance obligation for the period prior to June 1, 2017.

(2) For the delivery years beginning June 1, 2017 and June 1, 2018, an alternative retail electric supplier need not make any alternative compliance payment to meet any portion of its compliance obligation, as set forth in paragraph (3.5) of subsection (a) of this Section.

(3) An alternative retail electric supplier shall use any one or combination of the following means to cover the remainder of the alternative retail electric supplier's compliance obligation, as set forth in paragraphs (3) and (3.5) of subsection (a) of this Section, not covered by an alternative compliance payment made under paragraphs (1) and (2) of this subsection (b) of this Section:

(A) Generating electricity using renewable energy resources identified pursuant to item (4) of subsection (a) of this Section.

(B) Purchasing electricity generated using renewable energy resources identified pursuant to item (4) of subsection (a) of this Section through an energy contract.

(C) Purchasing renewable energy credits from renewable energy resources identified pursuant to item (4) of subsection (a) of this Section.

(D) Making an alternative compliance payment as described in subsection (d) of this Section.

(c) Use of renewable energy credits.

(1) Renewable energy credits that are not used by an alternative retail electric supplier to comply with a renewable portfolio standard in a compliance year may be banked and carried forward up to 2 12-month compliance periods after the compliance period in which the credit was generated for the purpose of complying with a renewable portfolio standard in those 2 subsequent compliance periods. For the 2009-2010 and 2010-2011 compliance periods, an alternative retail electric supplier may use renewable credits generated after December 31, 2008 and before June 1, 2009 to comply with this Section.

(2) An alternative retail electric supplier is responsible for demonstrating that a renewable energy credit used to comply with a renewable portfolio standard is derived from a renewable energy resource and that the alternative retail electric supplier has not used, traded, sold, or otherwise transferred the credit.

(3) The same renewable energy credit may be used by an alternative retail electric supplier to comply with a federal renewable portfolio standard and a renewable portfolio standard established under this Act. An alternative retail electric supplier that uses a renewable energy credit to comply with a renewable portfolio standard imposed by any other state may not use the same credit to comply with a renewable portfolio standard established under this Act.

(d) Alternative compliance payments.

(1) The Commission shall establish and post on its website, within 5 business days after entering an order approving a procurement plan pursuant to Section 1-75 of the Illinois Power Agency Act, maximum alternative compliance payment rates, expressed on a per kilowatt-hour basis, that will be applicable in the first compliance period following the plan approval. A separate maximum alternative compliance payment rate shall be established for the service territory of each electric utility that is subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. Each maximum alternative compliance payment rate shall be equal to the maximum allowable annual estimated average net increase due to the costs of the utility's purchase of renewable energy resources included in the amounts paid by eligible retail customers in connection with electric service, as described in item (2) of subsection (c) of Section 1-75 of the Illinois Power Agency Act for the compliance period, and as established in the approved procurement plan. Following each procurement event through which renewable energy resources are purchased for one or more of these utilities for the compliance period, the Commission shall establish and post on its website estimates of the alternative compliance payment rates, expressed on a per kilowatt-hour basis, that shall apply for that compliance period. Posting of the estimates shall occur no later than 10 business days following the procurement event, however, the Commission shall not be required to establish and post such estimates more often than once per calendar month. By July 1 of each year, the Commission shall establish and post on its website the actual alternative compliance payment rates for the preceding compliance year. For compliance years beginning prior to June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on renewable resources, excepting the additional incremental cost attributable to solar resources, for the compliance period divided by the forecasted load of eligible retail customers, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. For compliance years commencing on or after June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on all renewable resources for the compliance period divided by the forecasted load of retail customers for which the utility is procuring renewable energy resources in a given delivery year, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. The actual alternative compliance payment rates may not exceed the maximum alternative compliance payment rates established for the compliance period. For purposes of this subsection (d), the term "eligible retail customers" has the same meaning as found in Section 16-111.5 of this Act.

(2) In any given compliance year, an alternative retail electric supplier may elect to use alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard. In the event that an alternative retail electric supplier elects to make alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard, such payments shall be made by September 1, 2010 for the period of June 1, 2009 to May 1, 2010 and by September 1 of each year thereafter for the subsequent compliance period, in the manner and form as determined by the Commission. Any election by an alternative retail electric supplier to use alternative compliance payments is subject to review by the Commission under subsection (e) of this Section.

(3) An alternative retail electric supplier's alternative compliance payments shall be computed separately for each electric utility's service territory within which the alternative retail electric supplier provided retail service during the compliance period, provided that the electric utility was subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. For each service territory, the alternative retail electric supplier's alternative compliance payment shall be equal to (i) the actual alternative compliance payment rate established in item (1) of this subsection (d), multiplied by (ii) the actual amount of metered electricity delivered by the alternative retail electric supplier to retail customers for which the supplier has a compliance obligation within the service territory during the compliance period, multiplied by (iii) the result of one minus the ratios of the quantity of renewable energy resources used by the alternative retail electric supplier to comply with the requirements of this Section within the service territory to the product of the percentage of renewable energy resources required under item (3) or (3.5) of subsection (a) of this Section and the actual amount of metered electricity delivered by the alternative retail electrical supplier to retail customers for which the supplier has a compliance obligation within the service territory during the compliance period.

(4) Through May 31, 2017, all alternative compliance payments by alternative retail electric suppliers shall be deposited in the Illinois Power Agency Renewable Energy Resources Fund and used to purchase renewable energy credits, in accordance with Section 1-56 of the Illinois Power Agency Act. Beginning April 1, 2012 and by April 1 of each year thereafter, the Illinois Power Agency shall submit an annual report to the General Assembly, the Commission, and alternative retail electric suppliers that shall include, but not be limited to:

(A) the total amount of alternative compliance payments received in aggregate from alternative retail electric suppliers by planning year for all previous planning years in which the alternative compliance payment was in effect;

(B) the amount of those payments utilized to purchased renewable energy credits itemized by the date of each procurement in which the payments were utilized; and

(C) the unused and remaining balance in the Agency Renewable Energy Resources Fund attributable to those payments.

(4.5) Beginning with the delivery year commencing June 1, 2017, all alternative compliance payments by alternative retail electric suppliers shall be remitted to the applicable electric utility. To facilitate this remittance, each electric utility shall file a tariff with the Commission no later than 30 days following the effective date of this amendatory Act of the 99th General Assembly, which the Commission shall approve, after notice and hearing, no later than 45 days after its filing. The Illinois Power Agency shall use such payments to increase the amount of renewable energy resources otherwise to be procured under subsection (c) of Section 1-75 of the Illinois Power Agency Act.

(5) The Commission, in consultation with the Illinois Power Agency, shall establish a process or proceeding to consider the impact of a federal renewable portfolio standard, if enacted, on the operation of the alternative compliance mechanism, which shall include, but not be limited to, developing, to the extent permitted by the applicable federal statute, an appropriate methodology to apportion renewable energy credits retired as a result of alternative compliance payments made in accordance with this Section. The Commission shall commence any such process or proceeding within 35 days after enactment of a federal renewable portfolio standard.

(e) Each alternative retail electric supplier shall, by September 1, 2010 and by September 1 of each year thereafter, prepare and submit to the Commission a report, in a format to be specified by the Commission, that provides information certifying compliance by the alternative retail electric supplier with this Section, including copies of all PJM-GATS and M-RETS reports, and documentation relating to banking, retiring renewable energy credits, and any other information that the Commission determines necessary to ensure compliance with this Section.

An alternative retail electric supplier may file commercially or financially sensitive information or trade secrets with the Commission as provided under the rules of the Commission. To be filed confidentially, the information shall be accompanied by an affidavit that sets forth both the reasons for the confidentiality and a public synopsis of the information.

(f) The Commission may initiate a contested case to review allegations that the alternative retail electric supplier has violated this Section, including an order issued or rule promulgated under this Section. In any such proceeding, the alternative retail electric supplier shall have the burden of proof. If the Commission finds, after notice and hearing, that an alternative retail electric supplier has violated this Section, then the Commission shall issue an order requiring the alternative retail electric supplier to:

(1) immediately comply with this Section; and

(2) if the violation involves a failure to procure the requisite quantity of renewable energy resources or pay the applicable alternative compliance payment by the annual deadline, the Commission shall require the alternative retail electric supplier to double the applicable alternative compliance payment that would otherwise be required to bring the alternative retail electric supplier into compliance with this Section.

If an alternative retail electric supplier fails to comply with the renewable energy resource portfolio requirement or capacity portfolio requirement in this Section more than once in a 5-year period, then the Commission shall revoke the alternative electric supplier's certificate of service authority. The Commission shall not accept an application for a certificate of service authority from an alternative retail electric supplier that has lost certification under this subsection (f), or any corporate affiliate thereof, for at least one year after the date of revocation.

(g) All of the provisions of this Section apply to electric utilities operating outside their service area except under item (2) of subsection (a) of this Section the quantity of renewable energy resources shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied in the State outside of the utility's service territory during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of subsection (a) of this Section.

If any such utility fails to procure the requisite quantity of renewable energy resources by the annual deadline, then the Commission shall require the utility to double the alternative compliance payment that would otherwise be required to bring the utility into compliance with this Section.

If any such utility fails to comply with the renewable energy resource portfolio requirement in this Section more than once in a 5-year period, then the Commission shall order the utility to cease all sales outside of the utility's service territory for a period of at least one year.

(h) The provisions of this Section and the provisions of subsection (d) of Section 16-115 of this Act relating to procurement of renewable energy resources shall not apply to an alternative retail electric supplier that operates a combined heat and power system in this State or that has a corporate affiliate that operates such a combined heat and power system in this State that supplies electricity primarily to or for the benefit of: (i) facilities owned by the supplier, its subsidiary, or other corporate affiliate; (ii) facilities electrically integrated with the electrical system of facilities owned by the supplier, its subsidiary, or other corporate affiliate; or (iii) facilities that are adjacent to the site on which the combined heat and power system is located.

(i) The obligations of alternative retail electric suppliers and electric utilities operating outside their service territories to procure renewable energy resources, make alternative compliance payments, and file annual reports, and the obligations of the Commission to determine and post alternative compliance payment rates, shall terminate after May 31, 2019, provided that alternative retail electric suppliers and electric utilities operating outside their service territories shall be obligated to make all alternative compliance payments that they were obligated to pay for periods through and including May 31, 2019, but were not paid as of that date. The Commission shall continue to enforce the payment of unpaid alternative compliance payments in accordance with subsections (f) and (g) of this Section. All alternative compliance payments made after May 31, 2016 shall be remitted to the applicable electric utility and used to purchase renewable energy credits, in accordance with Section 1-75 of the Illinois Power Agency Act.

This subsection (i) is intended to accommodate the transition to the procurement of renewable energy resources for all retail customers in the amounts specified under subsection (c) of Section 1-75 of the Illinois Power Agency Act and Section 16-111.5 of this Act, including but not limited to the transition to a single charge applicable to all retail customers to recover the costs of these resources. Each alternative retail electric supplier shall certify in its annual reports filed pursuant to subsection (e) of this Section after May 31, 2019, that its retail customers are not paying the costs of alternative compliance payments or renewable energy resources that the alternative retail electric supplier is not required to remit or purchase under this Section. The Commission shall have the authority to initiate an emergency rulemaking to adopt rules regarding such certification.

(Source: P.A. 99-906, eff. 6-1-17.)

(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 110 . 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.)