HB1700sam002 104TH GENERAL ASSEMBLY

Sen. Steve Stadelman

Filed: 5/28/2026

10400HB1700sam002 LRB104 08228 AAS 38463 a

AMENDMENT TO HOUSE BILL 1700

AMENDMENT NO. ______. Amend House Bill 1700, AS AMENDED, by replacing everything after the enacting clause with the following:

"Section 5. The Illinois Enterprise Zone Act is amended by changing Section 5.5 as follows:

(20 ILCS 655/5.5) (from Ch. 67 1/2, par. 609.1)

Sec. 5.5. High Impact Business.

(a) In order to respond to unique opportunities to assist in the encouragement, development, growth, and expansion of the private sector through large-scale large scale investment and development projects, the Department is authorized to receive and approve applications for the designation of "High Impact Businesses" in Illinois, for an initial term of 20 years with an option for renewal for a term not to exceed 20 years, subject to the following conditions:

(1) such applications may be submitted at any time during the year;

(2) such business is not located, at the time of designation, in an enterprise zone designated pursuant to this Act, except for grocery stores, as defined in the Grocery Initiative Act, and a new battery energy storage solution facility, as defined by subparagraph (I) of paragraph (3) of this subsection (a);

(3) the business intends to do, commits to do, or is one or more of the following:

(A) the business intends to make a minimum investment of $12,000,000 which will be placed in service in qualified property and intends to create 500 full-time equivalent jobs at a designated location in Illinois or intends to make a minimum investment of $30,000,000 which will be placed in service in qualified property and intends to retain 1,500 full-time retained jobs at a designated location in Illinois. The terms "placed in service" and "qualified property" have the same meanings as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(B) the business intends to establish a new electric generating facility at a designated location in Illinois. "New electric generating facility", for purposes of this Section, means a newly constructed electric generation plant or a newly constructed generation capacity expansion at an existing electric generation plant, including the transmission lines and associated equipment that transfers electricity from points of supply to points of delivery, and for which such new foundation construction commenced not sooner than July 1, 2001. Such facility shall be designed to provide baseload electric generation and shall operate on a continuous basis throughout the year; and (i) shall have an aggregate rated generating capacity of at least 1,000 megawatts for all new units at one site if it uses natural gas as its primary fuel and foundation construction of the facility is commenced on or before December 31, 2004, or shall have an aggregate rated generating capacity of at least 400 megawatts for all new units at one site if it uses coal or gases derived from coal as its primary fuel and shall support the creation of at least 150 new Illinois coal mining jobs, or (ii) shall be funded through a federal Department of Energy grant before December 31, 2010 and shall support the creation of Illinois coal mining jobs, or (iii) shall use coal gasification or integrated gasification-combined cycle units that generate electricity or chemicals, or both, and shall support the creation of Illinois coal mining jobs. The term "placed in service" has the same meaning as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(B-5) the business intends to establish a new gasification facility at a designated location in Illinois. As used in this Section, "new gasification facility" means a newly constructed coal gasification facility that generates chemical feedstocks or transportation fuels derived from coal (which may include, but are not limited to, methane, methanol, and nitrogen fertilizer), that supports the creation or retention of Illinois coal mining jobs, and that qualifies for financial assistance from the Department before December 31, 2010. A new gasification facility does not include a pilot project located within Jefferson County or within a county adjacent to Jefferson County for synthetic natural gas from coal; or

(C) the business intends to establish production operations at a new coal mine, re-establish production operations at a closed coal mine, or expand production at an existing coal mine at a designated location in Illinois not sooner than July 1, 2001; provided that the production operations result in the creation of 150 new Illinois coal mining jobs as described in subdivision (a)(3)(B) of this Section, and further provided that the coal extracted from such mine is utilized as the predominant source for a new electric generating facility. The term "placed in service" has the same meaning as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(D) the business intends to construct new transmission facilities or upgrade existing transmission facilities at designated locations in Illinois, for which construction commenced not sooner than July 1, 2001. For the purposes of this Section, "transmission facilities" means transmission lines with a voltage rating of 115 kilovolts or above, including associated equipment, that transfer electricity from points of supply to points of delivery and that transmit a majority of the electricity generated by a new electric generating facility designated as a High Impact Business in accordance with this Section. The term "placed in service" has the same meaning as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(E) the business intends to establish a new wind power facility that will be constructed under a project labor agreement at a designated location in Illinois. For purposes of this Section, "new wind power facility" means a newly constructed electric generation facility, a newly constructed expansion of an existing electric generation facility, or the replacement of an existing electric generation facility, including the demolition and removal of an electric generation facility irrespective of whether it will be replaced, placed in service or replaced on or after July 1, 2009, that generates electricity using wind energy devices, and such facility shall be deemed to include any permanent structures associated with the electric generation facility and all associated transmission lines, substations, and other equipment related to the generation of electricity from wind energy devices. For purposes of this Section, "wind energy device" means any device, with a nameplate capacity of at least 0.5 megawatts, that is used in the process of converting kinetic energy from the wind to generate electricity; or

(E-5) the business intends to establish a new utility-scale solar facility that will be constructed under a project labor agreement at a designated location in Illinois. For purposes of this Section, "new utility-scale solar power facility" means a newly constructed electric generation facility, or a newly constructed expansion of an existing electric generation facility, placed in service on or after July 1, 2021, that (i) generates electricity using photovoltaic cells and (ii) has a nameplate capacity that is greater than 5,000 kilowatts, and such facility shall be deemed to include all associated transmission lines, substations, energy storage facilities, and other equipment related to the generation and storage of electricity from photovoltaic cells; or

(F) the business commits to (i) make a minimum investment of $500,000,000, which will be placed in service in a qualified property, (ii) create 125 full-time equivalent jobs at a designated location in Illinois, (iii) establish a fertilizer plant at a designated location in Illinois that complies with the set-back standards as described in Table 1: Initial Isolation and Protective Action Distances in the 2012 Emergency Response Guidebook published by the United States Department of Transportation, (iv) pay a prevailing wage for employees at that location who are engaged in construction activities, and (v) secure an appropriate level of general liability insurance to protect against catastrophic failure of the fertilizer plant or any of its constituent systems; in addition, the business must agree to enter into a construction project labor agreement including provisions establishing wages, benefits, and other compensation for employees performing work under the project labor agreement at that location; for the purposes of this Section, "fertilizer plant" means a newly constructed or upgraded plant utilizing gas used in the production of anhydrous ammonia and downstream nitrogen fertilizer products for resale; for the purposes of this Section, "prevailing wage" means the hourly cash wages plus fringe benefits for training and apprenticeship programs approved by the U.S. Department of Labor, Bureau of Apprenticeship and Training, health and welfare, insurance, vacations and pensions paid generally, in the locality in which the work is being performed, to employees engaged in work of a similar character on public works; this paragraph (F) applies only to businesses that submit an application to the Department within 60 days after July 25, 2013 (the effective date of Public Act 98-109); or

(G) the business intends to establish a new cultured cell material food production facility at a designated location in Illinois. As used in this paragraph (G):

"Cultured cell material food production facility" means a facility (i) at which cultured animal cell food is developed using animal cell culture technology, (ii) at which production processes occur that include the establishment of cell lines and cell banks, manufacturing controls, and all components and inputs, and (iii) that complies with all existing registrations, inspections, licensing, and approvals from all applicable and participating State and federal food agencies, including the Department of Agriculture, the Department of Public Health, and the United States Food and Drug Administration, to ensure that all food production is safe and lawful under provisions of the Federal Food, Drug and Cosmetic Act related to the development, production, and storage of cultured animal cell food.

"New cultured cell material food production facility" means a newly constructed cultured cell material food production facility that is placed in service on or after June 7, 2023 (the effective date of Public Act 103-9) or a newly constructed expansion of an existing cultured cell material food production facility, in a controlled environment, when the improvements are placed in service on or after June 7, 2023 (the effective date of Public Act 103-9); or

(H) the business is an existing or planned grocery store, as that term is defined in Section 5 of the Grocery Initiative Act, and receives financial support under that Act within the 10 years before submitting its application under this Act; or

(I) the business intends to establish a new battery energy storage solution facility that will be constructed under a project labor agreement at a designated location in Illinois. As used in this paragraph (I):

"New battery energy storage solution facility" means a newly constructed battery energy storage facility, a newly constructed expansion of an existing battery energy storage facility, or the replacement of an existing battery energy storage facility that stores electricity using battery devices and other means. "New battery energy storage solution facility" includes any permanent structures associated with the new battery energy storage facility and all associated transmission lines, substations, and other equipment that is related to the storage and transmission of electric power and that has a capacity of not less than 20 megawatt and storage capability of not less than 40 megawatt hours of energy; or

(J) the business intends to construct a new high voltage direct current converter station at a designated location in Illinois. As used in this paragraph, "high voltage direct current converter station" has the same meaning given to that term in Section 1-10 of the Illinois Power Agency Act; or

(K) the business intends to construct a new high voltage direct current converter station facility at a designated location in Illinois. As used in this paragraph, "high voltage direct current converter station" has the same meaning given to that term in Section 1-10 of the Illinois Power Agency Act; and

(4) no later than 90 days after an application is submitted, the Department shall notify the applicant of the Department's determination of the qualification of the proposed High Impact Business under this Section.

(a-5) For the purposes of businesses designated as High Impact Businesses pursuant to subparagraph (E), (E-5), or (I) of paragraph (3) of subsection (a) of this Section, "project labor agreement" means a pre-hire collective bargaining agreement that covers all terms and conditions of employment on a specific construction project. Project labor agreements required under subparagraph (E), (E-5), or (I) of paragraph (3) of subsection (a) of this Section must include, at a minimum, the following:

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

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

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

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

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

A labor organization and the general contractor building the project may include other terms and conditions in the project labor agreement as they deem necessary.

(b) Businesses designated as High Impact Businesses pursuant to subdivision (a)(3)(A) of this Section shall qualify for the credits and exemptions described in the following Acts: Section 9-222 and Section 9-222.1A of the Public Utilities Act, subsection (h) of Section 201 of the Illinois Income Tax Act, and Section 1d of the Retailers' Occupation Tax Act; provided that these credits and exemptions described in these Acts shall not be authorized until the minimum investments set forth in subdivision (a)(3)(A) of this Section have been placed in service in qualified properties and, in the case of the exemptions described in the Public Utilities Act and Section 1d of the Retailers' Occupation Tax Act, the minimum full-time equivalent jobs or full-time retained jobs set forth in subdivision (a)(3)(A) of this Section have been created or retained. Businesses designated as High Impact Businesses under this Section shall also qualify for the exemption described in Section 5l of the Retailers' Occupation Tax Act. The credit provided in subsection (h) of Section 201 of the Illinois Income Tax Act shall be applicable to investments in qualified property as set forth in subdivision (a)(3)(A) of this Section.

(b-5) Businesses designated as High Impact Businesses pursuant to subdivisions (a)(3)(B), (a)(3)(B-5), (a)(3)(C), (a)(3)(D), (a)(3)(G), (a)(3)(H), and (a)(3)(K) of this Section shall qualify for the credits and exemptions described in the following Acts: Section 51 of the Retailers' Occupation Tax Act, Section 9-222 and Section 9-222.1A of the Public Utilities Act, and subsection (h) of Section 201 of the Illinois Income Tax Act; however, the credits and exemptions authorized under Section 9-222 and Section 9-222.1A of the Public Utilities Act, and subsection (h) of Section 201 of the Illinois Income Tax Act shall not be authorized until the new electric generating facility, the new gasification facility, the new transmission facility, the new, expanded, or reopened coal mine, the new cultured cell material food production facility, or the existing or planned grocery store is operational, except that a new electric generating facility whose primary fuel source is natural gas is eligible only for the exemption under Section 5l of the Retailers' Occupation Tax Act.

(b-6) Businesses designated as High Impact Businesses pursuant to subdivision (a)(3)(E), (a)(3)(E-5), (A)(3)(I), or (a)(3)(J) of this Section shall qualify for the exemptions described in Section 5l of the Retailers' Occupation Tax Act; any business so designated as a High Impact Business being, for purposes of this Section, a "Wind Energy Business".

(b-7) Beginning on January 1, 2021, businesses designated as High Impact Businesses by the Department shall qualify for the High Impact Business construction jobs credit under subsection (h-5) of Section 201 of the Illinois Income Tax Act if the business meets the criteria set forth in subsection (i) of this Section. The total aggregate amount of credits awarded under the Blue Collar Jobs Act (Article 20 of Public Act 101-9) shall not exceed $20,000,000 in any State fiscal year.

(c) High Impact Businesses located in federally designated foreign trade zones or sub-zones are also eligible for additional credits, exemptions and deductions as described in the following Acts: Section 9-221 and Section 9-222.1 of the Public Utilities Act; and subsection (g) of Section 201, and Section 203 of the Illinois Income Tax Act.

(d) Except for businesses contemplated under subdivision (a)(3)(E), (a)(3)(E-5), (a)(3)(G), (a)(3)(H), (A)(3)(I), (a)(3)(J), or (a)(3)(K) of this Section, existing Illinois businesses which apply for designation as a High Impact Business must provide the Department with the prospective plan for which 1,500 full-time retained jobs would be eliminated in the event that the business is not designated.

(e) Except for new businesses contemplated under subdivision (a)(3)(E), subdivision (a)(3)(G), subdivision (a)(3)(H), or subdivision (a)(3)(J) of this Section, new proposed facilities which apply for designation as High Impact Business must provide the Department with proof of alternative non-Illinois sites which would receive the proposed investment and job creation in the event that the business is not designated as a High Impact Business.

(f) Except for businesses contemplated under subdivision (a)(3)(E), subdivision (a)(3)(G), subdivision (a)(3)(H), subdivision (a)(3)(J), or (a)(3)(K) of this Section, in the event that a business is designated a High Impact Business and it is later determined after reasonable notice and an opportunity for a hearing as provided under the Illinois Administrative Procedure Act, that the business would have placed in service in qualified property the investments and created or retained the requisite number of jobs without the benefits of the High Impact Business designation, the Department shall be required to immediately revoke the designation and notify the Director of the Department of Revenue who shall begin proceedings to recover all wrongfully exempted State taxes with interest.

(g) The Department shall revoke a High Impact Business designation if the participating business fails to comply with the terms and conditions of the designation.

(h) Prior to designating a business, the Department shall provide the members of the General Assembly and Commission on Government Forecasting and Accountability with a report setting forth the terms and conditions of the designation and guarantees that have been received by the Department in relation to the proposed business being designated.

(i) High Impact Business construction jobs credit. Beginning on January 1, 2021, a High Impact Business may receive a tax credit against the tax imposed under subsections (a) and (b) of Section 201 of the Illinois Income Tax Act in an amount equal to 50% of the amount of the incremental income tax attributable to High Impact Business construction jobs credit employees employed in the course of completing a High Impact Business construction jobs project. However, the High Impact Business construction jobs credit may equal 75% of the amount of the incremental income tax attributable to High Impact Business construction jobs credit employees if the High Impact Business construction jobs credit project is located in an underserved area.

The Department shall certify to the Department of Revenue: (1) the identity of taxpayers that are eligible for the High Impact Business construction jobs credit; and (2) the amount of High Impact Business construction jobs credits that are claimed pursuant to subsection (h-5) of Section 201 of the Illinois Income Tax Act in each taxable year.

As used in this subsection (i):

"High Impact Business construction jobs credit" means an amount equal to 50% (or 75% if the High Impact Business construction project is located in an underserved area) of the incremental income tax attributable to High Impact Business construction job employees. The total aggregate amount of credits awarded under the Blue Collar Jobs Act (Article 20 of Public Act 101-9) shall not exceed $20,000,000 in any State fiscal year

"High Impact Business construction job employee" means a laborer or worker who is employed by a contractor or subcontractor in the actual construction work on the site of a High Impact Business construction job project.

"High Impact Business construction jobs project" means building a structure or building or making improvements of any kind to real property, undertaken and commissioned by a business that was designated as a High Impact Business by the Department. The term "High Impact Business construction jobs project" does not include the routine operation, routine repair, or routine maintenance of existing structures, buildings, or real property.

"Incremental income tax" means the total amount withheld during the taxable year from the compensation of High Impact Business construction job employees.

"Underserved area" means a geographic area that meets one or more of the following conditions:

(1) the area has a poverty rate of at least 20% according to the latest American Community Survey;

(2) 35% or more of the families with children in the area are living below 130% of the poverty line, according to the latest American Community Survey;

(3) at least 20% of the households in the area receive assistance under the Supplemental Nutrition Assistance Program (SNAP); or

(4) the area has an average unemployment rate, as determined by the Illinois Department of Employment Security, that is more than 120% of the national unemployment average, as determined by the U.S. Department of Labor, for a period of at least 2 consecutive calendar years preceding the date of the application.

(j) (Blank).

(j-5) Annually, until construction is completed, a company seeking High Impact Business Construction Job credits shall submit a report that, at a minimum, describes the projected project scope, timeline, and anticipated budget. Once the project has commenced, the annual report shall include actual data for the prior year as well as projections for each additional year through completion of the project. The Department shall issue detailed reporting guidelines prescribing the requirements of construction-related reports.

In order to receive credit for construction expenses, the company must provide the Department with evidence that a certified third-party executed an Agreed-Upon Procedure (AUP) verifying the construction expenses or accept the standard construction wage expense estimated by the Department.

Upon review of the final project scope, timeline, budget, and AUP, the Department shall issue a tax credit certificate reflecting a percentage of the total construction job wages paid throughout the completion of the project.

(k) Upon 7 business days' notice, each taxpayer shall make available to each State agency and to federal, State, or local law enforcement agencies and prosecutors for inspection and copying at a location within this State during reasonable hours, the report under subsection (j-5).

(l) The changes made to this Section by Public Act 102-1125, other than the changes in subsection (a), apply to High Impact Businesses that submit applications on or after February 3, 2023 (the effective date of Public Act 102-1125).

(Source: P.A. 103-9, eff. 6-7-23; 103-561, eff. 1-1-24; 103-595, eff. 6-26-24; 103-605, eff. 7-1-24; 103-1066, eff. 2-20-25; 104-6, eff. 6-16-25; revised 12-12-25.)

Section 10. The Energy Transition Act is amended by changing Sections 5-20 and 5-40 as follows:

(20 ILCS 730/5-20)

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

Sec. 5-20. Clean Jobs Workforce Network Program.

(a) As used in this Section, "Program" means the Clean Jobs Workforce Network Program.

(b) Subject to appropriation, the Department shall develop and, through Regional Administrators, administer the Clean Jobs Workforce Network Program to create a network of 14 Program delivery Hub Sites with program elements delivered by community-based organizations and their subcontractors geographically distributed across the State including at least one Hub Site located in or near each of the following areas: Chicago (South Side), Chicago (Southwest and West Sides), Waukegan, Rockford, Aurora, Joliet, Peoria, Champaign, Danville, Decatur, Carbondale, East St. Louis, Kankakee, and Alton.

(c) In admitting program participants, for each workforce Hub Site, the Regional Administrators shall:

(1) in each Hub Site where the applicant pool allows:

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

(B) dedicate at least two-thirds of program placements to applicants that satisfy the criteria in paragraph (1) or who reside in a geographic area that is impacted by economic or environmental challenges, defined as an area that is either (i) an R3 Area, as defined pursuant to Section 10-40 of the Cannabis Regulation and Tax Act, or (ii) an environmental justice community, as defined by the Illinois Power Agency, excluding any racial or ethnic indicators used by the agency unless and until the constitutional basis for their inclusion in determining program admissions is established. Among applicants that satisfy these criteria, preference shall be given to applicants who face barriers to employment, such as low educational attainment, prior involvement with the criminal legal system, and language barriers; and applicants that are graduates of or currently enrolled in the foster care system; and

(2) prioritize the remaining program placements for: applicants who are displaced energy workers as defined in the Energy Community Reinvestment Act; persons who face barriers to employment, including low educational attainment, prior involvement with the criminal legal system, and language barriers; and applicants who are graduates of or currently enrolled in the foster care system, regardless of the applicant's area of residence.

The Department and Regional Administrators shall protect the confidentiality of any personal information provided by program applicants regarding the applicant's status as a formerly incarcerated person or foster care recipient; however, the Department or Regional Administrators may publish aggregated data on the number of participants that were formerly incarcerated or foster care recipients so long as that publication protects the identities of those persons.

Any person who applies to the program may elect not to share with the Department or Regional Administrators whether he or she is a graduate or currently enrolled in the foster care system or was formerly convicted.

(d) Program elements for each Hub Site shall be provided by a community-based organization. The Department shall initially select a community-based organization in each Hub Site and shall subsequently select a community-based organization in each Hub Site every 3 years. Community-based organizations delivering program elements outlined in subsection (e) may provide all elements required or may subcontract to other entities for provision of portions of program elements, including, but not limited to, administrative soft and hard skills for program participants, delivery of specific training in the core curriculum, or provision of other support functions for program delivery compliance.

(e) The Clean Jobs Workforce Hubs Network shall:

(1) coordinate with Energy Transition Navigators: (i) to increase participation in the Clean Jobs Workforce Network Program and clean energy and related sector workforce and training opportunities; (ii) coordinate recruitment, communications, and ongoing engagement with potential employers, including, but not limited to, activities such as job matchmaking initiatives, hosting events such as job fairs, and collaborating with other Hub Sites to identify and implement best practices for employer engagement; and (iii) leverage community-based organizations, educational institutions, and community-based and labor-based training providers to ensure program-eligible individuals across the State have dedicated and sustained support to enter and complete the career pipeline for clean energy and related sector jobs;

(2) develop formal partnerships, including formal sector partnerships between community-based organizations and entities that provide clean energy jobs, including businesses, nonprofit organizations, and worker-owned cooperatives, to ensure that Program participants have priority access to employment training and hiring opportunities; and

(3) implement the Clean Jobs Curriculum to provide, including, but not limited to, training, certification preparation, job readiness, and skill development, including soft skills, math skills, technical skills, certification test preparation, and other development needed, to Program participants.

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

(f-5) The Department and the Department of Corrections shall jointly conduct activities to support the recruitment of eligible candidates to the Program, consistent with Section 5-8A-4.2 of the Unified Code of Corrections. The activities shall include providing information on the community-based program provider serving the area in which the individual preparing for release is expected to reside and making available a process through which an individual may choose to consent to be contacted by that provider.

(g) The Department shall require submission of quarterly reports, including program performance metrics by each Hub Site to the Regional Administrator of their Program Delivery Area. Program performance metrics include, but are not limited to:

(1) demographic data, including racial, gender, residency in eligible communities, and geographic distribution data, on Program trainees entering and graduating the Program;

(2) demographic data, including racial, gender, residency in eligible communities, and geographic distribution data, on Program trainees who are placed in employment, including the percentages of trainees by race, gender, and geographic categories in each individual job type or category and whether employment is union, nonunion, or nonunion via temporary agency;

(3) trainee job acquisition and retention statistics, including the duration of employment (start and end dates of hires) by race, gender, and geography;

(4) hourly wages, including hourly overtime pay rate, and benefits of trainees placed into employment by race, gender, and geography;

(5) percentage of jobs by race, gender, and geography held by Program trainees or graduates that are full-time equivalent positions, meaning that the position held is full-time, direct, and permanent based on 2,080 hours worked per year (paid directly by the employer, whose activities, schedule, and manner of work the employer controls, and receives pay and benefits in the same manner as permanent employees); and

(6) qualitative data consisting of open-ended reporting on pertinent issues, including, but not limited to, qualitative descriptions accompanying metrics or identifying key successes and challenges.

(h) Within 3 years after the effective date of this Act, the Department shall select an independent evaluator to review and prepare a report on the performance of the Program and Regional Administrators.

(Source: P.A. 102-662, eff. 9-15-21; 103-595, eff. 7-1-25.)

(20 ILCS 730/5-40)

(Text of Section before amendment by P.A. 104-458)

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

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

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

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

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

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

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

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

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

(d) Each Climate Works Hub that receives funding from the Energy Transition Assistance Fund shall:

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

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

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

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

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

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

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

(Text of Section after amendment by P.A. 104-458)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(iii) applicants who are graduates of or currently enrolled in the foster care system, regardless of the applicant's area of residence;

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

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

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

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

(e-5) The Department and the Department of Corrections shall jointly conduct activities to support the recruitment of eligible candidates to the Program, consistent with Section 5-8A-4.2 of the Unified Code of Corrections. The activities shall include providing information on the community-based program provider serving the area in which the individual preparing for release is expected to reside and making available a process through which an individual may choose to consent to be contacted by that provider.

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

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

Section 15. The Energy Efficient Building Act is amended by changing Sections 20 and 55 as follows:

(20 ILCS 3125/20)

Sec. 20. Applicability.

(a) The Board shall review and adopt the Code within one year after its publication. The Code shall take effect within 6 months after it is adopted by the Board, except that, beginning January 1, 2012, the Code adopted in 2012 shall take effect on January 1, 2013. Except as otherwise provided in this Act, the Code shall apply to (i) any new building or structure in this State for which a building permit application is received by a municipality or county and (ii) beginning on the effective date of this amendatory Act of the 100th General Assembly, each State facility specified in Section 4.01 of the Capital Development Board Act. In the case of any addition, alteration, renovation, or repair to an existing residential or commercial structure, the Code adopted under this Act applies only to the portions of that structure that are being added, altered, renovated, or repaired. The changes made to this Section by this amendatory Act of the 97th General Assembly shall in no way invalidate or otherwise affect contracts entered into on or before the effective date of this amendatory Act of the 97th General Assembly.

(b) The following buildings shall be exempt from the Code and the Illinois Stretch Energy Code:

(1) Buildings otherwise exempt from the provisions of a locally adopted building code and buildings that do not contain a conditioned space.

(2) Buildings that do not use either electricity or fossil fuel for comfort conditioning. For purposes of determining whether this exemption applies, a building will be presumed to be heated by electricity, even in the absence of equipment used for electric comfort heating, whenever the building is provided with electrical service in excess of 100 amps, unless the code enforcement official determines that this electrical service is necessary for purposes other than providing electric comfort heating.

(3) Historic buildings. This exemption shall apply to those buildings that are listed on the National Register of Historic Places or the Illinois Register of Historic Places, and to those buildings that have been designated as historically significant by a local governing body that is authorized to make such designations.

(4) (Blank).

(5) Other buildings specified as exempt by the International Energy Conservation Code.

(c) Additions, alterations, renovations, or repairs to an existing building, building system, or portion thereof shall conform to the provisions of the Code as they relate to new construction without requiring the unaltered portion of the existing building or building system to comply with the Code. The following need not comply with the Code, provided that the energy use of the building is not increased: (i) storm windows installed over existing fenestration, (ii) glass-only replacements in an existing sash and frame, (iii) existing ceiling, wall, or floor cavities exposed during construction, provided that these cavities are filled with insulation, and (iv) construction where the existing roof, wall, or floor is not exposed.

(d) A unit of local government that does not regulate energy efficient building standards is not required to adopt, enforce, or administer the Code; however, any energy efficient building standards adopted by a unit of local government must comply with this Act. If a unit of local government does not regulate energy efficient building standards, any construction, renovation, or addition to buildings or structures is subject to the provisions contained in this Act.

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

(20 ILCS 3125/55)

Sec. 55. Illinois Stretch Energy Code.

(a) The Board, in consultation with the Agency, shall create and adopt the Illinois Stretch Energy Code, to allow municipalities, counties, and projects authorized or funded by the Board to achieve more energy efficiency in buildings than the Illinois Energy Conservation Code through a consistent pathway across the State. The Illinois Stretch Energy Code shall be available for adoption by any municipality or county and shall set minimum energy efficiency requirements, taking the place of the Illinois Energy Conservation Code within any municipality or county that adopts the Illinois Stretch Energy Code.

(b) The Illinois Stretch Energy Code shall have separate components for commercial and residential buildings, which may be adopted by the municipality or county jointly or separately.

(c) The Illinois Stretch Energy Code shall apply to all projects to which an energy conservation code is applicable that are authorized or funded in any part by the Board after July 1, 2024.

(d) Development of the Illinois Stretch Energy Code shall be completed and available for adoption by municipalities by June 30, 2024.

(e) Consistent with the requirements under paragraph (2.5) of subsection (g) of Section 8-103B of the Public Utilities Act and under paragraph (2) of subsection (j) of Section 8-104 of the Public Utilities Act, municipalities and counties may adopt the Illinois Stretch Energy Code and may use utility programs to support compliance with the Illinois Stretch Energy Code. The amount of savings from such utility efforts that may be counted toward achievement of their annual savings goals shall be based on reasonable estimates of the increase in savings resulting from the utility efforts, relative to reasonable approximations of what would have occurred absent the utility involvement.

(f) The Illinois Stretch Energy Code's residential components shall:

(1) apply to residential buildings as defined under Section 10;

(2) set performance targets using a site energy index with reductions relative to the 2006 International Energy Conservation Code; and

(3) include stretch energy codes with site energy index standards and adoption dates as follows: by no later than June 30, 2024, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.50 of the 2006 International Energy Conservation Code; by no later than December 31, 2026, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.40 of the 2006 International Energy Conservation Code, unless the Board identifies unanticipated burdens associated with the stretch energy code adopted in 2023 or 2024, in which case the Board may adopt a stretch energy code with a site energy index no greater than 0.42 of the 2006 International Energy Conservation Code, provided that the more relaxed standard has a site energy index that is at least 0.05 more restrictive than the 2024 International Energy Conservation Code; by no later than December 31, 2029, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.33 of the 2006 International Energy Conservation Code, unless the Board identifies unanticipated burdens associated with the stretch energy code adopted in 2025, in which case the Board may adopt a stretch energy code with a site energy index no greater than 0.35 of the 2006 International Energy Conservation Code, but only if that more relaxed standard has a site energy index that is at least 0.05 more restrictive than the 2027 International Energy Conservation Code; and by no later than December 31, 2032, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.25 of the 2006 International Energy Conservation Code.

(g) The Illinois Stretch Energy Code's commercial components shall:

(1) apply to commercial buildings as defined under Section 10;

(2) set performance targets using a site energy index with reductions relative to the 2006 International Energy Conservation Code; and

(3) include stretch energy codes with site energy index standards and adoption dates as follows: by no later than June 30, 2024, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.60 of the 2006 International Energy Conservation Code; by no later than December 31, 2026, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.50 of the 2006 International Energy Conservation Code; by no later than December 31, 2029, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.44 of the 2006 International Energy Conservation Code; and by no later than December 31, 2032, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.39 of the 2006 International Energy Conservation Code.

(h) The process for the creation of the Illinois Stretch Energy Code includes:

(1) within 60 days after the effective date of this amendatory Act of the 102nd General Assembly, the Capital Development Board shall meet with the Illinois Energy Code Advisory Council to advise and provide technical assistance and recommendations to the Capital Development Board for the Illinois Stretch Energy Code, which shall:

(A) advise the Capital Development Board on creation of interim performance targets, code requirements, and an implementation plan for the Illinois Stretch Energy Code;

(B) recommend amendments to proposed rules issued by the Capital Development Board;

(C) recommend complementary programs or policies;

(D) complete recommendations and development for the Illinois Stretch Energy Code elements and requirements by December 31, 2023;

(2) As part of its deliberations, the Illinois Energy Code Advisory Council shall actively solicit input from other energy code stakeholders and interested parties.

(Source: P.A. 103-4, eff. 5-31-23; 104-315, eff. 1-1-26.)

Section 20. The Illinois Power Agency Act is amended by changing Section 1-75 as follows:

(20 ILCS 3855/1-75)

(Text of Section before amendment by P.A. 104-458)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(E) expertise in credit and contract protocols;

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

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

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

(A) failure to satisfy qualification criteria;

(B) identification of a conflict of interest; or

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

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

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

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

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

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

(c) Renewable portfolio standard.

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

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

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

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

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

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

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

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

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

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

(iii) For purposes of this Section:

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

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

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

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

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

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

Notwithstanding the requirements of this subsection (c), and except as provided in subparagraph (E-5) of paragraph (1) of this subsection (c), the total of renewable energy resources procured under the procurement plan for any single year shall be subject to the limitations of this subparagraph (E). Such procurement shall be reduced for all retail customers based on the amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than 4.25% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009. To arrive at a maximum dollar amount of renewable energy resources to be procured for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered, or applicable portion of such amount as specified in paragraph (1) of this subsection (c), as applicable, by the electric utility in the delivery year immediately prior to the procurement to all retail customers in its service territory. The calculations required by this subparagraph (E) shall be made only once for each delivery year at the time that the renewable energy resources are procured. Once the determination as to the amount of renewable energy resources to procure is made based on the calculations set forth in this subparagraph (E) and the contracts procuring those amounts are executed between the seller and applicable electric utility, no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. As provided in subparagraph (E-5) of paragraph (1) of this subsection (c), the seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this subparagraph (E), and all costs incurred under such contracts shall be fully recoverable by the electric utility as provided in this Section.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(vi) All procurements under this subparagraph (G), including the procurement of renewable energy credits from hydropower facilities, shall comply with the geographic requirements in subparagraph (I) of this paragraph (1) and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act to the extent practicable, and these processes and procedures may be expedited to accommodate the schedule established by this subparagraph (G).

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(ii) At least 20% from distributed renewable energy generation devices with a nameplate capacity of more than 25 kilowatts and no more than 5,000 kilowatts. The Agency may create sub-categories within this category to account for the differences between projects for small commercial customers, large commercial customers, and public or non-profit customers.

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

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

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

(3) projects shall not be colocated with one or more other community renewable generation projects, as defined in the Agency's first revised long-term renewable resources procurement plan approved by the Commission on February 18, 2020, such that the aggregate nameplate capacity exceeds 5,000 kilowatts; and

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

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

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

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

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

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

(1) community ownership or community wealth-building;

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

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

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

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

Selection criteria may also prioritize projects that:

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

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

(3) are located in Equity Investment Eligible Communities;

(4) are not greenfield projects;

(5) serve only local subscribers;

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

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

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

For the purposes of this item (v):

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

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

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

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

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

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

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

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

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

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

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

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

(i) (Blank).

(ii) For those renewable energy credits that qualify and are procured under item (i) of subparagraph (K) of this paragraph (1), and any similar category projects that are procured under item (vi) of subparagraph (K) of this paragraph (1) that qualify and are procured under item (vi), the contract length shall be 15 years. The renewable energy credit delivery contract value shall be paid in full, based on the estimated generation during the first 15 years of operation, by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and compliant by the Program Administrator. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

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

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

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

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

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

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

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

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

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

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

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

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

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

(i) The Agency shall establish a registration process for entities seeking to qualify for program-administered incentive funding and establish baseline qualifications for vendor approval. The Agency must maintain a list of approved entities on each program's website, and may revoke a vendor's ability to receive program-administered incentive funding status upon a determination that the vendor failed to comply with contract terms, the law, or other program requirements.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(i) all new utility-scale wind projects;

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

(iii) all new brownfield photovoltaic projects;

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

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

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

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

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

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

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

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

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

(1) For the purposes of this subparagraph:

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

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

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

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

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

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

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

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

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

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

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

(4) The Commission shall approve a reduction in the volumetric charges collected pursuant to Section 16-108 of the Public Utilities Act for approved eligible self-direct customers equivalent to the anticipated cost of renewable energy credit deliveries under contracts for new utility-scale wind and new utility-scale solar entered for each delivery year after the large energy customer begins retiring eligible new utility scale renewable energy credits for self-compliance. The self-direct credit amount shall be determined annually and is equal to the estimated portion of the cost authorized by subparagraph (E) of paragraph (1) of this subsection (c) that supported the annual procurement of utility-scale renewable energy credits in the prior delivery year using a methodology described in the long-term renewable resources procurement plan, expressed on a per kilowatthour basis, and does not include (i) costs associated with any contracts entered into before the delivery year in which the customer files the initial compliance report to be eligible for participation in the self-direct program, and (ii) costs associated with procuring renewable energy credits through existing and future contracts through the Adjustable Block Program, subsection (c-5) of this Section 1-75, and the Solar for All Program. The Agency shall assist the Commission in determining the current and future costs. The Agency must determine the self-direct credit amount for new and existing eligible self-direct customers and submit this to the Commission in an annual compliance filing. The Commission must approve the self-direct credit amount by June 1, 2023 and June 1 of each delivery year thereafter.

(5) Customers described in this subparagraph (R) shall apply, on a form developed by the Agency, to the Agency to be designated as a self-direct eligible customer. Once the Agency determines that a self-direct customer is eligible for participation in the program, the self-direct customer will remain eligible until the end of the term of the contract. Thereafter, application may be made not less than 12 months before the filing date of the long-term renewable resources procurement plan described in this Act. At a minimum, such application shall contain the following:

(i) the customer's certification that, at the time of the customer's application, the customer qualifies to be a self-direct eligible customer, including documents demonstrating that qualification;

(ii) the customer's certification that the customer has entered into or will enter into by the beginning of the applicable procurement year, one or more bilateral contracts for new wind projects or new photovoltaic projects, including supporting documentation;

(iii) certification that the contract or contracts for new renewable energy resources are long-term contracts with term lengths of at least 10 years, including supporting documentation;

(iv) certification of the quantities of renewable energy credits that the customer will purchase each year under such contract or contracts, including supporting documentation;

(v) proof that the contract is sufficient to produce renewable energy credits to be equivalent in volume to at least 40% of the large energy customer's usage from the previous delivery year, measured to the nearest megawatt-hour; and

(vi) certification that the customer intends to maintain the contract for the duration of the length of the contract.

(6) If a customer receives the self-direct credit but fails to properly procure and retire renewable energy credits as required under this subparagraph (R), the Commission, on petition from the Agency and after notice and hearing, may direct such customer's utility to recover the cost of the wrongfully received self-direct credits plus interest through an adder to charges assessed pursuant to Section 16-108 of the Public Utilities Act. Self-direct customers who knowingly fail to properly procure and retire renewable energy credits and do not notify the Agency are ineligible for continued participation in the self-direct renewable portfolio standard compliance program.

(2) (Blank).

(3) (Blank).

(4) The electric utility shall retire all renewable energy credits used to comply with the standard.

(5) Beginning with the 2010 delivery year and ending June 1, 2017, an electric utility subject to this subsection (c) shall apply the lesser of the maximum alternative compliance payment rate or the most recent estimated alternative compliance payment rate for its service territory for the corresponding compliance period, established pursuant to subsection (d) of Section 16-115D of the Public Utilities Act to its retail customers that take service pursuant to the electric utility's hourly pricing tariff or tariffs. The electric utility shall retain all amounts collected as a result of the application of the alternative compliance payment rate or rates to such customers, and, beginning in 2011, the utility shall include in the information provided under item (1) of subsection (d) of Section 16-111.5 of the Public Utilities Act the amounts collected under the alternative compliance payment rate or rates for the prior year ending May 31. Notwithstanding any limitation on the procurement of renewable energy resources imposed by item (2) of this subsection (c), the Agency shall increase its spending on the purchase of renewable energy resources to be procured by the electric utility for the next plan year by an amount equal to the amounts collected by the utility under the alternative compliance payment rate or rates in the prior year ending May 31.

(6) The electric utility shall be entitled to recover all of its costs associated with the procurement of renewable energy credits under plans approved under this Section and Section 16-111.5 of the Public Utilities Act. These costs shall include associated reasonable expenses for implementing the procurement programs, including, but not limited to, the costs of administering and evaluating the Adjustable Block program, through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act.

(7) Renewable energy credits procured from new photovoltaic projects or new distributed renewable energy generation devices under this Section after June 1, 2017 (the effective date of Public Act 99-906) must be procured from devices installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

In meeting the renewable energy requirements of this subsection (c), to the extent feasible and consistent with State and federal law, the renewable energy credit procurements, Adjustable Block solar program, and community renewable generation program shall provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(c-5) Procurement of renewable energy credits from new renewable energy facilities installed at or adjacent to the sites of electric generating facilities that burn or burned coal as their primary fuel source.

(1) In addition to the procurement of renewable energy credits pursuant to long-term renewable resources procurement plans in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, the Agency shall conduct procurement events in accordance with this subsection (c-5) for the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new renewable energy facilities to be installed at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source and meet the other criteria specified in this subsection (c-5). For purposes of this subsection (c-5), "new renewable energy facility" means a new utility-scale solar project as defined in this Section 1-75. The renewable energy credits procured pursuant to this subsection (c-5) may be included or counted for purposes of compliance with the amounts of renewable energy credits required to be procured pursuant to subsection (c) of this Section to the extent that there are otherwise shortfalls in compliance with such requirements. The procurement of renewable energy credits by electric utilities pursuant to this subsection (c-5) shall be funded solely by revenues collected from the Coal to Solar and Energy Storage Initiative Charge provided for in this subsection (c-5) and subsection (i-5) of Section 16-108 of the Public Utilities Act, shall not be funded by revenues collected through any of the other funding mechanisms provided for in subsection (c) of this Section, and shall not be subject to the limitation imposed by subsection (c) on charges to retail customers for costs to procure renewable energy resources pursuant to subsection (c), and shall not be subject to any other requirements or limitations of subsection (c).

(2) The Agency shall conduct 2 procurement events to select owners of electric generating facilities meeting the eligibility criteria specified in this subsection (c-5) to enter into long-term contracts to sell renewable energy credits to electric utilities serving more than 300,000 retail customers in this State as of January 1, 2019. The first procurement event shall be conducted no later than March 31, 2022, unless the Agency elects to delay it, until no later than May 1, 2022, due to its overall volume of work, and shall be to select owners of electric generating facilities located in this State and south of federal Interstate Highway 80 that meet the eligibility criteria specified in this subsection (c-5). The second procurement event shall be conducted no sooner than September 30, 2022 and no later than October 31, 2022 and shall be to select owners of electric generating facilities located anywhere in this State that meet the eligibility criteria specified in this subsection (c-5). The Agency shall establish and announce a time period, which shall begin no later than 30 days prior to the scheduled date for the procurement event, during which applicants may submit applications to be selected as suppliers of renewable energy credits pursuant to this subsection (c-5). The eligibility criteria for selection as a supplier of renewable energy credits pursuant to this subsection (c-5) shall be as follows:

(A) The applicant owns an electric generating facility located in this State that: (i) as of January 1, 2016, burned coal as its primary fuel to generate electricity; and (ii) has, or had prior to retirement, an electric generating capacity of at least 150 megawatts. The electric generating facility can be either: (i) retired as of the date of the procurement event; or (ii) still operating as of the date of the procurement event.

(B) The applicant is not (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in (i) or (ii); and the coal-fueled electric generating facility was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act.

(C) If participating in the first procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 20 megawatts but no more than 100 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 2 megawatts and at most 10 megawatts. If participating in the second procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 5 megawatts but no more than 20 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 0.5 megawatts and at most one megawatt.

(D) The applicant agrees that the new renewable energy facility and the energy storage facility will be constructed or installed by a qualified entity or entities in compliance with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted thereunder.

(E) The applicant agrees that personnel operating the new renewable energy facility and the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function.

(F) The applicant commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the applicant's employees engaged in construction activities associated with the new renewable energy facility and the new energy storage facility and to the employees of applicant's contractors engaged in construction activities associated with the new renewable energy facility and the new energy storage facility, and that, on or before the commercial operation date of the new renewable energy facility, the applicant shall file a report with the Agency certifying that the requirements of this subparagraph (F) have been met.

(G) The applicant commits that if selected, it will negotiate a project labor agreement for the construction of the new renewable energy facility and associated energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

(H) The applicant commits to enter into a contract or contracts for the applicable duration to provide specified numbers of renewable energy credits each year from the new renewable energy facility to electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019, at a price of $30 per renewable energy credit. The price per renewable energy credit shall be fixed at $30 for the applicable duration and the renewable energy credits shall not be indexed renewable energy credits as provided for in item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act. The applicable duration of each contract shall be 20 years, unless the applicant is physically interconnected to the PJM Interconnection, LLC transmission grid and had a generating capacity of at least 1,200 megawatts as of January 1, 2021, in which case the applicable duration of the contract shall be 15 years.

(I) The applicant's application is certified by an officer of the applicant and by an officer of the applicant's ultimate parent company, if any.

(3) An applicant may submit applications to contract to supply renewable energy credits from more than one new renewable energy facility to be constructed at or adjacent to one or more qualifying electric generating facilities owned by the applicant. The Agency may select new renewable energy facilities to be located at or adjacent to the sites of more than one qualifying electric generation facility owned by an applicant to contract with electric utilities to supply renewable energy credits from such facilities.

(4) The Agency shall assess fees to each applicant to recover the Agency's costs incurred in receiving and evaluating applications, conducting the procurement event, developing contracts for sale, delivery and purchase of renewable energy credits, and monitoring the administration of such contracts, as provided for in this subsection (c-5), including fees paid to a procurement administrator retained by the Agency for one or more of these purposes.

(5) The Agency shall select the applicants and the new renewable energy facilities to contract with electric utilities to supply renewable energy credits in accordance with this subsection (c-5). In the first procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no less than 400,000 renewable energy credits per year for the applicable duration, assuming sufficient qualifying applications to supply, in the aggregate, at least that amount of renewable energy credits per year; and not more than 580,000 renewable energy credits per year for the applicable duration. In the second procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no more than 625,000 renewable energy credits per year less the amount of renewable energy credits each year contracted for as a result of the first procurement event, for the applicable durations. The number of renewable energy credits to be procured as specified in this paragraph (5) shall not be reduced based on renewable energy credits procured in the self-direct renewable energy credit compliance program established pursuant to subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75.

(6) The obligation to purchase renewable energy credits from the applicants and their new renewable energy facilities selected by the Agency shall be allocated to the electric utilities based on their respective percentages of kilowatthours delivered to delivery services customers to the aggregate kilowatthour deliveries by the electric utilities to delivery services customers for the year ended December 31, 2021. In order to achieve these allocation percentages between or among the electric utilities, the Agency shall require each applicant that is selected in the procurement event to enter into a contract with each electric utility for the sale and purchase of renewable energy credits from each new renewable energy facility to be constructed and operated by the applicant, with the sale and purchase obligations under the contracts to aggregate to the total number of renewable energy credits per year to be supplied by the applicant from the new renewable energy facility.

(7) The Agency shall submit its proposed selection of applicants, new renewable energy facilities to be constructed, and renewable energy credit amounts for each procurement event to the Commission for approval. The Commission shall, within 2 business days after receipt of the Agency's proposed selections, approve the proposed selections if it determines that the applicants and the new renewable energy facilities to be constructed meet the selection criteria set forth in this subsection (c-5) and that the Agency seeks approval for contracts of applicable durations aggregating to no more than the maximum amount of renewable energy credits per year authorized by this subsection (c-5) for the procurement event, at a price of $30 per renewable energy credit.

(8) The Agency, in conjunction with its procurement administrator if one is retained, the electric utilities, and potential applicants for contracts to produce and supply renewable energy credits pursuant to this subsection (c-5), shall develop a standard form contract for the sale, delivery and purchase of renewable energy credits pursuant to this subsection (c-5). Each contract resulting from the first procurement event shall allow for a commercial operation date for the new renewable energy facility of either June 1, 2023 or June 1, 2024, with such dates subject to adjustment as provided in this paragraph. Each contract resulting from the second procurement event shall provide for a commercial operation date on June 1 next occurring up to 48 months after execution of the contract. Each contract shall provide that the owner shall receive payments for renewable energy credits for the applicable durations beginning with the commercial operation date of the new renewable energy facility. The form contract shall provide for adjustments to the commercial operation and payment start dates as needed due to any delays in completing the procurement and contracting processes, in finalizing interconnection agreements and installing interconnection facilities, and in obtaining other necessary governmental permits and approvals. The form contract shall be, to the maximum extent possible, consistent with standard electric industry contracts for sale, delivery, and purchase of renewable energy credits while taking into account the specific requirements of this subsection (c-5). The form contract shall provide for over-delivery and under-delivery of renewable energy credits within reasonable ranges during each 12-month period and penalty, default, and enforcement provisions for failure of the selling party to deliver renewable energy credits as specified in the contract and to comply with the requirements of this subsection (c-5). The standard form contract shall specify that all renewable energy credits delivered to the electric utility pursuant to the contract shall be retired. The Agency shall make the proposed contracts available for a reasonable period for comment by potential applicants, and shall publish the final form contract at least 30 days before the date of the first procurement event.

(9) Coal to Solar and Energy Storage Initiative Charge.

(A) By no later than July 1, 2022, each electric utility that served more than 300,000 retail customers in this State as of January 1, 2019 shall file a tariff with the Commission for the billing and collection of a Coal to Solar and Energy Storage Initiative Charge in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act, with such tariff to be effective, following review and approval or modification by the Commission, beginning January 1, 2023. The tariff shall provide for the calculation and setting of the electric utility's Coal to Solar and Energy Storage Initiative Charge to collect revenues estimated to be sufficient, in the aggregate, (i) to enable the electric utility to pay for the renewable energy credits it has contracted to purchase in the delivery year beginning June 1, 2023 and each delivery year thereafter from new renewable energy facilities located at the sites of qualifying electric generating facilities, and (ii) to fund the grant payments to be made in each delivery year by the Department of Commerce and Economic Opportunity, or any successor department or agency, which shall be referred to in this subsection (c-5) as the Department, pursuant to paragraph (10) of this subsection (c-5). The electric utility's tariff shall provide for the billing and collection of the Coal to Solar and Energy Storage Initiative Charge on each kilowatthour of electricity delivered to its delivery services customers within its service territory and shall provide for an annual reconciliation of revenues collected with actual costs, in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act.

(B) Each electric utility shall remit on a monthly basis to the State Treasurer, for deposit in the Coal to Solar and Energy Storage Initiative Fund provided for in this subsection (c-5), the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge in the amount estimated to be needed by the Department for grant payments pursuant to grant contracts entered into by the Department pursuant to paragraph (10) of this subsection (c-5).

(10) Coal to Solar and Energy Storage Initiative Fund.

(A) The Coal to Solar and Energy Storage Initiative Fund is established as a special fund in the State treasury. The Coal to Solar and Energy Storage Initiative Fund is authorized to receive, by statutory deposit, that portion specified in item (B) of paragraph (9) of this subsection (c-5) of moneys collected by electric utilities through imposition of the Coal to Solar and Energy Storage Initiative Charge required by this subsection (c-5). The Coal to Solar and Energy Storage Initiative Fund shall be administered by the Department to provide grants to support the installation and operation of energy storage facilities at the sites of qualifying electric generating facilities meeting the criteria specified in this paragraph (10).

(B) The Coal to Solar and Energy Storage Initiative Fund shall not be subject to sweeps, administrative charges, or chargebacks, including, but not limited to, those authorized under Section 8h of the State Finance Act, that would in any way result in the transfer of those funds from the Coal to Solar and Energy Storage Initiative Fund to any other fund of this State or in having any such funds utilized for any purpose other than the express purposes set forth in this paragraph (10).

(C) The Department shall utilize up to $280,500,000 in the Coal to Solar and Energy Storage Initiative Fund for grants, assuming sufficient qualifying applicants, to support installation of energy storage facilities at the sites of up to 3 qualifying electric generating facilities located in the Midcontinent Independent System Operator, Inc., region in Illinois and the sites of up to 2 qualifying electric generating facilities located in the PJM Interconnection, LLC region in Illinois that meet the criteria set forth in this subparagraph (C). The criteria for receipt of a grant pursuant to this subparagraph (C) are as follows:

(1) the electric generating facility at the site has, or had prior to retirement, an electric generating capacity of at least 150 megawatts;

(2) the electric generating facility burns (or burned prior to retirement) coal as its primary source of fuel;

(3) if the electric generating facility is retired, it was retired subsequent to January 1, 2016;

(4) the owner of the electric generating facility has not been selected by the Agency pursuant to this subsection (c-5) of this Section to enter into a contract to sell renewable energy credits to one or more electric utilities from a new renewable energy facility located or to be located at or adjacent to the site at which the electric generating facility is located;

(5) the electric generating facility located at the site was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act;

(6) the electric generating facility at the site is not owned by (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in items (i) or (ii);

(7) the proposed energy storage facility at the site will have energy storage capacity of at least 37 megawatts;

(8) the owner commits to place the energy storage facility into commercial operation on either June 1, 2023, June 1, 2024, or June 1, 2025, with such date subject to adjustment as needed due to any delays in completing the grant contracting process, in finalizing interconnection agreements and in installing interconnection facilities, and in obtaining necessary governmental permits and approvals;

(9) the owner agrees that the new energy storage facility will be constructed or installed by a qualified entity or entities consistent with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted under that Section;

(10) the owner agrees that personnel operating the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function;

(11) the owner commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the owner's employees engaged in construction activities associated with the new energy storage facility and to the employees of the owner's contractors engaged in construction activities associated with the new energy storage facility, and that, on or before the commercial operation date of the new energy storage facility, the owner shall file a report with the Department certifying that the requirements of this subparagraph (11) have been met; and

(12) the owner commits that if selected to receive a grant, it will negotiate a project labor agreement for the construction of the new energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

The Department shall accept applications for this grant program until March 31, 2022 and shall announce the award of grants no later than June 1, 2022. The Department shall make the grant payments to a recipient in equal annual amounts for 10 years following the date the energy storage facility is placed into commercial operation. The annual grant payments to a qualifying energy storage facility shall be $110,000 per megawatt of energy storage capacity, with total annual grant payments pursuant to this subparagraph (C) for qualifying energy storage facilities not to exceed $28,050,000 in any year.

(D) Grants of funding for energy storage facilities pursuant to subparagraph (C) of this paragraph (10), from the Coal to Solar and Energy Storage Initiative Fund, shall be memorialized in grant contracts between the Department and the recipient. The grant contracts shall specify the date or dates in each year on which the annual grant payments shall be paid.

(E) All disbursements from the Coal to Solar and Energy Storage Initiative Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Director of the Department or by the person or persons designated by the Director of the Department for that purpose. The Comptroller is authorized to draw the warrants upon vouchers so signed. The Treasurer shall accept all written warrants so signed and shall be released from liability for all payments made on those warrants.

(11) Diversity, equity, and inclusion plans.

(A) Each applicant selected in a procurement event to contract to supply renewable energy credits in accordance with this subsection (c-5) and each owner selected by the Department to receive a grant or grants to support the construction and operation of a new energy storage facility or facilities in accordance with this subsection (c-5) shall, within 60 days following the Commission's approval of the applicant to contract to supply renewable energy credits or within 60 days following execution of a grant contract with the Department, as applicable, submit to the Commission a diversity, equity, and inclusion plan setting forth the applicant's or owner's numeric goals for the diversity composition of its supplier entities for the new renewable energy facility or new energy storage facility, as applicable, which shall be referred to for purposes of this paragraph (11) as the project, and the applicant's or owner's action plan and schedule for achieving those goals.

(B) For purposes of this paragraph (11), diversity composition shall be based on the percentage, which shall be a minimum of 25%, of eligible expenditures for contract awards for materials and services (which shall be defined in the plan) to business enterprises owned by minority persons, women, or persons with disabilities as defined in Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act, to LGBTQ business enterprises, to veteran-owned business enterprises, and to business enterprises located in environmental justice communities. The diversity composition goals of the plan may include eligible expenditures in areas for vendor or supplier opportunities in addition to development and construction of the project, and may exclude from eligible expenditures materials and services with limited market availability, limited production and availability from suppliers in the United States, such as solar panels and storage batteries, and material and services that are subject to critical energy infrastructure or cybersecurity requirements or restrictions. The plan may provide that the diversity composition goals may be met through Tier 1 Direct or Tier 2 subcontracting expenditures or a combination thereof for the project.

(C) The plan shall provide for, but not be limited to: (i) internal initiatives, including multi-tier initiatives, by the applicant or owner, or by its engineering, procurement and construction contractor if one is used for the project, which for purposes of this paragraph (11) shall be referred to as the EPC contractor, to enable diverse businesses to be considered fairly for selection to provide materials and services; (ii) requirements for the applicant or owner or its EPC contractor to proactively solicit and utilize diverse businesses to provide materials and services; and (iii) requirements for the applicant or owner or its EPC contractor to hire a diverse workforce for the project. The plan shall include a description of the applicant's or owner's diversity recruiting efforts both for the project and for other areas of the applicant's or owner's business operations. The plan shall provide for the imposition of financial penalties on the applicant's or owner's EPC contractor for failure to exercise best efforts to comply with and execute the EPC contractor's diversity obligations under the plan. The plan may provide for the applicant or owner to set aside a portion of the work on the project to serve as an incubation program for qualified businesses, as specified in the plan, owned by minority persons, women, persons with disabilities, LGBTQ persons, and veterans, and businesses located in environmental justice communities, seeking to enter the renewable energy industry.

(D) The applicant or owner may submit a revised or updated plan to the Commission from time to time as circumstances warrant. The applicant or owner shall file annual reports with the Commission detailing the applicant's or owner's progress in implementing its plan and achieving its goals and any modifications the applicant or owner has made to its plan to better achieve its diversity, equity and inclusion goals. The applicant or owner shall file a final report on the fifth June 1 following the commercial operation date of the new renewable energy resource or new energy storage facility, but the applicant or owner shall thereafter continue to be subject to applicable reporting requirements of Section 5-117 of the Public Utilities Act.

(c-10) Equity accountability system. It is the purpose of this subsection (c-10) to create an equity accountability system, which includes the minimum equity standards for all renewable energy procurements, the equity category of the Adjustable Block Program, and the equity prioritization for noncompetitive procurements, that is successful in advancing priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes. Further, it is the purpose of this subsection to ensure that this equity accountability system is successful in advancing equity across Illinois by providing access to the clean energy economy for businesses and workers from communities that have been historically excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes.

(1) Minimum equity standards. The Agency shall create programs with the purpose of increasing access to and development of equity eligible contractors, who are prime contractors and subcontractors, across all of the programs it manages. All applications for renewable energy credit procurements shall comply with specific minimum equity commitments. Starting in the delivery year immediately following the next long-term renewable resources procurement plan, at least 10% of the project workforce for each entity participating in a procurement program outlined in this subsection (c-10) must be done by equity eligible persons or equity eligible contractors. The Agency shall increase the minimum percentage each delivery year thereafter by increments that ensure a statewide average of 30% of the project workforce for each entity participating in a procurement program is done by equity eligible persons or equity eligible contractors by 2030. The Agency shall propose a schedule of percentage increases to the minimum equity standards in its draft revised renewable energy resources procurement plan submitted to the Commission for approval pursuant to paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. In determining these annual increases, the Agency shall have the discretion to establish different minimum equity standards for different types of procurements and different regions of the State if the Agency finds that doing so will further the purposes of this subsection (c-10). The proposed schedule of annual increases shall be revisited and updated on an annual basis. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, clean energy industry representatives, and community-based organizations that work with such persons and contractors.

(A) At the start of each delivery year, the Agency shall require a compliance plan from each entity participating in a procurement program of subsection (c) of this Section that demonstrates how they will achieve compliance with the minimum equity standard percentage for work completed in that delivery year. If an entity applies for its approved vendor or designee status between delivery years, the Agency shall require a compliance plan at the time of application.

(B) Halfway through each delivery year, the Agency shall require each entity participating in a procurement program to confirm that it will achieve compliance in that delivery year, when applicable. The Agency may offer corrective action plans to entities that are not on track to achieve compliance.

(C) At the end of each delivery year, each entity participating and completing work in that delivery year in a procurement program of subsection (c) shall submit a report to the Agency that demonstrates how it achieved compliance with the minimum equity standards percentage for that delivery year.

(D) The Agency shall prohibit participation in procurement programs by an approved vendor or designee, as applicable, or entities with which an approved vendor or designee, as applicable, shares a common parent company if an approved vendor or designee, as applicable, failed to meet the minimum equity standards for the prior delivery year. Waivers approved for lack of equity eligible persons or equity eligible contractors in a geographic area of a project shall not count against the approved vendor or designee. The Agency shall offer a corrective action plan for any such entities to assist them in obtaining compliance and shall allow continued access to procurement programs upon an approved vendor or designee demonstrating compliance.

(E) The Agency shall pursue efficiencies achieved by combining with other approved vendor or designee reporting.

(2) Equity accountability system within the Adjustable Block program. The equity category described in item (vi) of subparagraph (K) of subsection (c) is only available to applicants that are equity eligible contractors.

(3) Equity accountability system within competitive procurements. Through its long-term renewable resources procurement plan, the Agency shall develop requirements for ensuring that competitive procurement processes, including utility-scale solar, utility-scale wind, and brownfield site photovoltaic projects, advance the equity goals of this subsection (c-10). Subject to Commission approval, the Agency shall develop bid application requirements and a bid evaluation methodology for ensuring that utilization of equity eligible contractors, whether as bidders or as participants on project development, is optimized, including requiring that winning or successful applicants for utility-scale projects are or will partner with equity eligible contractors and giving preference to bids through which a higher portion of contract value flows to equity eligible contractors. To the extent practicable, entities participating in competitive procurements shall also be required to meet all the equity accountability requirements for approved vendors and their designees under this subsection (c-10). In developing these requirements, the Agency shall also consider whether equity goals can be further advanced through additional measures.

(4) In the first revision to the long-term renewable energy resources procurement plan and each revision thereafter, the Agency shall include the following:

(A) The current status and number of equity eligible contractors listed in the Energy Workforce Equity Database designed in subsection (c-25), including the number of equity eligible contractors with current certifications as issued by the Agency.

(B) A mechanism for measuring, tracking, and reporting project workforce at the approved vendor or designee level, as applicable, which shall include a measurement methodology and records to be made available for audit by the Agency or the Program Administrator.

(C) A program for approved vendors, designees, eligible persons, and equity eligible contractors to receive trainings, guidance, and other support from the Agency or its designee regarding the equity category outlined in item (vi) of subparagraph (K) of paragraph (1) of subsection (c) and in meeting the minimum equity standards of this subsection (c-10).

(D) A process for certifying equity eligible contractors and equity eligible persons. The certification process shall coordinate with the Energy Workforce Equity Database set forth in subsection (c-25).

(E) An application for waiver of the minimum equity standards of this subsection, which the Agency shall have the discretion to grant in rare circumstances. The Agency may grant such a waiver where the applicant provides evidence of significant efforts toward meeting the minimum equity commitment, including: use of the Energy Workforce Equity Database; efforts to hire or contract with entities that hire eligible persons; and efforts to establish contracting relationships with eligible contractors. The Agency shall support applicants in understanding the Energy Workforce Equity Database and other resources for pursuing compliance of the minimum equity standards. Waivers shall be project-specific, unless the Agency deems it necessary to grant a waiver across a portfolio of projects, and in effect for no longer than one year. Any waiver extension or subsequent waiver request from an applicant shall be subject to the requirements of this Section and shall specify efforts made to reach compliance. When considering whether to grant a waiver, and to what extent, the Agency shall consider the degree to which similarly situated applicants have been able to meet these minimum equity commitments. For repeated waiver requests for specific lack of eligible persons or eligible contractors available, the Agency shall make recommendations to target recruitment to add such eligible persons or eligible contractors to the database.

(5) The Agency shall collect information about work on projects or portfolios of projects subject to these minimum equity standards to ensure compliance with this subsection (c-10). Reporting in furtherance of this requirement may be combined with other annual reporting requirements. Such reporting shall include proof of certification of each equity eligible contractor or equity eligible person during the applicable time period.

(6) The Agency shall keep confidential all information and communication that provides private or personal information.

(7) Modifications to the equity accountability system. As part of the update of the long-term renewable resources procurement plan to be initiated in 2023, or sooner if the Agency deems necessary, the Agency shall determine the extent to which the equity accountability system described in this subsection (c-10) has advanced the goals of this amendatory Act of the 102nd General Assembly, including through the inclusion of equity eligible persons and equity eligible contractors in renewable energy credit projects. If the Agency finds that the equity accountability system has failed to meet those goals to its fullest potential, the Agency may revise the following criteria for future Agency procurements: (A) the percentage of project workforce, or other appropriate workforce measure, certified as equity eligible persons or equity eligible contractors; (B) definitions for equity investment eligible persons and equity investment eligible community; and (C) such other modifications necessary to advance the goals of this amendatory Act of the 102nd General Assembly effectively. Such revised criteria may also establish distinct equity accountability systems for different types of procurements or different regions of the State if the Agency finds that doing so will further the purposes of such programs. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, and community-based organizations that work with such persons and contractors.

(c-15) Racial discrimination elimination powers and process.

(1) Purpose. It is the purpose of this subsection to empower the Agency and other State actors to remedy racial discrimination in Illinois' clean energy economy as effectively and expediently as possible, including through the use of race-conscious remedies, such as race-conscious contracting and hiring goals, as consistent with State and federal law.

(2) Racial disparity and discrimination review process.

(A) Within one year after awarding contracts using the equity actions processes established in this Section, the Agency shall publish a report evaluating the effectiveness of the equity actions point criteria of this Section in increasing participation of equity eligible persons and equity eligible contractors. The report shall disaggregate participating workers and contractors by race and ethnicity. The report shall be forwarded to the Governor, the General Assembly, and the Illinois Commerce Commission and be made available to the public.

(B) As soon as is practicable thereafter, the Agency, in consultation with the Department of Commerce and Economic Opportunity, Department of Labor, and other agencies that may be relevant, shall commission and publish a disparity and availability study that measures the presence and impact of discrimination on minority businesses and workers in Illinois' clean energy economy. The Agency may hire consultants and experts to conduct the disparity and availability study, with the retention of those consultants and experts exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Illinois Power Agency shall forward a copy of its findings and recommendations to the Governor, the General Assembly, and the Illinois Commerce Commission. If the disparity and availability study establishes a strong basis in evidence that there is discrimination in Illinois' clean energy economy, the Agency, Department of Commerce and Economic Opportunity, Department of Labor, Department of Corrections, and other appropriate agencies shall take appropriate remedial actions, including race-conscious remedial actions as consistent with State and federal law, to effectively remedy this discrimination. Such remedies may include modification of the equity accountability system as described in subsection (c-10).

(c-20) Program data collection.

(1) Purpose. Data collection, data analysis, and reporting are critical to ensure that the benefits of the clean energy economy provided to Illinois residents and businesses are equitably distributed across the State. The Agency shall collect data from program applicants in order to track and improve equitable distribution of benefits across Illinois communities for all procurements the Agency conducts. The Agency shall use this data to, among other things, measure any potential impact of racial discrimination on the distribution of benefits and provide information necessary to correct any discrimination through methods consistent with State and federal law.

(2) Agency collection of program data. The Agency shall collect demographic and geographic data for each entity awarded contracts under any Agency-administered program.

(3) Required information to be collected. The Agency shall collect the following information from applicants and program participants where applicable:

(A) demographic information, including racial or ethnic identity for real persons employed, contracted, or subcontracted through the program and owners of businesses or entities that apply to receive renewable energy credits from the Agency;

(B) geographic location of the residency of real persons employed, contracted, or subcontracted through the program and geographic location of the headquarters of the business or entity that applies to receive renewable energy credits from the Agency; and

(C) any other information the Agency determines is necessary for the purpose of achieving the purpose of this subsection.

(4) Publication of collected information. The Agency shall publish, at least annually, information on the demographics of program participants on an aggregate basis.

(5) Nothing in this subsection shall be interpreted to limit the authority of the Agency, or other agency or department of the State, to require or collect demographic information from applicants of other State programs.

(c-25) Energy Workforce Equity Database.

(1) The Agency, in consultation with the Department of Commerce and Economic Opportunity, shall create an Energy Workforce Equity Database, and may contract with a third party to do so ("database program administrator"). If the Department decides to contract with a third party, that third party shall be exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Energy Workforce Equity Database shall be a searchable database of suppliers, vendors, and subcontractors for clean energy industries that is:

(A) publicly accessible;

(B) easy for people to find and use;

(C) organized by company specialty or field;

(D) region-specific; and

(E) populated with information including, but not limited to, contacts for suppliers, vendors, or subcontractors who are minority and women-owned business enterprise certified or who participate or have participated in any of the programs described in this Act.

(2) The Agency shall create an easily accessible, public facing online tool using the database information that includes, at a minimum, the following:

(A) a map of environmental justice and equity investment eligible communities;

(B) job postings and recruiting opportunities;

(C) a means by which recruiting clean energy companies can find and interact with current or former participants of clean energy workforce training programs;

(D) information on workforce training service providers and training opportunities available to prospective workers;

(E) renewable energy company diversity reporting;

(F) a list of equity eligible contractors with their contact information, types of work performed, and locations worked in;

(G) reporting on outcomes of the programs described in the workforce programs of the Energy Transition Act, including information such as, but not limited to, retention rate, graduation rate, and placement rates of trainees; and

(H) information about the Jobs and Environmental Justice Grant Program, the Clean Energy Jobs and Justice Fund, and other sources of capital.

(3) The Agency shall ensure the database is regularly updated to ensure information is current and shall coordinate with the Department of Commerce and Economic Opportunity to ensure that it includes information on individuals and entities that are or have participated in the Clean Jobs Workforce Network Program, Clean Energy Contractor Incubator Program, Returning Residents Clean Jobs Training Program, or Clean Energy Primes Contractor Accelerator Program.

(c-30) Enforcement of minimum equity standards. All entities seeking renewable energy credits must submit an annual report to demonstrate compliance with each of the equity commitments required under subsection (c-10). If the Agency concludes the entity has not met or maintained its minimum equity standards required under the applicable subparagraphs under subsection (c-10), the Agency shall deny the entity's ability to participate in procurement programs in subsection (c), including by withholding approved vendor or designee status. The Agency may require the entity to enter into a corrective action plan. An entity that is not recertified for failing to meet required equity actions in subparagraph (c-10) may reapply once they have a corrective action plan and achieve compliance with the minimum equity standards.

(d) Clean coal portfolio standard.

(1) The procurement plans shall include electricity generated using clean coal. Each utility shall enter into one or more sourcing agreements with the initial clean coal facility, as provided in paragraph (3) of this subsection (d), covering electricity generated by the initial clean coal facility representing at least 5% of each utility's total supply to serve the load of eligible retail customers in 2015 and each year thereafter, as described in paragraph (3) of this subsection (d), subject to the limits specified in paragraph (2) of this subsection (d). It is the goal of the State that by January 1, 2025, 25% of the electricity used in the State shall be generated by cost-effective clean coal facilities. For purposes of this subsection (d), "cost-effective" means that the expenditures pursuant to such sourcing agreements do not cause the limit stated in paragraph (2) of this subsection (d) to be exceeded and do not exceed cost-based benchmarks, which shall be developed to assess all expenditures pursuant to such sourcing agreements covering electricity generated by clean coal facilities, other than the initial clean coal facility, by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

A utility party to a sourcing agreement shall immediately retire any emission credits that it receives in connection with the electricity covered by such agreement.

Utilities shall maintain adequate records documenting the purchases under the sourcing agreement to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act.

A utility shall be deemed to have complied with the clean coal portfolio standard specified in this subsection (d) if the utility enters into a sourcing agreement as required by this subsection (d).

(2) For purposes of this subsection (d), the required execution of sourcing agreements with the initial clean coal facility for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the planning year ending immediately prior to the agreement's execution. For purposes of this subsection (d), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges and add-on taxes.

Notwithstanding the requirements of this subsection (d), the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any given year shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to:

(A) in 2010, no more than 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(B) in 2011, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2010 or 1% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(C) in 2012, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2011 or 1.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(D) in 2013, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2012 or 2% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009; and

(E) thereafter, the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of (i) 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or (ii) the incremental amount per kilowatthour paid for these resources in 2013. These requirements may be altered only as provided by statute.

No later than June 30, 2015, the Commission shall review the limitation on the total amount paid under sourcing agreements, if any, with clean coal facilities pursuant to this subsection (d) and report to the General Assembly its findings as to whether that limitation unduly constrains the amount of electricity generated by cost-effective clean coal facilities that is covered by sourcing agreements.

(3) Initial clean coal facility. In order to promote development of clean coal facilities in Illinois, each electric utility subject to this Section shall execute a sourcing agreement to source electricity from a proposed clean coal facility in Illinois (the "initial clean coal facility") that will have a nameplate capacity of at least 500 MW when commercial operation commences, that has a final Clean Air Act permit on June 1, 2009 (the effective date of Public Act 95-1027), and that will meet the definition of clean coal facility in Section 1-10 of this Act when commercial operation commences. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of paragraph (4) of this subsection (d) and shall be executed within 90 days after any such approval by the General Assembly. The Agency and the Commission shall have authority to inspect all books and records associated with the initial clean coal facility during the term of such a sourcing agreement. A utility's sourcing agreement for electricity produced by the initial clean coal facility shall include:

(A) a formula contractual price (the "contract price") approved pursuant to paragraph (4) of this subsection (d), which shall:

(i) be determined using a cost of service methodology employing either a level or deferred capital recovery component, based on a capital structure consisting of 45% equity and 55% debt, and a return on equity as may be approved by the Federal Energy Regulatory Commission, which in any case may not exceed the lower of 11.5% or the rate of return approved by the General Assembly pursuant to paragraph (4) of this subsection (d); and

(ii) provide that all miscellaneous net revenue, including but not limited to net revenue from the sale of emission allowances, if any, substitute natural gas, if any, grants or other support provided by the State of Illinois or the United States Government, firm transmission rights, if any, by-products produced by the facility, energy or capacity derived from the facility and not covered by a sourcing agreement pursuant to paragraph (3) of this subsection (d) or item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, whether generated from the synthesis gas derived from coal, from SNG, or from natural gas, shall be credited against the revenue requirement for this initial clean coal facility;

(B) power purchase provisions, which shall:

(i) provide that the utility party to such sourcing agreement shall pay the contract price for electricity delivered under such sourcing agreement;

(ii) require delivery of electricity to the regional transmission organization market of the utility that is party to such sourcing agreement;

(iii) require the utility party to such sourcing agreement to buy from the initial clean coal facility in each hour an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount purchased by the utility in any year will be limited by paragraph (2) of this subsection (d); and

(iv) be considered pre-existing contracts in such utility's procurement plans for eligible retail customers;

(C) contract for differences provisions, which shall:

(i) require the utility party to such sourcing agreement to contract with the initial clean coal facility in each hour with respect to an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the utility's service territory in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount paid by the utility in any year will be limited by paragraph (2) of this subsection (d);

(ii) provide that the utility's payment obligation in respect of the quantity of electricity determined pursuant to the preceding clause (i) shall be limited to an amount equal to (1) the difference between the contract price determined pursuant to subparagraph (A) of paragraph (3) of this subsection (d) and the day-ahead price for electricity delivered to the regional transmission organization market of the utility that is party to such sourcing agreement (or any successor delivery point at which such utility's supply obligations are financially settled on an hourly basis) (the "reference price") on the day preceding the day on which the electricity is delivered to the initial clean coal facility busbar, multiplied by (2) the quantity of electricity determined pursuant to the preceding clause (i); and

(iii) not require the utility to take physical delivery of the electricity produced by the facility;

(D) general provisions, which shall:

(i) specify a term of no more than 30 years, commencing on the commercial operation date of the facility;

(ii) provide that utilities shall maintain adequate records documenting purchases under the sourcing agreements entered into to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act;

(iii) provide that all costs associated with the initial clean coal facility will be periodically reported to the Federal Energy Regulatory Commission and to purchasers in accordance with applicable laws governing cost-based wholesale power contracts;

(iv) permit the Illinois Power Agency to assume ownership of the initial clean coal facility, without monetary consideration and otherwise on reasonable terms acceptable to the Agency, if the Agency so requests no less than 3 years prior to the end of the stated contract term;

(v) require the owner of the initial clean coal facility to provide documentation to the Commission each year, starting in the facility's first year of commercial operation, accurately reporting the quantity of carbon emissions from the facility that have been captured and sequestered and report any quantities of carbon released from the site or sites at which carbon emissions were sequestered in prior years, based on continuous monitoring of such sites. If, in any year after the first year of commercial operation, the owner of the facility fails to demonstrate that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon dioxide into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The cost of such offsets for the facility that are not recoverable shall not exceed $15 million in any given year. No costs of any such purchases of carbon offsets may be recovered from a utility or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements specified in paragraph (3) of this subsection (d) shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General. The Commission may, in the course of the review specified in item (vii), reduce the allowable return on equity for the facility if the facility willfully fails to comply with the carbon capture and sequestration requirements set forth in this item (v);

(vi) include limits on, and accordingly provide for modification of, the amount the utility is required to source under the sourcing agreement consistent with paragraph (2) of this subsection (d);

(vii) require Commission review: (1) to determine the justness, reasonableness, and prudence of the inputs to the formula referenced in subparagraphs (A)(i) through (A)(iii) of paragraph (3) of this subsection (d), prior to an adjustment in those inputs including, without limitation, the capital structure and return on equity, fuel costs, and other operations and maintenance costs and (2) to approve the costs to be passed through to customers under the sourcing agreement by which the utility satisfies its statutory obligations. Commission review shall occur no less than every 3 years, regardless of whether any adjustments have been proposed, and shall be completed within 9 months;

(viii) limit the utility's obligation to such amount as the utility is allowed to recover through tariffs filed with the Commission, provided that neither the clean coal facility nor the utility waives any right to assert federal pre-emption or any other argument in response to a purported disallowance of recovery costs;

(ix) limit the utility's or alternative retail electric supplier's obligation to incur any liability until such time as the facility is in commercial operation and generating power and energy and such power and energy is being delivered to the facility busbar;

(x) provide that the owner or owners of the initial clean coal facility, which is the counterparty to such sourcing agreement, shall have the right from time to time to elect whether the obligations of the utility party thereto shall be governed by the power purchase provisions or the contract for differences provisions;

(xi) append documentation showing that the formula rate and contract, insofar as they relate to the power purchase provisions, have been approved by the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act;

(xii) provide that any changes to the terms of the contract, insofar as such changes relate to the power purchase provisions, are subject to review under the public interest standard applied by the Federal Energy Regulatory Commission pursuant to Sections 205 and 206 of the Federal Power Act; and

(xiii) conform with customary lender requirements in power purchase agreements used as the basis for financing non-utility generators.

(4) Effective date of sourcing agreements with the initial clean coal facility. Any proposed sourcing agreement with the initial clean coal facility shall not become effective unless the following reports are prepared and submitted and authorizations and approvals obtained:

(i) Facility cost report. The owner of the initial clean coal facility shall submit to the Commission, the Agency, and the General Assembly a front-end engineering and design study, a facility cost report, method of financing (including but not limited to structure and associated costs), and an operating and maintenance cost quote for the facility (collectively "facility cost report"), which shall be prepared in accordance with the requirements of this paragraph (4) of subsection (d) of this Section, and shall provide the Commission and the Agency access to the work papers, relied upon documents, and any other backup documentation related to the facility cost report.

(ii) Commission report. Within 6 months following receipt of the facility cost report, the Commission, in consultation with the Agency, shall submit a report to the General Assembly setting forth its analysis of the facility cost report. Such report shall include, but not be limited to, a comparison of the costs associated with electricity generated by the initial clean coal facility to the costs associated with electricity generated by other types of generation facilities, an analysis of the rate impacts on residential and small business customers over the life of the sourcing agreements, and an analysis of the likelihood that the initial clean coal facility will commence commercial operation by and be delivering power to the facility's busbar by 2016. To assist in the preparation of its report, the Commission, in consultation with the Agency, may hire one or more experts or consultants, the costs of which shall be paid for by the owner of the initial clean coal facility. The Commission and Agency may begin the process of selecting such experts or consultants prior to receipt of the facility cost report.

(iii) General Assembly approval. The proposed sourcing agreements shall not take effect unless, based on the facility cost report and the Commission's report, the General Assembly enacts authorizing legislation approving (A) the projected price, stated in cents per kilowatthour, to be charged for electricity generated by the initial clean coal facility, (B) the projected impact on residential and small business customers' bills over the life of the sourcing agreements, and (C) the maximum allowable return on equity for the project; and

(iv) Commission review. If the General Assembly enacts authorizing legislation pursuant to subparagraph (iii) approving a sourcing agreement, the Commission shall, within 90 days of such enactment, complete a review of such sourcing agreement. During such time period, the Commission shall implement any directive of the General Assembly, resolve any disputes between the parties to the sourcing agreement concerning the terms of such agreement, approve the form of such agreement, and issue an order finding that the sourcing agreement is prudent and reasonable.

The facility cost report shall be prepared as follows:

(A) The facility cost report shall be prepared by duly licensed engineering and construction firms detailing the estimated capital costs payable to one or more contractors or suppliers for the engineering, procurement and construction of the components comprising the initial clean coal facility and the estimated costs of operation and maintenance of the facility. The facility cost report shall include:

(i) an estimate of the capital cost of the core plant based on one or more front end engineering and design studies for the gasification island and related facilities. The core plant shall include all civil, structural, mechanical, electrical, control, and safety systems.

(ii) an estimate of the capital cost of the balance of the plant, including any capital costs associated with sequestration of carbon dioxide emissions and all interconnects and interfaces required to operate the facility, such as transmission of electricity, construction or backfeed power supply, pipelines to transport substitute natural gas or carbon dioxide, potable water supply, natural gas supply, water supply, water discharge, landfill, access roads, and coal delivery.

The quoted construction costs shall be expressed in nominal dollars as of the date that the quote is prepared and shall include capitalized financing costs during construction, taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the construction cost quote is expressed.

(B) The front end engineering and design study for the gasification island and the cost study for the balance of plant shall include sufficient design work to permit quantification of major categories of materials, commodities and labor hours, and receipt of quotes from vendors of major equipment required to construct and operate the clean coal facility.

(C) The facility cost report shall also include an operating and maintenance cost quote that will provide the estimated cost of delivered fuel, personnel, maintenance contracts, chemicals, catalysts, consumables, spares, and other fixed and variable operations and maintenance costs. The delivered fuel cost estimate will be provided by a recognized third party expert or experts in the fuel and transportation industries. The balance of the operating and maintenance cost quote, excluding delivered fuel costs, will be developed based on the inputs provided by duly licensed engineering and construction firms performing the construction cost quote, potential vendors under long-term service agreements and plant operating agreements, or recognized third party plant operator or operators.

The operating and maintenance cost quote (including the cost of the front end engineering and design study) shall be expressed in nominal dollars as of the date that the quote is prepared and shall include taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the operating and maintenance cost quote is expressed.

(D) The facility cost report shall also include an analysis of the initial clean coal facility's ability to deliver power and energy into the applicable regional transmission organization markets and an analysis of the expected capacity factor for the initial clean coal facility.

(E) Amounts paid to third parties unrelated to the owner or owners of the initial clean coal facility to prepare the core plant construction cost quote, including the front end engineering and design study, and the operating and maintenance cost quote will be reimbursed through Coal Development Bonds.

(5) Re-powering and retrofitting coal-fired power plants previously owned by Illinois utilities to qualify as clean coal facilities. During the 2009 procurement planning process and thereafter, the Agency and the Commission shall consider sourcing agreements covering electricity generated by power plants that were previously owned by Illinois utilities and that have been or will be converted into clean coal facilities, as defined by Section 1-10 of this Act. Pursuant to such procurement planning process, the owners of such facilities may propose to the Agency sourcing agreements with utilities and alternative retail electric suppliers required to comply with subsection (d) of this Section and item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, covering electricity generated by such facilities. In the case of sourcing agreements that are power purchase agreements, the contract price for electricity sales shall be established on a cost of service basis. In the case of sourcing agreements that are contracts for differences, the contract price from which the reference price is subtracted shall be established on a cost of service basis. The Agency and the Commission may approve any such utility sourcing agreements that do not exceed cost-based benchmarks developed by the procurement administrator, in consultation with the Commission staff, Agency staff and the procurement monitor, subject to Commission review and approval. The Commission shall have authority to inspect all books and records associated with these clean coal facilities during the term of any such contract.

(6) Costs incurred under this subsection (d) or pursuant to a contract entered into under this subsection (d) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

(d-5) Zero emission standard.

(1) Beginning with the delivery year commencing on June 1, 2017, the Agency shall, for electric utilities that serve at least 100,000 retail customers in this State, procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the actual amount of electricity delivered by each electric utility to retail customers in the State during calendar year 2014. For an electric utility serving fewer than 100,000 retail customers in this State that requested, under Section 16-111.5 of the Public Utilities Act, that the Agency procure power and energy for all or a portion of the utility's Illinois load for the delivery year commencing June 1, 2016, the Agency shall procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the portion of power and energy to be procured by the Agency for the utility. The duration of the contracts procured under this subsection (d-5) shall be for a term of 10 years ending May 31, 2027. The quantity of zero emission credits to be procured under the contracts shall be all of the zero emission credits generated by the zero emission facility in each delivery year; however, if the zero emission facility is owned by more than one entity, then the quantity of zero emission credits to be procured under the contracts shall be the amount of zero emission credits that are generated from the portion of the zero emission facility that is owned by the winning supplier.

The 16% value identified in this paragraph (1) is the average of the percentage targets in subparagraph (B) of paragraph (1) of subsection (c) of this Section for the 5 delivery years beginning June 1, 2017.

The procurement process shall be subject to the following provisions:

(A) Those zero emission facilities that intend to participate in the procurement shall submit to the Agency the following eligibility information for each zero emission facility on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the zero emission facility;

(ii) the amount of power generated annually for each of the years 2005 through 2015, and the projected zero emission credits to be generated over the remaining useful life of the zero emission facility, which shall be used to determine the capability of each facility;

(iii) the annual zero emission facility cost projections, expressed on a per megawatthour basis, over the next 6 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; non-fuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this item (iii), that the costs could reasonably be avoided only by ceasing operations of the zero emission facility; and

(iv) a commitment to continue operating, for the duration of the contract or contracts executed under the procurement held under this subsection (d-5), the zero emission facility that produces the zero emission credits to be procured in the procurement.

The information described in item (iii) of this subparagraph (A) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(B) The price for each zero emission credit procured under this subsection (d-5) for each delivery year shall be in an amount that equals the Social Cost of Carbon, expressed on a price per megawatthour basis. However, to ensure that the procurement remains affordable to retail customers in this State if electricity prices increase, the price in an applicable delivery year shall be reduced below the Social Cost of Carbon by the amount ("Price Adjustment") by which the market price index for the applicable delivery year exceeds the baseline market price index for the consecutive 12-month period ending May 31, 2016. If the Price Adjustment is greater than or equal to the Social Cost of Carbon in an applicable delivery year, then no payments shall be due in that delivery year. The components of this calculation are defined as follows:

(i) Social Cost of Carbon: The Social Cost of Carbon is $16.50 per megawatthour, which is based on the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each year of the program. Beginning with the delivery year commencing June 1, 2023, the price per megawatthour shall increase by $1 per megawatthour, and continue to increase by an additional $1 per megawatthour each delivery year thereafter.

(ii) Baseline market price index: The baseline market price index for the consecutive 12-month period ending May 31, 2016 is $31.40 per megawatthour, which is based on the sum of (aa) the average day-ahead energy price across all hours of such 12-month period at the PJM Interconnection LLC Northern Illinois Hub, (bb) 50% multiplied by the Base Residual Auction, or its successor, capacity price for the rest of the RTO zone group determined by PJM Interconnection LLC, divided by 24 hours per day, and (cc) 50% multiplied by the Planning Resource Auction, or its successor, capacity price for Zone 4 determined by the Midcontinent Independent System Operator, Inc., divided by 24 hours per day.

(iii) Market price index: The market price index for a delivery year shall be the sum of projected energy prices and projected capacity prices determined as follows:

(aa) Projected energy prices: the projected energy prices for the applicable delivery year shall be calculated once for the year using the forward market price for the PJM Interconnection, LLC Northern Illinois Hub. The forward market price shall be calculated as follows: the energy forward prices for each month of the applicable delivery year averaged for each trade date during the calendar year immediately preceding that delivery year to produce a single energy forward price for the delivery year. The forward market price calculation shall use data published by the Intercontinental Exchange, or its successor.

(bb) Projected capacity prices:

(I) For the delivery years commencing June 1, 2017, June 1, 2018, and June 1, 2019, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the rest of the RTO zone group as determined by PJM Interconnection LLC, divided by 24 hours per day and, (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

(II) For the delivery year commencing June 1, 2020, and each year thereafter, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the ComEd zone as determined by PJM Interconnection LLC, divided by 24 hours per day, and (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

For purposes of this subsection (d-5):

"Rest of the RTO" and "ComEd Zone" shall have the meaning ascribed to them by PJM Interconnection, LLC.

"RTO" means regional transmission organization.

(C) No later than 45 days after June 1, 2017 (the effective date of Public Act 99-906), the Agency shall publish its proposed zero emission standard procurement plan. The plan shall be consistent with the provisions of this paragraph (1) and shall provide that winning bids shall be selected based on public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. In particular, the selection of winning bids shall take into account the incremental environmental benefits resulting from the procurement, such as any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would cease to exist if the procurements were not held, including the preservation of zero emission facilities. The plan shall also describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement and given full effect.

For purposes of developing the plan, the Agency shall consider any reports issued by a State agency, board, or commission under House Resolution 1146 of the 98th General Assembly and paragraph (4) of subsection (d) of this Section, as well as publicly available analyses and studies performed by or for regional transmission organizations that serve the State and their independent market monitors.

Upon publishing of the zero emission standard procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 10 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 60 days later than June 1, 2017 (the effective date of Public Act 99-906), the Agency shall revise the plan as necessary based on the comments received and file its zero emission standard procurement plan with the Commission.

If the Commission determines that the plan will result in the procurement of cost-effective zero emission credits, then the Commission shall, after notice and hearing, but no later than 45 days after the Agency filed the plan, approve the plan or approve with modification. For purposes of this subsection (d-5), "cost effective" means the projected costs of procuring zero emission credits from zero emission facilities do not cause the limit stated in paragraph (2) of this subsection to be exceeded.

(C-5) As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the winning bids satisfy the public interest criteria described in subparagraph (C) of this paragraph (1) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of winning bids takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would have ceased to exist if the procurements had not been held, such as the preservation of zero emission facilities;

(iii) quantify the environmental benefit of preserving the resources identified in item (ii) of this subparagraph (C-5), including the following:

(aa) the value of avoided greenhouse gas emissions measured as the product of the zero emission facilities' output over the contract term multiplied by the U.S. Environmental Protection Agency eGrid subregion carbon dioxide emission rate and the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each delivery year; and

(bb) the costs of replacement with other zero carbon dioxide resources, including wind and photovoltaic, based upon the simple average of the following:

(I) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale wind projects in the procurement events specified in item (i) of subparagraph (G) of paragraph (1) of subsection (c) of this Section; and

(II) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects in the procurement events specified in item (ii) of subparagraph (G) of paragraph (1) of subsection (c) of this Section and, after January 1, 2015, renewable energy credits from photovoltaic distributed generation projects in procurement events held under subsection (c) of this Section.

Each utility shall enter into binding contractual arrangements with the winning suppliers.

The procurement described in this subsection (d-5), including, but not limited to, the execution of all contracts procured, shall be completed no later than May 10, 2017. Based on the effective date of Public Act 99-906, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (C) and (D) of this paragraph (1). The procurement and plan approval processes required by this subsection (d-5) shall be conducted in conjunction with the procurement and plan approval processes required by subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. Notwithstanding whether a procurement event is conducted under Section 16-111.5 of the Public Utilities Act, the Agency shall immediately initiate a procurement process on June 1, 2017 (the effective date of Public Act 99-906).

(D) Following the procurement event described in this paragraph (1) and consistent with subparagraph (B) of this paragraph (1), the Agency shall calculate the payments to be made under each contract for the next delivery year based on the market price index for that delivery year. The Agency shall publish the payment calculations no later than May 25, 2017 and every May 25 thereafter.

(E) Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the zero emission facility may, as applicable, suspend or terminate performance under the contracts in the following instances:

(i) A zero emission facility shall be excused from its performance under the contract for any cause beyond the control of the resource, including, but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of the foregoing cases, by exercise of commercially reasonable efforts the zero emission facility could not reasonably have been expected to avoid, and which, by the exercise of commercially reasonable efforts, it has been unable to overcome. In such event, the zero emission facility shall be excused from performance for the duration of the event, including, but not limited to, delivery of zero emission credits, and no payment shall be due to the zero emission facility during the duration of the event.

(ii) A zero emission facility shall be permitted to terminate the contract if legislation is enacted into law by the General Assembly that imposes or authorizes a new tax, special assessment, or fee on the generation of electricity, the ownership or leasehold of a generating unit, or the privilege or occupation of such generation, ownership, or leasehold of generation units by a zero emission facility. However, the provisions of this item (ii) do not apply to any generally applicable tax, special assessment or fee, or requirements imposed by federal law.

(iii) A zero emission facility shall be permitted to terminate the contract in the event that the resource requires capital expenditures in excess of $40,000,000 that were neither known nor reasonably foreseeable at the time it executed the contract and that a prudent owner or operator of such resource would not undertake.

(iv) A zero emission facility shall be permitted to terminate the contract in the event the Nuclear Regulatory Commission terminates the resource's license.

(F) If the zero emission facility elects to terminate a contract under subparagraph (E) of this paragraph (1), then the Commission shall reopen the docket in which the Commission approved the zero emission standard procurement plan under subparagraph (C) of this paragraph (1) and, after notice and hearing, enter an order acknowledging the contract termination election if such termination is consistent with the provisions of this subsection (d-5).

(2) For purposes of this subsection (d-5), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d-5), the total amount paid for electric service includes, without limitation, amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the total of zero emission credits procured under a procurement plan shall be subject to the limitations of this paragraph (2). For each delivery year, the contractual volume receiving payments in such year shall be reduced for all retail customers based on the amount necessary to limit the net increase that delivery year to the costs of those credits included in the amounts paid by eligible retail customers in connection with electric service to no more than 1.65% of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009. The result of this computation shall apply to and reduce the procurement for all retail customers, and all those customers shall pay the same single, uniform cents per kilowatthour charge under subsection (k) of Section 16-108 of the Public Utilities Act. To arrive at a maximum dollar amount of zero emission credits to be paid for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the delivery year immediately prior to the procurement, to all retail customers in its service territory. Unpaid contractual volume for any delivery year shall be paid in any subsequent delivery year in which such payments can be made without exceeding the amount specified in this paragraph (2). The calculations required by this paragraph (2) shall be made only once for each procurement plan year. Once the determination as to the amount of zero emission credits to be paid is made based on the calculations set forth in this paragraph (2), no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. All costs incurred under those contracts and in implementing this subsection (d-5) shall be recovered by the electric utility as provided in this Section.

No later than June 30, 2019, the Commission shall review the limitation on the amount of zero emission credits procured under this subsection (d-5) and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of cost-effective zero emission credits.

(3) Six years after the execution of a contract under this subsection (d-5), the Agency shall determine whether the actual zero emission credit payments received by the supplier over the 6-year period exceed the Average ZEC Payment. In addition, at the end of the term of a contract executed under this subsection (d-5), or at the time, if any, a zero emission facility's contract is terminated under subparagraph (E) of paragraph (1) of this subsection (d-5), then the Agency shall determine whether the actual zero emission credit payments received by the supplier over the term of the contract exceed the Average ZEC Payment, after taking into account any amounts previously credited back to the utility under this paragraph (3). If the Agency determines that the actual zero emission credit payments received by the supplier over the relevant period exceed the Average ZEC Payment, then the supplier shall credit the difference back to the utility. The amount of the credit shall be remitted to the applicable electric utility no later than 120 days after the Agency's determination, which the utility shall reflect as a credit on its retail customer bills as soon as practicable; however, the credit remitted to the utility shall not exceed the total amount of payments received by the facility under its contract.

For purposes of this Section, the Average ZEC Payment shall be calculated by multiplying the quantity of zero emission credits delivered under the contract times the average contract price. The average contract price shall be determined by subtracting the amount calculated under subparagraph (B) of this paragraph (3) from the amount calculated under subparagraph (A) of this paragraph (3), as follows:

(A) The average of the Social Cost of Carbon, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract.

(B) The average of the market price indices, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract, minus the baseline market price index, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5).

If the subtraction yields a negative number, then the Average ZEC Payment shall be zero.

(4) Cost-effective zero emission credits procured from zero emission facilities shall satisfy the applicable definitions set forth in Section 1-10 of this Act.

(5) The electric utility shall retire all zero emission credits used to comply with the requirements of this subsection (d-5).

(6) Electric utilities shall be entitled to recover all of the costs associated with the procurement of zero emission credits through an automatic adjustment clause tariff in accordance with subsection (k) and (m) of Section 16-108 of the Public Utilities Act, and the contracts executed under this subsection (d-5) shall provide that the utilities' payment obligations under such contracts shall be reduced if an adjustment is required under subsection (m) of Section 16-108 of the Public Utilities Act.

(7) This subsection (d-5) shall become inoperative on January 1, 2028.

(d-10) Nuclear Plant Assistance; carbon mitigation credits.

(1) The General Assembly finds:

(A) The health, welfare, and prosperity of all Illinois citizens require that the State of Illinois act to avoid and not increase carbon emissions from electric generation sources while continuing to ensure affordable, stable, and reliable electricity to all citizens.

(B) Absent immediate action by the State to preserve existing carbon-free energy resources, those resources may retire, and the electric generation needs of Illinois' retail customers may be met instead by facilities that emit significant amounts of carbon pollution and other harmful air pollutants at a high social and economic cost until Illinois is able to develop other forms of clean energy.

(C) The General Assembly finds that nuclear power generation is necessary for the State's transition to 100% clean energy, and ensuring continued operation of nuclear plants advances environmental and public health interests through providing carbon-free electricity while reducing the air pollution profile of the Illinois energy generation fleet.

(D) The clean energy attributes of nuclear generation facilities support the State in its efforts to achieve 100% clean energy.

(E) The State currently invests in various forms of clean energy, including, but not limited to, renewable energy, energy efficiency, and low-emission vehicles, among others.

(F) The Environmental Protection Agency commissioned an independent audit which provided a detailed assessment of the financial condition of the Illinois nuclear fleet to evaluate its financial viability and whether the environmental benefits of such resources were at risk. The report identified the risk of losing the environmental benefits of several specific nuclear units. The report also identified that the LaSalle County Generating Station will continue to operate through 2026 and therefore is not eligible to participate in the carbon mitigation credit program.

(G) Nuclear plants provide carbon-free energy, which helps to avoid many health-related negative impacts for Illinois residents.

(H) The procurement of carbon mitigation credits representing the environmental benefits of carbon-free generation will further the State's efforts at achieving 100% clean energy and decarbonizing the electricity sector in a safe, reliable, and affordable manner. Further, the procurement of carbon emission credits will enhance the health and welfare of Illinois residents through decreased reliance on more highly polluting generation.

(I) The General Assembly therefore finds it necessary to establish carbon mitigation credits to ensure decreased reliance on more carbon-intensive energy resources, for transitioning to a fully decarbonized electricity sector, and to help ensure health and welfare of the State's residents.

(2) As used in this subsection:

"Baseline costs" means costs used to establish a customer protection cap that have been evaluated through an independent audit of a carbon-free energy resource conducted by the Environmental Protection Agency that evaluated projected annual costs for operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this definition, that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource.

"Carbon mitigation credit" means a tradable credit that represents the carbon emission reduction attributes of one megawatt-hour of energy produced from a carbon-free energy resource.

"Carbon-free energy resource" means a generation facility that: (1) is fueled by nuclear power; and (2) is interconnected to PJM Interconnection, LLC.

(3) Procurement.

(A) Beginning with the delivery year commencing on June 1, 2022, the Agency shall, for electric utilities serving at least 3,000,000 retail customers in the State, seek to procure contracts for no more than approximately 54,500,000 cost-effective carbon mitigation credits from carbon-free energy resources because such credits are necessary to support current levels of carbon-free energy generation and ensure the State meets its carbon dioxide emissions reduction goals. The Agency shall not make a partial award of a contract for carbon mitigation credits covering a fractional amount of a carbon-free energy resource's projected output.

(B) Each carbon-free energy resource that intends to participate in a procurement shall be required to submit to the Agency the following information for the resource on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the carbon-free energy resource;

(ii) the amount of power generated annually for each of the past 10 years, which shall be used to determine the capability of each facility;

(iii) a commitment to be reflected in any contract entered into pursuant to this subsection (d-10) to continue operating the carbon-free energy resource at a capacity factor of at least 88% annually on average for the duration of the contract or contracts executed under the procurement held under this subsection (d-10), except in an instance described in subparagraph (E) of paragraph (1) of subsection (d-5) of this Section or made impracticable as a result of compliance with law or regulation;

(iv) financial need and the risk of loss of the environmental benefits of such resource, which shall include the following information:

(I) the carbon-free energy resource's cost projections, expressed on a per megawatt-hour basis, over the next 5 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this subitem (I), that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource; and

(II) the carbon-free energy resource's revenue projections, including energy, capacity, ancillary services, any other direct State support, known or anticipated federal attribute credits, known or anticipated tax credits, and any other direct federal support.

The information described in this subparagraph (B) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of the Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(C) The Agency shall solicit bids for the contracts described in this subsection (d-10) from carbon-free energy resources that have satisfied the requirements of subparagraph (B) of this paragraph (3). The contracts procured pursuant to a procurement event shall reflect, and be subject to, the following terms, requirements, and limitations:

(i) Contracts are for delivery of carbon mitigation credits, and are not energy or capacity sales contracts requiring physical delivery. Pursuant to item (iii), contract payments shall fully deduct the value of any monetized federal production tax credits, credits issued pursuant to a federal clean energy standard, and other federal credits if applicable.

(ii) Contracts for carbon mitigation credits shall commence with the delivery year beginning on June 1, 2022 and shall be for a term of 5 delivery years concluding on May 31, 2027.

(iii) The price per carbon mitigation credit to be paid under a contract for a given delivery year shall be equal to an accepted bid price less the sum of:

(I) one of the following energy price indices, selected by the bidder at the time of the bid for the term of the contract:

(aa) the weighted-average hourly day-ahead price for the applicable delivery year at the busbar of all resources procured pursuant to this subsection (d-10), weighted by actual production from the resources; or

(bb) the projected energy price for the PJM Interconnection, LLC Northern Illinois Hub for the applicable delivery year determined according to subitem (aa) of item (iii) of subparagraph (B) of paragraph (1) of subsection (d-5).

(II) the Base Residual Auction Capacity Price for the ComEd zone as determined by PJM Interconnection, LLC, divided by 24 hours per day, for the applicable delivery year for the first 3 delivery years, and then any subsequent delivery years unless the PJM Interconnection, LLC applies the Minimum Offer Price Rule to participating carbon-free energy resources because they supply carbon mitigation credits pursuant to this Section at which time, upon notice by the carbon-free energy resource to the Commission and subject to the Commission's confirmation, the value under this subitem shall be zero, as further described in the carbon mitigation credit procurement plan; and

(III) any value of monetized federal tax credits, direct payments, or similar subsidy provided to the carbon-free energy resource from any unit of government that is not already reflected in energy prices.

If the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net positive value, then the electric utility counterparty to the contract shall multiply such net value by the applicable contract quantity and remit the amount to the supplier.

To protect retail customers from retail rate impacts that may arise upon the initiation of carbon policy changes, if the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net negative value, then the supplier counterparty to the contract shall multiply such net value by the applicable contract quantity and remit such amount to the electric utility counterparty. The electric utility shall reflect such amounts remitted by suppliers as a credit on its retail customer bills as soon as practicable.

(iv) To ensure that retail customers in Northern Illinois do not pay more for carbon mitigation credits than the value such credits provide, and notwithstanding the provisions of this subsection (d-10), the Agency shall not accept bids for contracts that exceed a customer protection cap equal to the baseline costs of carbon-free energy resources.

The baseline costs for the applicable year shall be the following:

(I) For the delivery year beginning June 1, 2022, the baseline costs shall be an amount equal to $30.30 per megawatt-hour.

(II) For the delivery year beginning June 1, 2023, the baseline costs shall be an amount equal to $32.50 per megawatt-hour.

(III) For the delivery year beginning June 1, 2024, the baseline costs shall be an amount equal to $33.43 per megawatt-hour.

(IV) For the delivery year beginning June 1, 2025, the baseline costs shall be an amount equal to $33.50 per megawatt-hour.

(V) For the delivery year beginning June 1, 2026, the baseline costs shall be an amount equal to $34.50 per megawatt-hour.

An Environmental Protection Agency consultant forecast, included in a report issued April 14, 2021, projects that a carbon-free energy resource has the opportunity to earn on average approximately $30.28 per megawatt-hour, for the sale of energy and capacity during the time period between 2022 and 2027. Therefore, the sale of carbon mitigation credits provides the opportunity to receive an additional amount per megawatt-hour in addition to the projected prices for energy and capacity.

Although actual energy and capacity prices may vary from year-to-year, the General Assembly finds that this customer protection cap will help ensure that the cost of carbon mitigation credits will be less than its value, based upon the social cost of carbon identified in the Technical Support Document issued in February 2021 by the U.S. Interagency Working Group on Social Cost of Greenhouse Gases and the PJM Interconnection, LLC carbon dioxide marginal emission rate for 2020, and that a carbon-free energy resource receiving payment for carbon mitigation credits receives no more than necessary to keep those units in operation.

(D) No later than 7 days after the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall publish its proposed carbon mitigation credit procurement plan. The Plan shall provide that winning bids shall be selected by taking into consideration which resources best match public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. The selection of winning bids shall also take into account the incremental environmental benefits resulting from the procurement or procurements, such as any existing environmental benefits that are preserved by a procurement held under this subsection (d-10) and would cease to exist if the procurement were not held, including the preservation of carbon-free energy resources. For those bidders having the same public interest criteria score, the relative ranking of such bidders shall be determined by price. The Plan shall describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement. The Plan shall, to the extent practical and permissible by federal law, ensure that successful bidders make commercially reasonable efforts to apply for federal tax credits, direct payments, or similar subsidy programs that support carbon-free generation and for which the successful bidder is eligible. Upon publishing of the carbon mitigation credit procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 7 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 19 days later than the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall revise the plan as necessary based on the comments received and file its carbon mitigation credit procurement plan with the Commission.

(E) If the Commission determines that the plan is likely to result in the procurement of cost-effective carbon mitigation credits, then the Commission shall, after notice and hearing and opportunity for comment, but no later than 42 days after the Agency filed the plan, approve the plan or approve it with modification. For purposes of this subsection (d-10), "cost-effective" means carbon mitigation credits that are procured from carbon-free energy resources at prices that are within the limits specified in this paragraph (3). As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the selected carbon-free energy resources satisfy the public interest criteria described in this paragraph (3) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of carbon-free energy resources takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under this amendatory Act of the 102nd General Assembly and would have ceased to exist if the procurements had not been held, such as the preservation of carbon-free energy resources;

(iii) quantify the environmental benefit of preserving the carbon-free energy resources procured pursuant to this subsection (d-10), including the following:

(I) an assessment value of avoided greenhouse gas emissions measured as the product of the carbon-free energy resources' output over the contract term, using generally accepted methodologies for the valuation of avoided emissions; and

(II) an assessment of costs of replacement with other carbon-free energy resources and renewable energy resources, including wind and photovoltaic generation, based upon an assessment of the prices paid for renewable energy credits through programs and procurements conducted pursuant to subsection (c) of Section 1-75 of this Act, and the additional storage necessary to produce the same or similar capability of matching customer usage patterns.

(F) The procurements described in this paragraph (3), including, but not limited to, the execution of all contracts procured, shall be completed no later than December 3, 2021. The procurement and plan approval processes required by this paragraph (3) shall be conducted in conjunction with the procurement and plan approval processes required by Section 16-111.5 of the Public Utilities Act, to the extent practicable. However, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (D) and (E) of this paragraph (3) to meet the December 3, 2021 contract execution deadline. Following the completion of such procurements, and consistent with this paragraph (3), the Agency shall calculate the payments to be made under each contract in a timely fashion.

(F-1) Costs incurred by the electric utility pursuant to a contract authorized by this subsection (d-10) shall be deemed prudently incurred and reasonable in amount, and the electric utility shall be entitled to full cost recovery pursuant to a tariff or tariffs filed with the Commission.

(G) The counterparty electric utility shall retire all carbon mitigation credits used to comply with the requirements of this subsection (d-10).

(H) If a carbon-free energy resource is sold to another owner, the rights, obligations, and commitments under this subsection (d-10) shall continue to the subsequent owner.

(I) This subsection (d-10) shall become inoperative on January 1, 2028.

(e) The draft procurement plans are subject to public comment, as required by Section 16-111.5 of the Public Utilities Act.

(f) The Agency shall submit the final procurement plan to the Commission. The Agency shall revise a procurement plan if the Commission determines that it does not meet the standards set forth in Section 16-111.5 of the Public Utilities Act.

(g) The Agency shall assess fees to each affected utility to recover the costs incurred in preparation of the annual procurement plan for the utility.

(h) The Agency shall assess fees to each bidder to recover the costs incurred in connection with a competitive procurement process.

(i) A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit can only be used once to comply with a single portfolio or other standard as set forth in subsection (c), subsection (d), or subsection (d-5) of this Section, respectively. A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit cannot be used to satisfy the requirements of more than one standard. If more than one type of credit is issued for the same megawatt hour of energy, only one credit can be used to satisfy the requirements of a single standard. After such use, the credit must be retired together with any other credits issued for the same megawatt hour of energy.

(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24; 103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)

(Text of Section after amendment by P.A. 104-458)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(E) expertise in credit and contract protocols;

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

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

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

(A) failure to satisfy qualification criteria;

(B) identification of a conflict of interest; or

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

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

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

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

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

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

(c) Renewable portfolio standard.

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

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

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

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

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

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

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

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

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

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

(iii) For purposes of this Section:

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

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

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

"Geothermal heating and cooling system" means a system located in this State that meets all of the following requirements:

(I) the system exchanges thermal energy from groundwater or a shallow ground source to generate thermal energy through an electric geothermal heat pump or a system of electric geothermal heat pumps interconnected with any geothermal extraction facility that is (1) a closed loop or a series of closed loop systems in which fluid is permanently confined within a pipe or tubing and does not come in contact with the outside environment or (2) an open loop system in which ground or surface water is circulated in an environmentally safe manner directly into the facility and returned to the same aquifer or surface water source;

(II) to the extent applicable and practicable, the system meets or exceeds federal Energy Star product specification standards for Geothermal Heat Pumps established on January 1, 2012, as clarified by the Environmental Protection Agency guidance document released on February 28, 2012 entitled "Clarification to the Geothermal Heat Pump Verification Testing Requirements and Basic Model Group Definition", or any successor standards that meet or exceed these standards;

(III) the system replaces or displaces less efficient space or water heating systems, regardless of fuel type;

(IV) the system replaces or displaces less efficient space cooling systems, when applicable;

(V) the system does not feed electricity back to the grid, as defined at the level of the geothermal heat pump; and

(VI) the system became operational on or after the effective date of this amendatory Act of the 104th General Assembly.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

For purposes of this item (ii):

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

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

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

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

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

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

(3) projects shall not be colocated with one or more other photovoltaic community renewable generation projects such that the aggregate nameplate capacity exceeds 10,000 kilowatts. The total nameplate capacity of colocated projects shall be the sum of the nameplate capacities of the individual projects. For purposes of this subitem (3), separate legal formation of approved vendors, owners, or developers shall not preclude a finding of affiliation by the Agency. Evidence of affiliation may include, but is not limited to, shared personnel, common contractual or financing arrangements, a shared interconnection agreement, distinct interconnection agreements obtained by the same pre-development entity that are subsequently sold to distinct legal entities, familial relationships, or any demonstrable pattern of coordinated action in the pre-development, development, construction, or management of photovoltaic community renewable generation projects.

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

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

For purposes of determining colocation, an approved vendor who submits an application for a photovoltaic community renewable generation project shall be required to submit an affidavit attesting that (i) the parcel on which the project is sited has not been subdivided within the 5 years preceding the project application and (ii) the project is not affiliated with any other photovoltaic community renewable generation energy project in a manner that would cause the 2 projects, if deemed colocated, to exceed the 10,000 kilowatt nameplate capacity limitation. The receipt of an affidavit shall not restrict the Agency's ability to investigate and determine whether the project is colocated.

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

For purposes of this subitem (3):

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

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

"Control" means the possession, directly or indirectly, of the power to direct the management and policies of an entity; and

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

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

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

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

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

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

(1) community ownership or community wealth-building;

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

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

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

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

Selection criteria may also prioritize projects that:

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

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

(3) are located in Equity Investment Eligible Communities;

(4) are not greenfield projects;

(5) serve only local subscribers;

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

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

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

For the purposes of this item (v):

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

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

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

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

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

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

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

For projects developed under this item (vi), the Agency shall take steps to encourage higher portions of contract value to be provided to equity eligible contractors and to support equity eligible persons who participate in this Program and who exercise control and actively manage their businesses and their businesses' contractual projects. These steps may include, but are not limited to, differentiated REC prices, exceptions or exemptions, and other mechanisms and requirements for nonnominal contract value to be provided to equity eligible contractors and equity eligible persons as a prerequisite to Program participation. Any steps taken shall aim to encourage and grow the meaningful participation of equity eligible contractors in this State's clean energy economy. All entities participating under this item (vi) shall comply with the minimum equity standard set forth under Section 1-75.

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

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

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

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

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

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

(i) (Blank).

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(viii) The Agency may, at its discretion, establish a registration process for entities, or a subset of entities, that provide financing for consumers for the purchase of distributed renewable generation devices. The Agency may establish baseline qualifications for financing entity approval, including defining the circumstances under which financing entities may be subject to registration. The Agency may also establish program requirements for entities that provide financing for the purchase of distributed renewable generation devices, which may include marketing and disclosure requirements, other requirements as further defined by the Agency through its long-term plan, and any consumer protection requirements developed or modified thereto. If the Agency establishes a registration process for financing entities, the Agency may revoke a financing entity's approval in a program upon a determination that the financing entity failed to comply with contract terms, the law, or other program requirements. The Agency may also establish program requirements that prohibit distributed renewable generation devices intending to apply for program-administered incentive funding from receiving program funding if the consumer's purchase of the device was financed by an entity whose approval status in the program has been revoked. These registration requirements may apply to entities that finance projects intended to apply for program-administered incentive funding even if those entities do not receive any portion of the program-administered incentive funding.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(i) all new utility-scale wind projects;

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

(iii) all new brownfield photovoltaic projects;

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

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

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

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

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

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

(x) all new geothermal heating and cooling systems awarded through the Geothermal Homes and Businesses Program under subparagraph (S) of this paragraph (1) that do not serve (1) single-family residential buildings, (2) multi-family residential buildings with aggregate geothermal system tonnage, including colocated projects, of no more than 29 tons, or (3) houses of worship with aggregate geothermal system tonnage, including colocated projects, of no more than 29 tons.

(2) Renewable energy credits procured from new utility-scale wind projects, new utility-scale solar projects, new brownfield solar projects, repowered wind projects, and retooled hydropower facilities pursuant to Agency procurement events occurring after the effective date of this amendatory Act of the 102nd General Assembly and community-driven community solar projects or photovoltaic community renewable generation projects where the aggregate capacity, including colocated projects, exceeds 3,000 kilowatts pursuant to a renewable energy credit delivery contract approved by the Illinois Commerce Commission under the Adjustable Block Program after the effective date of this amendatory Act of the 104th General Assembly must be from facilities built by general contractors that must enter into a project labor agreement, as defined by this Act, prior to construction. Community-driven community solar projects and photovoltaic Photovoltaic community renewable generation projects on a program waitlist as of the effective date of this amendatory Act of the 104th General Assembly awarded capacity for the program year commencing June 1, 2026 or any program year thereafter shall not be exempt from the project labor agreement requirements of this item (2). The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency in this item (2) shall be considered commercially sensitive information. At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The agreement must also specify the terms and conditions as defined by this Act.

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

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

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

(1) For the purposes of this subparagraph:

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

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

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

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

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

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

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

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

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

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

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

(4) The Commission shall approve a reduction in the volumetric charges collected pursuant to Section 16-108 of the Public Utilities Act for approved eligible self-direct customers equivalent to the anticipated cost of renewable energy credit deliveries under contracts for new utility-scale wind and new utility-scale solar entered for each delivery year after the large energy customer begins retiring eligible new utility-scale renewable energy credits for self-compliance. The self-direct credit amount shall be determined annually and is equal to the estimated portion of the cost authorized by subparagraph (E) of paragraph (1) of this subsection (c) that supported the annual procurement of utility-scale renewable energy credits in the prior delivery year using a methodology described in the long-term renewable resources procurement plan, expressed on a per kilowatthour basis, and does not include (i) costs associated with any contracts entered into before the delivery year in which the customer files the initial compliance report to be eligible for participation in the self-direct program, and (ii) costs associated with procuring renewable energy credits through existing and future contracts through the Adjustable Block Program, subsection (c-5) of this Section 1-75, and the Solar for All Program. The Agency shall assist the Commission in determining the current and future costs. The Agency must determine the self-direct credit amount for new and existing eligible self-direct customers and submit this to the Commission in an annual compliance filing. The Commission must approve the self-direct credit amount by June 1, 2023 and June 1 of each delivery year thereafter.

(5) Customers described in this subparagraph (R) shall apply, on a form developed by the Agency, to the Agency to be designated as a self-direct eligible customer. Once the Agency determines that a self-direct customer is eligible for participation in the program, the self-direct customer will remain eligible until the end of the term of the contract. Thereafter, application may be made not less than 12 months before the filing date of the long-term renewable resources procurement plan described in this Act. At a minimum, such application shall contain the following:

(i) the customer's certification that, at the time of the customer's application, the customer qualifies to be a self-direct eligible customer, including documents demonstrating that qualification;

(ii) the customer's certification that the customer has entered into or will enter into by the beginning of the applicable procurement year, one or more bilateral contracts for new wind projects or new photovoltaic projects, including supporting documentation;

(iii) certification that the contract or contracts for new renewable energy resources are long-term contracts with term lengths of at least 10 years, including supporting documentation;

(iv) certification of the quantities of renewable energy credits that the customer will purchase each year under such contract or contracts, including supporting documentation;

(v) proof that the contract is sufficient to produce renewable energy credits to be equivalent in volume to at least 40% of the large energy customer's usage from the previous delivery year, measured to the nearest megawatt-hour; and

(vi) certification that the customer intends to maintain the contract for the duration of the length of the contract.

(6) If a customer receives the self-direct credit but fails to properly procure and retire renewable energy credits as required under this subparagraph (R), the Commission, on petition from the Agency and after notice and hearing, may direct such customer's utility to recover the cost of the wrongfully received self-direct credits plus interest through an adder to charges assessed pursuant to Section 16-108 of the Public Utilities Act. Self-direct customers who knowingly fail to properly procure and retire renewable energy credits and do not notify the Agency are ineligible for continued participation in the self-direct renewable portfolio standard compliance program.

(S) Beginning with the long-term renewable resources procurement plan covering program and procurement activity for the delivery year beginning on June 1, 2028, any long-term renewable resources procurement plan developed by the Agency in accordance with subparagraph (A) of this paragraph (1) shall include a Geothermal Homes and Businesses Program for the procurement of geothermal renewable energy credits from new geothermal heating and cooling systems. The long-term renewable resources procurement plan shall allocate up to $10,000,000 per delivery year to fund the Program as described in this subparagraph (S). The Program shall be designed to stimulate the steady, predictable, and sustainable growth of new geothermal heating and cooling system deployment in this State and meet gaps in the marketplace. To this end, the Geothermal Homes and Businesses Program shall provide a transparent annual schedule of prices and quantities to enable the geothermal heating and cooling market to scale up and renewable energy credit prices to adjust at a predictable rate over time. The prices set by the Geothermal Homes and Businesses Program may be reflected as a set value or as the product of a formula.

(i) The Geothermal Homes and Businesses Program shall allocate blocks of renewable energy credits as follows:

(1) The Agency may create categories for the Program based on structure features and use cases, including categories based on the nature and size of the Program's projects, customers, communities in which a project is located, and other attributes, defined at the discretion of the Agency through its long-term plan.

(2) The Agency shall propose an initial single annual block for each Program delivery year for each category it creates through the delivery year beginning on June 1, 2035. The Program shall include the following for eligible projects for each delivery year: (I) a block of geothermal renewable energy credit volumes; (II) a price for renewable energy credits from geothermal heating and cooling systems within the identified block; and (III) the terms and conditions for securing a spot on a waitlist once the block is fully committed or reserved. The Agency may periodically review its prior decisions establishing the amount of geothermal renewable energy credit volumes in each annual block and the purchase price for each block and may propose, on an expedited basis, changes to the previously set values, including, but not limited to, redistributing the amounts and the available funds as necessary and appropriate, subject to Commission approval. The Agency may define different block sizes, purchase prices, or other distinct terms and conditions for projects located in different utility service territories if the Agency deems it necessary.

(3) The Agency may develop an intra-year and year-to-year waitlist and block reservation policy that balances market certainty, program availability, and expedient project deployment.

(4) For the program year beginning on June 1, 2028, at least 33% of each annual block shall be available to be reserved for systems that are residential, as defined by the Agency. The Agency shall endeavor to ensure at least 40% of each annual block is available to be reserved by systems located in Equity Investment Eligible Communities. At least 10% of all annual blocks shall be available to be reserved by systems from applicants that are equity eligible contractors, and the Agency shall propose to increase the percentage of systems from applicants that are equity eligible contractors over time to 40% based on factors that include, but are not limited to, the number of equity eligible contractors and the volume used under this clause (4) in previous delivery years. For long-term renewable resources procurement plans developed thereafter, the Agency may propose adjustments to the minimum percentages based on developer interest, market interest and availability, and other factors.

(5) The Agency shall establish Program eligibility requirements that ensure that systems that enter the Program are sufficiently mature enough to indicate a demonstrable path to completion and other terms, conditions, and requirements for the program, including vendor registration and approval, sales and marketing requirements, and other consumer protection requirements as the Agency deems necessary.

(6) The Program shall be designed to ensure that geothermal renewable energy credits are procured from projects in diverse locations and are not procured from projects that are concentrated in a few regional areas.

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

(ii) Energy derived from a geothermal heating and cooling system shall be eligible for inclusion in meeting the requirements of the Program. Geothermal renewable energy credits shall be expressed in megawatt-hour units. To make this calculation, the Agency (1) shall identify an appropriate formula supported by a geothermal industry trade organization, a national laboratory, or another data-backed and verifiable methodology, (2) may propose adjustments to any formulas for its proposed renewable energy credit calculation methodology, and (3) may reflect calculation methodologies already in use for other State renewable portfolio standards, if applicable and appropriate. The Agency shall determine the form and manner in which the renewable energy credits are verified and retired, in accordance with national best practices.

Geothermal renewable energy credits retired by obligated utilities for compliance with the Program are only valid for compliance if those geothermal renewable energy credits have not been previously retired by another entity that is not the obligated utility on any tracking system, carbon registry, or other accounting mechanism at any time. Additionally, geothermal renewable energy credits retired by obligated utilities for compliance with the Program shall only be valid for compliance if those geothermal renewable energy credits have not been used to substantiate a public emissions or energy usage claim by any other another entity that is not the obligated utility, of any type and at any time, whether or not the geothermal renewable energy credits were actually retired on a tracking system, registry, or other accounting mechanism at the time of the public emissions-based claim. Geothermal renewable energy credits generated for compliance with the Program shall be valid only if retired once, and claimed once, by the obligated utility.

In order to promote the competitive development of geothermal heating and cooling systems in furtherance of this State's interest in the health, safety, and welfare of its residents, renewable energy credits from geothermal heating and cooling systems shall not be eligible for purchase and retirement under this Act if the credits are sourced from a geothermal heating and cooling system for which costs are being recovered on or after the effective date of this amendatory Act of the 104th General Assembly through rates regulated by this State or any other state.

(iii) The Agency shall establish Program requirements and minimum contract terms to ensure that projects are properly installed and that projects operate to the level of expected benefits. The contract terms shall include, but are not limited to, the following:

(1) The capital that is not advanced shall be disbursed upon a schedule determined by the Agency, based on the total contracted fulfillment over the delivery term, not to exceed, during each delivery year, the contract price multiplied by the estimated annual renewable energy credit generation amount. Payment structures shall include provisions that provide portions of the renewable energy credit delivery contract value upon energization, including no less than 40% of the contract value for residential projects, based on the estimated renewable energy credit production during the contract term.

(2) For renewable energy credits that qualify and are procured under the Program, the delivery contract length shall be 15 years.

(3) For contracts that are paid upon the delivery of renewable energy credits, if generation of renewable energy credits from geothermal heating and cooling systems during a delivery year exceeds the estimated annual generation amount, the excess of such renewable energy credits shall be carried forward to future delivery years and shall not expire during the delivery term. If the renewable energy credit generation during a delivery year, including any carried forward excess renewable energy credits, is less than the estimated annual generation amount, payments during the delivery year shall not exceed the quantity generated plus the quantity carried forward multiplied by the contract price. The electric utility shall receive all renewable energy credits generated by the project during the first 15 years of operation, and retire all renewable energy credits paid for under this clause (3) and return at the end of the delivery term all geothermal renewable energy credits that were not paid for. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(4) For renewable energy contracts for any type of community, shared, or similar geothermal heating and cooling system that operates using a subscription model and for which subscriptions are a basis for contractual payments, subscription of 90% of total renewable energy credit volumes or greater shall be deemed to be fully subscribed.

(5) Beginning with the long-term renewable resources procurement plan covering the delivery year beginning on June 1, 2030, the Agency may propose a payment structure for Program contracts upon a demonstration of qualification or need under criteria established by the Agency that is focused on supporting the small and emerging businesses and the businesses that most acutely face barriers to capital access. Successful applicant firms shall have advanced capital disbursed before renewable energy credits are first generated. The maximum amount or percentage of capital advanced shall be included in the long-term renewable resources procurement plan, and any amount actually advanced shall be designed to overcome the barriers in access to capital that are faced by an applicant through that applicant's demonstration of need. The amount or percentage of advanced capital may vary by year, or inter-year, by structure category, block, and other factors as deemed applicable by the Agency and by an applicant's demonstration of need. Contracts featuring capital advanced prior to system operation shall feature provisions to ensure both the successful development of applicant projects and the delivery of renewable energy credits for the full term of the contract, including ongoing collateral requirements and other provisions deemed necessary by the Agency. The percentage or amount of capital advanced prior to system operation shall not increase the overall contract value.

(6) Each contract shall include provisions to ensure the delivery of the estimated quantity of geothermal renewable energy credits, including a requirement of performance assurance in an amount deemed appropriate by the Agency.

(7) An obligated utility shall be the counterparty to the contracts executed under this subparagraph (S) that are approved by the Commission. No contract shall be executed for an amount that is less than one geothermal renewable energy credit per year.

(8) Nothing in this subparagraph (S) shall require the utility to advance any payment or pay any amounts that exceed the actual amount of revenues anticipated to be collected by the utility inclusive of eligible funds collected in prior years and alternative compliance payments for use by the utility.

(9) Contracts may be assignable, but only to entities first deemed by the Agency to have met Program terms and requirements applicable to direct Program participation. In developing contracts for the delivery of renewable energy credits from geothermal heating and cooling systems, the Agency may establish fees applicable to each contract assignment.

(10) If, at any time, approved applications for the Program exceed funds collected by the electric utility or would cause the Agency to exceed the limitation on the amount of renewable energy resources that may be procured, then the Agency may consider future uncommitted funds to be reserved for these contracts on a first-come, first-served basis.

(iv) In order to advance priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, been subject to disproportionate levels of pollution, and disproportionately experienced negative public health outcomes, the Agency shall apply its equity accountability system and minimum equity standards established under subsections (c-10), (c-15), (c-20), (c-25), and (c-30) to geothermal heating and cooling system renewable energy credit procurement and programs and may include any proposed modifications to the equity accountability system and minimum equity standards that may be warranted with respect to geothermal heating and cooling systems in its plan submission to the Commission under Section 16-111.5 of the Public Utilities Act.

(v) Projects shall be developed in compliance with the prevailing wage and project labor agreement requirements, as applicable, for renewable energy projects in subparagraph (Q) of paragraph (1) of subsection (c). Projects approved under this Program are subject to the prevailing wage requirements outlined in subitem (x) of item (1) of subparagraph (Q) of paragraph (1) of this subsection (c). Renewable energy credits for any single geothermal heating and cooling project that is 142 tons or larger and is procured under this Program after the effective date of this amendatory Act of the 104th General Assembly shall only be eligible if the associated project was built by general contractors who entered into a project labor agreement prior to construction. The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. The project labor agreement shall provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees that participate in the project labor agreement. The project labor agreement shall also specify terms and conditions as provided in this Act.

(vi) The Agency shall strive to minimize administrative expenses in the implementation of the Program. The Agency may use any existing program administrator and any applicable subcontractors to develop, administer, implement, operate, and evaluate the Program.

(T) Renewable energy credits procured under Agency procurements or programs for community solar projects with more than 3 megawatts in nameplate capacity must be procured from facilities built by general contractors that, prior to construction, enter into a project labor agreement, as defined by this Act, subject to the following requirements and limitations:

(i) The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency under this item (i) shall be considered commercially sensitive information.

(ii) At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the project and any individuals representing the labor organization of the employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The project labor agreement must also meet the terms and conditions, as set forth in this Act.

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

(2) (Blank).

(3) (Blank).

(4) The electric utility shall retire all renewable energy credits used to comply with the standard.

(5) Beginning with the 2010 delivery year and ending June 1, 2017, an electric utility subject to this subsection (c) shall apply the lesser of the maximum alternative compliance payment rate or the most recent estimated alternative compliance payment rate for its service territory for the corresponding compliance period, established pursuant to subsection (d) of Section 16-115D of the Public Utilities Act to its retail customers that take service pursuant to the electric utility's hourly pricing tariff or tariffs. The electric utility shall retain all amounts collected as a result of the application of the alternative compliance payment rate or rates to such customers, and, beginning in 2011, the utility shall include in the information provided under item (1) of subsection (d) of Section 16-111.5 of the Public Utilities Act the amounts collected under the alternative compliance payment rate or rates for the prior year ending May 31. Notwithstanding any limitation on the procurement of renewable energy resources imposed by item (2) of this subsection (c), the Agency shall increase its spending on the purchase of renewable energy resources to be procured by the electric utility for the next plan year by an amount equal to the amounts collected by the utility under the alternative compliance payment rate or rates in the prior year ending May 31.

(6) The electric utility shall be entitled to recover all of its costs associated with the procurement of renewable energy credits under plans approved under this Section and Section 16-111.5 of the Public Utilities Act. These costs shall include associated reasonable expenses for implementing the procurement programs, including, but not limited to, the costs of administering and evaluating the Adjustable Block program and the Geothermal Homes and Businesses Program, through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act.

(7) Renewable energy credits procured from new photovoltaic projects or new distributed renewable energy generation devices under this Section after June 1, 2017 (the effective date of Public Act 99-906) must be procured from devices installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

In meeting the renewable energy requirements of this subsection (c), to the extent feasible and consistent with State and federal law, the renewable energy credit procurements, Adjustable Block solar program, and community renewable generation program shall provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(c-5) Procurement of renewable energy credits from new renewable energy facilities installed at or adjacent to the sites of electric generating facilities that burn or burned coal as their primary fuel source.

(1) In addition to the procurement of renewable energy credits pursuant to long-term renewable resources procurement plans in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, the Agency shall conduct procurement events in accordance with this subsection (c-5) for the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new renewable energy facilities to be installed at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source and meet the other criteria specified in this subsection (c-5). For purposes of this subsection (c-5), "new renewable energy facility" means a new utility-scale solar project as defined in this Section 1-75. The renewable energy credits procured pursuant to this subsection (c-5) may be included or counted for purposes of compliance with the amounts of renewable energy credits required to be procured pursuant to subsection (c) of this Section to the extent that there are otherwise shortfalls in compliance with such requirements. The procurement of renewable energy credits by electric utilities pursuant to this subsection (c-5) shall be funded solely by revenues collected from the Coal to Solar and Energy Storage Initiative Charge provided for in this subsection (c-5) and subsection (i-5) of Section 16-108 of the Public Utilities Act, shall not be funded by revenues collected through any of the other funding mechanisms provided for in subsection (c) of this Section, and shall not be subject to the limitation imposed by subsection (c) on charges to retail customers for costs to procure renewable energy resources pursuant to subsection (c), and shall not be subject to any other requirements or limitations of subsection (c).

(2) The Agency shall conduct 2 procurement events to select owners of electric generating facilities meeting the eligibility criteria specified in this subsection (c-5) to enter into long-term contracts to sell renewable energy credits to electric utilities serving more than 300,000 retail customers in this State as of January 1, 2019. The first procurement event shall be conducted no later than March 31, 2022, unless the Agency elects to delay it, until no later than May 1, 2022, due to its overall volume of work, and shall be to select owners of electric generating facilities located in this State and south of federal Interstate Highway 80 that meet the eligibility criteria specified in this subsection (c-5). The second procurement event shall be conducted no sooner than September 30, 2022 and no later than October 31, 2022 and shall be to select owners of electric generating facilities located anywhere in this State that meet the eligibility criteria specified in this subsection (c-5). The Agency shall establish and announce a time period, which shall begin no later than 30 days prior to the scheduled date for the procurement event, during which applicants may submit applications to be selected as suppliers of renewable energy credits pursuant to this subsection (c-5). The eligibility criteria for selection as a supplier of renewable energy credits pursuant to this subsection (c-5) shall be as follows:

(A) The applicant owns an electric generating facility located in this State that: (i) as of January 1, 2016, burned coal as its primary fuel to generate electricity; and (ii) has, or had prior to retirement, an electric generating capacity of at least 150 megawatts. The electric generating facility can be either: (i) retired as of the date of the procurement event; or (ii) still operating as of the date of the procurement event.

(B) The applicant is not (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in (i) or (ii); and the coal-fueled electric generating facility was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act.

(C) If participating in the first procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 20 megawatts but no more than 100 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 2 megawatts and at most 10 megawatts. If participating in the second procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 5 megawatts but no more than 20 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 0.5 megawatts and at most one megawatt.

(D) The applicant agrees that the new renewable energy facility and the energy storage facility will be constructed or installed by a qualified entity or entities in compliance with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted thereunder.

(E) The applicant agrees that personnel operating the new renewable energy facility and the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function.

(F) The applicant commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the applicant's employees engaged in construction activities associated with the new renewable energy facility and the new energy storage facility and to the employees of applicant's contractors engaged in construction activities associated with the new renewable energy facility and the new energy storage facility, and that, on or before the commercial operation date of the new renewable energy facility, the applicant shall file a report with the Agency certifying that the requirements of this subparagraph (F) have been met.

(G) The applicant commits that if selected, it will negotiate a project labor agreement for the construction of the new renewable energy facility and associated energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

(H) The applicant commits to enter into a contract or contracts for the applicable duration to provide specified numbers of renewable energy credits each year from the new renewable energy facility to electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019, at a price of $30 per renewable energy credit. The price per renewable energy credit shall be fixed at $30 for the applicable duration and the renewable energy credits shall not be indexed renewable energy credits as provided for in item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act. The applicable duration of each contract shall be 20 years, unless the applicant is physically interconnected to the PJM Interconnection, LLC transmission grid and had a generating capacity of at least 1,200 megawatts as of January 1, 2021, in which case the applicable duration of the contract shall be 15 years.

(I) The applicant's application is certified by an officer of the applicant and by an officer of the applicant's ultimate parent company, if any.

(3) An applicant may submit applications to contract to supply renewable energy credits from more than one new renewable energy facility to be constructed at or adjacent to one or more qualifying electric generating facilities owned by the applicant. The Agency may select new renewable energy facilities to be located at or adjacent to the sites of more than one qualifying electric generation facility owned by an applicant to contract with electric utilities to supply renewable energy credits from such facilities.

(4) The Agency shall assess fees to each applicant to recover the Agency's costs incurred in receiving and evaluating applications, conducting the procurement event, developing contracts for sale, delivery and purchase of renewable energy credits, and monitoring the administration of such contracts, as provided for in this subsection (c-5), including fees paid to a procurement administrator retained by the Agency for one or more of these purposes.

(5) The Agency shall select the applicants and the new renewable energy facilities to contract with electric utilities to supply renewable energy credits in accordance with this subsection (c-5). In the first procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no less than 400,000 renewable energy credits per year for the applicable duration, assuming sufficient qualifying applications to supply, in the aggregate, at least that amount of renewable energy credits per year; and not more than 580,000 renewable energy credits per year for the applicable duration. In the second procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no more than 625,000 renewable energy credits per year less the amount of renewable energy credits each year contracted for as a result of the first procurement event, for the applicable durations. The number of renewable energy credits to be procured as specified in this paragraph (5) shall not be reduced based on renewable energy credits procured in the self-direct renewable energy credit compliance program established pursuant to subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75.

(6) The obligation to purchase renewable energy credits from the applicants and their new renewable energy facilities selected by the Agency shall be allocated to the electric utilities based on their respective percentages of kilowatthours delivered to delivery services customers to the aggregate kilowatthour deliveries by the electric utilities to delivery services customers for the year ended December 31, 2021. In order to achieve these allocation percentages between or among the electric utilities, the Agency shall require each applicant that is selected in the procurement event to enter into a contract with each electric utility for the sale and purchase of renewable energy credits from each new renewable energy facility to be constructed and operated by the applicant, with the sale and purchase obligations under the contracts to aggregate to the total number of renewable energy credits per year to be supplied by the applicant from the new renewable energy facility.

(7) The Agency shall submit its proposed selection of applicants, new renewable energy facilities to be constructed, and renewable energy credit amounts for each procurement event to the Commission for approval. The Commission shall, within 2 business days after receipt of the Agency's proposed selections, approve the proposed selections if it determines that the applicants and the new renewable energy facilities to be constructed meet the selection criteria set forth in this subsection (c-5) and that the Agency seeks approval for contracts of applicable durations aggregating to no more than the maximum amount of renewable energy credits per year authorized by this subsection (c-5) for the procurement event, at a price of $30 per renewable energy credit.

(8) The Agency, in conjunction with its procurement administrator if one is retained, the electric utilities, and potential applicants for contracts to produce and supply renewable energy credits pursuant to this subsection (c-5), shall develop a standard form contract for the sale, delivery and purchase of renewable energy credits pursuant to this subsection (c-5). Each contract resulting from the first procurement event shall allow for a commercial operation date for the new renewable energy facility of either June 1, 2023 or June 1, 2024, with such dates subject to adjustment as provided in this paragraph. Each contract resulting from the second procurement event shall provide for a commercial operation date on June 1 next occurring up to 48 months after execution of the contract. Each contract shall provide that the owner shall receive payments for renewable energy credits for the applicable durations beginning with the commercial operation date of the new renewable energy facility. The form contract shall provide for adjustments to the commercial operation and payment start dates as needed due to any delays in completing the procurement and contracting processes, in finalizing interconnection agreements and installing interconnection facilities, and in obtaining other necessary governmental permits and approvals. The form contract shall be, to the maximum extent possible, consistent with standard electric industry contracts for sale, delivery, and purchase of renewable energy credits while taking into account the specific requirements of this subsection (c-5). The form contract shall provide for over-delivery and under-delivery of renewable energy credits within reasonable ranges during each 12-month period and penalty, default, and enforcement provisions for failure of the selling party to deliver renewable energy credits as specified in the contract and to comply with the requirements of this subsection (c-5). The standard form contract shall specify that all renewable energy credits delivered to the electric utility pursuant to the contract shall be retired. The Agency shall make the proposed contracts available for a reasonable period for comment by potential applicants, and shall publish the final form contract at least 30 days before the date of the first procurement event.

(9) Coal to Solar and Energy Storage Initiative Charge.

(A) By no later than July 1, 2022, each electric utility that served more than 300,000 retail customers in this State as of January 1, 2019 shall file a tariff with the Commission for the billing and collection of a Coal to Solar and Energy Storage Initiative Charge in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act, with such tariff to be effective, following review and approval or modification by the Commission, beginning January 1, 2023. The tariff shall provide for the calculation and setting of the electric utility's Coal to Solar and Energy Storage Initiative Charge to collect revenues estimated to be sufficient, in the aggregate, (i) to enable the electric utility to pay for the renewable energy credits it has contracted to purchase in the delivery year beginning June 1, 2023 and each delivery year thereafter from new renewable energy facilities located at the sites of qualifying electric generating facilities, and (ii) to fund the grant payments to be made in each delivery year by the Department of Commerce and Economic Opportunity, or any successor department or agency, which shall be referred to in this subsection (c-5) as the Department, pursuant to paragraph (10) of this subsection (c-5). The electric utility's tariff shall provide for the billing and collection of the Coal to Solar and Energy Storage Initiative Charge on each kilowatthour of electricity delivered to its delivery services customers within its service territory and shall provide for an annual reconciliation of revenues collected with actual costs, in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act.

(B) Each electric utility shall remit on a monthly basis to the State Treasurer, for deposit in the Coal to Solar and Energy Storage Initiative Fund provided for in this subsection (c-5), the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge in the amount estimated to be needed by the Department for grant payments pursuant to grant contracts entered into by the Department pursuant to paragraph (10) of this subsection (c-5).

(10) Coal to Solar and Energy Storage Initiative Fund.

(A) The Coal to Solar and Energy Storage Initiative Fund is established as a special fund in the State treasury. The Coal to Solar and Energy Storage Initiative Fund is authorized to receive, by statutory deposit, that portion specified in item (B) of paragraph (9) of this subsection (c-5) of moneys collected by electric utilities through imposition of the Coal to Solar and Energy Storage Initiative Charge required by this subsection (c-5). The Coal to Solar and Energy Storage Initiative Fund shall be administered by the Department to provide grants to support the installation and operation of energy storage facilities at the sites of qualifying electric generating facilities meeting the criteria specified in this paragraph (10).

(B) The Coal to Solar and Energy Storage Initiative Fund shall not be subject to sweeps, administrative charges, or chargebacks, including, but not limited to, those authorized under Section 8h of the State Finance Act, that would in any way result in the transfer of those funds from the Coal to Solar and Energy Storage Initiative Fund to any other fund of this State or in having any such funds utilized for any purpose other than the express purposes set forth in this paragraph (10).

(C) The Department shall utilize up to $280,500,000 in the Coal to Solar and Energy Storage Initiative Fund for grants, assuming sufficient qualifying applicants, to support installation of energy storage facilities at the sites of up to 3 qualifying electric generating facilities located in the Midcontinent Independent System Operator, Inc., region in Illinois and the sites of up to 2 qualifying electric generating facilities located in the PJM Interconnection, LLC region in Illinois that meet the criteria set forth in this subparagraph (C). The criteria for receipt of a grant pursuant to this subparagraph (C) are as follows:

(1) the electric generating facility at the site has, or had prior to retirement, an electric generating capacity of at least 150 megawatts;

(2) the electric generating facility burns (or burned prior to retirement) coal as its primary source of fuel;

(3) if the electric generating facility is retired, it was retired subsequent to January 1, 2016;

(4) the owner of the electric generating facility has not been selected by the Agency pursuant to this subsection (c-5) of this Section to enter into a contract to sell renewable energy credits to one or more electric utilities from a new renewable energy facility located or to be located at or adjacent to the site at which the electric generating facility is located;

(5) the electric generating facility located at the site was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act;

(6) the electric generating facility at the site is not owned by (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in items (i) or (ii);

(7) the proposed energy storage facility at the site will have energy storage capacity of at least 37 megawatts;

(8) the owner commits to place the energy storage facility into commercial operation on either June 1, 2023, June 1, 2024, or June 1, 2025, with such date subject to adjustment as needed due to any delays in completing the grant contracting process, in finalizing interconnection agreements and in installing interconnection facilities, and in obtaining necessary governmental permits and approvals;

(9) the owner agrees that the new energy storage facility will be constructed or installed by a qualified entity or entities consistent with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted under that Section;

(10) the owner agrees that personnel operating the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function;

(11) the owner commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the owner's employees engaged in construction activities associated with the new energy storage facility and to the employees of the owner's contractors engaged in construction activities associated with the new energy storage facility, and that, on or before the commercial operation date of the new energy storage facility, the owner shall file a report with the Department certifying that the requirements of this subparagraph (11) have been met; and

(12) the owner commits that if selected to receive a grant, it will negotiate a project labor agreement for the construction of the new energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

The Department shall accept applications for this grant program until March 31, 2022 and shall announce the award of grants no later than June 1, 2022. The Department shall make the grant payments to a recipient in equal annual amounts for 10 years following the date the energy storage facility is placed into commercial operation. The annual grant payments to a qualifying energy storage facility shall be $110,000 per megawatt of energy storage capacity, with total annual grant payments pursuant to this subparagraph (C) for qualifying energy storage facilities not to exceed $28,050,000 in any year.

(D) Grants of funding for energy storage facilities pursuant to subparagraph (C) of this paragraph (10), from the Coal to Solar and Energy Storage Initiative Fund, shall be memorialized in grant contracts between the Department and the recipient. The grant contracts shall specify the date or dates in each year on which the annual grant payments shall be paid.

(E) All disbursements from the Coal to Solar and Energy Storage Initiative Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Director of the Department or by the person or persons designated by the Director of the Department for that purpose. The Comptroller is authorized to draw the warrants upon vouchers so signed. The Treasurer shall accept all written warrants so signed and shall be released from liability for all payments made on those warrants.

(11) Diversity, equity, and inclusion plans.

(A) Each applicant selected in a procurement event to contract to supply renewable energy credits in accordance with this subsection (c-5) and each owner selected by the Department to receive a grant or grants to support the construction and operation of a new energy storage facility or facilities in accordance with this subsection (c-5) shall, within 60 days following the Commission's approval of the applicant to contract to supply renewable energy credits or within 60 days following execution of a grant contract with the Department, as applicable, submit to the Commission a diversity, equity, and inclusion plan setting forth the applicant's or owner's numeric goals for the diversity composition of its supplier entities for the new renewable energy facility or new energy storage facility, as applicable, which shall be referred to for purposes of this paragraph (11) as the project, and the applicant's or owner's action plan and schedule for achieving those goals.

(B) For purposes of this paragraph (11), diversity composition shall be based on the percentage, which shall be a minimum of 25%, of eligible expenditures for contract awards for materials and services (which shall be defined in the plan) to business enterprises owned by minority persons, women, or persons with disabilities as defined in Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act, to LGBTQ business enterprises, to veteran-owned business enterprises, and to business enterprises located in environmental justice communities. The diversity composition goals of the plan may include eligible expenditures in areas for vendor or supplier opportunities in addition to development and construction of the project, and may exclude from eligible expenditures materials and services with limited market availability, limited production and availability from suppliers in the United States, such as solar panels and storage batteries, and material and services that are subject to critical energy infrastructure or cybersecurity requirements or restrictions. The plan may provide that the diversity composition goals may be met through Tier 1 Direct or Tier 2 subcontracting expenditures or a combination thereof for the project.

(C) The plan shall provide for, but not be limited to: (i) internal initiatives, including multi-tier initiatives, by the applicant or owner, or by its engineering, procurement and construction contractor if one is used for the project, which for purposes of this paragraph (11) shall be referred to as the EPC contractor, to enable diverse businesses to be considered fairly for selection to provide materials and services; (ii) requirements for the applicant or owner or its EPC contractor to proactively solicit and utilize diverse businesses to provide materials and services; and (iii) requirements for the applicant or owner or its EPC contractor to hire a diverse workforce for the project. The plan shall include a description of the applicant's or owner's diversity recruiting efforts both for the project and for other areas of the applicant's or owner's business operations. The plan shall provide for the imposition of financial penalties on the applicant's or owner's EPC contractor for failure to exercise best efforts to comply with and execute the EPC contractor's diversity obligations under the plan. The plan may provide for the applicant or owner to set aside a portion of the work on the project to serve as an incubation program for qualified businesses, as specified in the plan, owned by minority persons, women, persons with disabilities, LGBTQ persons, and veterans, and businesses located in environmental justice communities, seeking to enter the renewable energy industry.

(D) The applicant or owner may submit a revised or updated plan to the Commission from time to time as circumstances warrant. The applicant or owner shall file annual reports with the Commission detailing the applicant's or owner's progress in implementing its plan and achieving its goals and any modifications the applicant or owner has made to its plan to better achieve its diversity, equity and inclusion goals. The applicant or owner shall file a final report on the fifth June 1 following the commercial operation date of the new renewable energy resource or new energy storage facility, but the applicant or owner shall thereafter continue to be subject to applicable reporting requirements of Section 5-117 of the Public Utilities Act.

(c-10) Equity accountability system. It is the purpose of this subsection (c-10) to create an equity accountability system, which includes the minimum equity standards for all renewable energy procurements, the equity category of the Adjustable Block Program, and the equity prioritization for noncompetitive procurements, that is successful in advancing priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes. Further, it is the purpose of this subsection to ensure that this equity accountability system is successful in advancing equity across Illinois by providing access to the clean energy economy for businesses and workers from communities that have been historically excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes.

(1) Minimum equity standards. The Agency shall create programs with the purpose of increasing access to and development of equity eligible contractors, who are prime contractors and subcontractors, across all of the programs it manages. All applications for renewable energy credit procurements shall comply with specific minimum equity commitments. Starting in the delivery year immediately following the next long-term renewable resources procurement plan, at least 10% of the project workforce for each entity participating in a procurement program outlined in this subsection (c-10) must be done by equity eligible persons or equity eligible contractors. The Agency shall increase the minimum percentage each delivery year thereafter by increments that ensure a statewide average of 30% of the project workforce for each entity participating in a procurement program is done by equity eligible persons or equity eligible contractors by 2030. The Agency shall propose a schedule of percentage increases to the minimum equity standards in its draft revised renewable energy resources procurement plan submitted to the Commission for approval pursuant to paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. In determining these annual increases, the Agency shall have the discretion to establish different minimum equity standards for different types of procurements and different regions of the State if the Agency finds that doing so will further the purposes of this subsection (c-10). The proposed schedule of annual increases shall be revisited and updated on an annual basis. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, clean energy industry representatives, and community-based organizations that work with such persons and contractors.

(A) At the start of each delivery year, the Agency shall require a compliance plan from each entity participating in a procurement program of subsection (c) of this Section, and entities opting to comply with the minimum equity standard through the Illinois Solar for All Program under Section 1-56 of this Act, that demonstrates how they will achieve compliance with the minimum equity standard percentage for work completed in that delivery year. If an entity applies for its approved vendor or designee status between delivery years, the Agency shall require a compliance plan at the time of application.

(B) Halfway through each delivery year, the Agency shall require each entity participating in a procurement program to confirm that it will achieve compliance in that delivery year, when applicable. The Agency may offer corrective action plans to entities that are not on track to achieve compliance.

(C) At the end of each delivery year, each entity participating and completing work in that delivery year in a procurement program of subsection (c) shall submit a report to the Agency that demonstrates how it achieved compliance with the minimum equity standards percentage for that delivery year.

(D) The Agency shall prohibit participation in procurement programs by an approved vendor or designee, as applicable, or entities with which an approved vendor or designee, as applicable, shares a common parent company if an approved vendor or designee, as applicable, failed to meet the minimum equity standards for the prior delivery year. Waivers approved for lack of equity eligible persons or equity eligible contractors in a geographic area of a project shall not count against the approved vendor or designee. The Agency shall offer a corrective action plan for any such entities to assist them in obtaining compliance and shall allow continued access to procurement programs upon an approved vendor or designee demonstrating compliance.

(E) The Agency shall pursue efficiencies achieved by combining with other approved vendor or designee reporting.

(2) Equity accountability system within the Adjustable Block program. The equity category described in item (vi) of subparagraph (K) of subsection (c) is only available to applicants that are equity eligible contractors.

(3) Equity accountability system within competitive procurements. Through its long-term renewable resources procurement plan, the Agency shall develop requirements for ensuring that competitive procurement processes, including utility-scale solar, utility-scale wind, and brownfield site photovoltaic projects, advance the equity goals of this subsection (c-10). Subject to Commission approval, the Agency shall develop bid application requirements and a bid evaluation methodology for ensuring that utilization of equity eligible contractors, whether as bidders or as participants on project development, is optimized, including requiring that winning or successful applicants for utility-scale projects are or will partner with equity eligible contractors and giving preference to bids through which a higher portion of contract value flows to equity eligible contractors. To the extent practicable, entities participating in competitive procurements shall also be required to meet all the equity accountability requirements for approved vendors and their designees under this subsection (c-10). In developing these requirements, the Agency shall also consider whether equity goals can be further advanced through additional measures.

(4) In the first revision to the long-term renewable energy resources procurement plan and each revision thereafter, the Agency shall include the following:

(A) The current status and number of equity eligible contractors listed in the Energy Workforce Equity Database designed in subsection (c-25), including the number of equity eligible contractors with current certifications as issued by the Agency.

(B) A mechanism for measuring, tracking, and reporting project workforce at the approved vendor or designee level, as applicable, which shall include a measurement methodology and records to be made available for audit by the Agency or the Program Administrator.

(C) A program for approved vendors, designees, eligible persons, and equity eligible contractors to receive trainings, guidance, and other support from the Agency or its designee regarding the equity category outlined in item (vi) of subparagraph (K) of paragraph (1) of subsection (c) and in meeting the minimum equity standards of this subsection (c-10).

(D) A process for certifying equity eligible contractors and equity eligible persons. The certification process shall coordinate with the Energy Workforce Equity Database set forth in subsection (c-25).

(E) An application for waiver of the minimum equity standards of this subsection, which the Agency shall have the discretion to grant in rare circumstances. The Agency may grant such a waiver where the applicant provides evidence of significant efforts toward meeting the minimum equity commitment, including: use of the Energy Workforce Equity Database; efforts to hire or contract with entities that hire eligible persons; and efforts to establish contracting relationships with eligible contractors. The Agency shall support applicants in understanding the Energy Workforce Equity Database and other resources for pursuing compliance of the minimum equity standards. Waivers shall be project-specific, unless the Agency deems it necessary to grant a waiver across a portfolio of projects, and in effect for no longer than one year. Any waiver extension or subsequent waiver request from an applicant shall be subject to the requirements of this Section and shall specify efforts made to reach compliance. When considering whether to grant a waiver, and to what extent, the Agency shall consider the degree to which similarly situated applicants have been able to meet these minimum equity commitments. For repeated waiver requests for specific lack of eligible persons or eligible contractors available, the Agency shall make recommendations to target recruitment to add such eligible persons or eligible contractors to the database.

(5) The Agency shall collect information about work on projects or portfolios of projects subject to these minimum equity standards to ensure compliance with this subsection (c-10). Reporting in furtherance of this requirement may be combined with other annual reporting requirements. Such reporting shall include proof of certification of each equity eligible contractor or equity eligible person during the applicable time period.

As part of the reporting requirement under this subparagraph (5), the Agency shall collect and report information about the use of equity eligible contractors and equity eligible persons, as well as Minimum Equity Standard compliance and waiver usage on the Adjustable Block program and utility-scale projects subject to project labor agreements. The Agency shall note any instances of the projects being unable to meet or requiring a waiver to meet Minimum Equity Standard requirements and the location of those projects.

On an annual basis, the Agency shall submit a written summary of its findings on an annual basis to the General Assembly and the Governor and shall make the report and summary available on the Agency's website.

(6) The Agency shall keep confidential all information and communication that provides private or personal information.

(7) Modifications to the equity accountability system. As part of the update of the long-term renewable resources procurement plan to be initiated in 2023, or sooner if the Agency deems necessary, the Agency shall determine the extent to which the equity accountability system described in this subsection (c-10) has advanced the goals of this amendatory Act of the 102nd General Assembly, including through the inclusion of equity eligible persons and equity eligible contractors in renewable energy credit projects. If the Agency finds that the equity accountability system has failed to meet those goals to its fullest potential, the Agency may revise the following criteria for future Agency procurements: (A) the percentage of project workforce, or other appropriate workforce measure, certified as equity eligible persons or equity eligible contractors; (B) definitions for equity investment eligible persons and equity investment eligible community; and (C) such other modifications necessary to advance the goals of this amendatory Act of the 102nd General Assembly effectively. Such revised criteria may also establish distinct equity accountability systems for different types of procurements or different regions of the State if the Agency finds that doing so will further the purposes of such programs. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, and community-based organizations that work with such persons and contractors.

(c-15) Racial discrimination elimination powers and process.

(1) Purpose. It is the purpose of this subsection to empower the Agency and other State actors to remedy racial discrimination in Illinois' clean energy economy as effectively and expediently as possible, including through the use of race-conscious remedies, such as race-conscious contracting and hiring goals, as consistent with State and federal law.

(2) Racial disparity and discrimination review process.

(A) Within one year after awarding contracts using the equity actions processes established in this Section, the Agency shall publish a report evaluating the effectiveness of the equity actions point criteria of this Section in increasing participation of equity eligible persons and equity eligible contractors. The report shall disaggregate participating workers and contractors by race and ethnicity. The report shall be forwarded to the Governor, the General Assembly, and the Illinois Commerce Commission and be made available to the public.

(B) As soon as is practicable thereafter, the Agency, in consultation with the Department of Commerce and Economic Opportunity, Department of Labor, and other agencies that may be relevant, shall commission and publish a disparity and availability study that measures the presence and impact of discrimination on minority businesses and workers in Illinois' clean energy economy. The Agency may hire consultants and experts to conduct the disparity and availability study, with the retention of those consultants and experts exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Illinois Power Agency shall forward a copy of its findings and recommendations to the Governor, the General Assembly, and the Illinois Commerce Commission. If the disparity and availability study establishes a strong basis in evidence that there is discrimination in Illinois' clean energy economy, the Agency, Department of Commerce and Economic Opportunity, Department of Labor, Department of Corrections, and other appropriate agencies shall take appropriate remedial actions, including race-conscious remedial actions as consistent with State and federal law, to effectively remedy this discrimination. Such remedies may include modification of the equity accountability system as described in subsection (c-10).

(c-20) Program data collection.

(1) Purpose. Data collection, data analysis, and reporting are critical to ensure that the benefits of the clean energy economy provided to Illinois residents and businesses are equitably distributed across the State. The Agency shall collect data from program applicants in order to track and improve equitable distribution of benefits across Illinois communities for all procurements the Agency conducts. The Agency shall use this data to, among other things, measure any potential impact of racial discrimination on the distribution of benefits and provide information necessary to correct any discrimination through methods consistent with State and federal law.

(2) Agency collection of program data. The Agency shall collect demographic and geographic data for each entity awarded contracts under any Agency-administered program.

(3) Required information to be collected. The Agency shall collect the following information from applicants and program participants where applicable:

(A) demographic information, including racial or ethnic identity for real persons employed, contracted, or subcontracted through the program and owners of businesses or entities that apply to receive renewable energy credits from the Agency;

(B) geographic location of the residency of real persons employed, contracted, or subcontracted through the program and geographic location of the headquarters of the business or entity that applies to receive renewable energy credits from the Agency; and

(C) any other information the Agency determines is necessary for the purpose of achieving the purpose of this subsection.

(4) Publication of collected information. The Agency shall publish, at least annually, information on the demographics of program participants on an aggregate basis.

(5) Nothing in this subsection shall be interpreted to limit the authority of the Agency, or other agency or department of the State, to require or collect demographic information from applicants of other State programs.

(c-25) Energy Workforce Equity Database.

(1) The Agency, in consultation with the Department of Commerce and Economic Opportunity, shall create an Energy Workforce Equity Database, and may contract with a third party to do so ("database program administrator"). If the Department decides to contract with a third party, that third party shall be exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Energy Workforce Equity Database shall be a searchable database of suppliers, vendors, and subcontractors for clean energy industries that is:

(A) publicly accessible;

(B) easy for people to find and use;

(C) organized by company specialty or field;

(D) region-specific; and

(E) populated with information including, but not limited to, contacts for suppliers, vendors, or subcontractors who are minority and women-owned business enterprise certified or who participate or have participated in any of the programs described in this Act.

(2) The Agency shall create an easily accessible, public facing online tool using the database information that includes, at a minimum, the following:

(A) a map of environmental justice and equity investment eligible communities;

(B) job postings and recruiting opportunities;

(C) a means by which recruiting clean energy companies can find and interact with current or former participants of clean energy workforce training programs;

(D) information on workforce training service providers and training opportunities available to prospective workers;

(E) renewable energy company diversity reporting;

(F) a list of equity eligible contractors with their contact information, types of work performed, and locations worked in;

(G) reporting on outcomes of the programs described in the workforce programs of the Energy Transition Act, including information such as, but not limited to, retention rate, graduation rate, and placement rates of trainees; and

(H) information about the Jobs and Environmental Justice Grant Program, the Clean Energy Jobs and Justice Fund, and other sources of capital.

(3) The Agency shall ensure the database is regularly updated to ensure information is current and shall coordinate with the Department of Commerce and Economic Opportunity to ensure that it includes information on individuals and entities that are or have participated in the Clean Jobs Workforce Network Program, Clean Energy Contractor Incubator Program, Returning Residents Clean Jobs Training Program, or Clean Energy Primes Contractor Accelerator Program.

(c-30) Enforcement of minimum equity standards. All entities seeking renewable energy credits must submit an annual report to demonstrate compliance with each of the equity commitments required under subsection (c-10). If the Agency concludes the entity has not met or maintained its minimum equity standards required under the applicable subparagraphs under subsection (c-10), the Agency shall deny the entity's ability to participate in procurement programs in subsection (c), including by withholding approved vendor or designee status. The Agency may require the entity to enter into a corrective action plan. An entity that is not recertified for failing to meet required equity actions in subparagraph (c-10) may reapply once they have a corrective action plan and achieve compliance with the minimum equity standards.

(d) Clean coal portfolio standard.

(1) The procurement plans shall include electricity generated using clean coal. Each utility shall enter into one or more sourcing agreements with the initial clean coal facility, as provided in paragraph (3) of this subsection (d), covering electricity generated by the initial clean coal facility representing at least 5% of each utility's total supply to serve the load of eligible retail customers in 2015 and each year thereafter, as described in paragraph (3) of this subsection (d), subject to the limits specified in paragraph (2) of this subsection (d). It is the goal of the State that by January 1, 2025, 25% of the electricity used in the State shall be generated by cost-effective clean coal facilities. For purposes of this subsection (d), "cost-effective" means that the expenditures pursuant to such sourcing agreements do not cause the limit stated in paragraph (2) of this subsection (d) to be exceeded and do not exceed cost-based benchmarks, which shall be developed to assess all expenditures pursuant to such sourcing agreements covering electricity generated by clean coal facilities, other than the initial clean coal facility, by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

A utility party to a sourcing agreement shall immediately retire any emission credits that it receives in connection with the electricity covered by such agreement.

Utilities shall maintain adequate records documenting the purchases under the sourcing agreement to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act.

A utility shall be deemed to have complied with the clean coal portfolio standard specified in this subsection (d) if the utility enters into a sourcing agreement as required by this subsection (d).

(2) For purposes of this subsection (d), the required execution of sourcing agreements with the initial clean coal facility for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the planning year ending immediately prior to the agreement's execution. For purposes of this subsection (d), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges and add-on taxes.

Notwithstanding the requirements of this subsection (d), the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any given year shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to:

(A) in 2010, no more than 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(B) in 2011, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2010 or 1% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(C) in 2012, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2011 or 1.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(D) in 2013, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2012 or 2% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009; and

(E) thereafter, the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of (i) 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or (ii) the incremental amount per kilowatthour paid for these resources in 2013. These requirements may be altered only as provided by statute.

No later than June 30, 2015, the Commission shall review the limitation on the total amount paid under sourcing agreements, if any, with clean coal facilities pursuant to this subsection (d) and report to the General Assembly its findings as to whether that limitation unduly constrains the amount of electricity generated by cost-effective clean coal facilities that is covered by sourcing agreements.

(3) Initial clean coal facility. In order to promote development of clean coal facilities in Illinois, each electric utility subject to this Section shall execute a sourcing agreement to source electricity from a proposed clean coal facility in Illinois (the "initial clean coal facility") that will have a nameplate capacity of at least 500 MW when commercial operation commences, that has a final Clean Air Act permit on June 1, 2009 (the effective date of Public Act 95-1027), and that will meet the definition of clean coal facility in Section 1-10 of this Act when commercial operation commences. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of paragraph (4) of this subsection (d) and shall be executed within 90 days after any such approval by the General Assembly. The Agency and the Commission shall have authority to inspect all books and records associated with the initial clean coal facility during the term of such a sourcing agreement. A utility's sourcing agreement for electricity produced by the initial clean coal facility shall include:

(A) a formula contractual price (the "contract price") approved pursuant to paragraph (4) of this subsection (d), which shall:

(i) be determined using a cost of service methodology employing either a level or deferred capital recovery component, based on a capital structure consisting of 45% equity and 55% debt, and a return on equity as may be approved by the Federal Energy Regulatory Commission, which in any case may not exceed the lower of 11.5% or the rate of return approved by the General Assembly pursuant to paragraph (4) of this subsection (d); and

(ii) provide that all miscellaneous net revenue, including but not limited to net revenue from the sale of emission allowances, if any, substitute natural gas, if any, grants or other support provided by the State of Illinois or the United States Government, firm transmission rights, if any, by-products produced by the facility, energy or capacity derived from the facility and not covered by a sourcing agreement pursuant to paragraph (3) of this subsection (d) or item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, whether generated from the synthesis gas derived from coal, from SNG, or from natural gas, shall be credited against the revenue requirement for this initial clean coal facility;

(B) power purchase provisions, which shall:

(i) provide that the utility party to such sourcing agreement shall pay the contract price for electricity delivered under such sourcing agreement;

(ii) require delivery of electricity to the regional transmission organization market of the utility that is party to such sourcing agreement;

(iii) require the utility party to such sourcing agreement to buy from the initial clean coal facility in each hour an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount purchased by the utility in any year will be limited by paragraph (2) of this subsection (d); and

(iv) be considered pre-existing contracts in such utility's procurement plans for eligible retail customers;

(C) contract for differences provisions, which shall:

(i) require the utility party to such sourcing agreement to contract with the initial clean coal facility in each hour with respect to an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the utility's service territory in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount paid by the utility in any year will be limited by paragraph (2) of this subsection (d);

(ii) provide that the utility's payment obligation in respect of the quantity of electricity determined pursuant to the preceding clause (i) shall be limited to an amount equal to (1) the difference between the contract price determined pursuant to subparagraph (A) of paragraph (3) of this subsection (d) and the day-ahead price for electricity delivered to the regional transmission organization market of the utility that is party to such sourcing agreement (or any successor delivery point at which such utility's supply obligations are financially settled on an hourly basis) (the "reference price") on the day preceding the day on which the electricity is delivered to the initial clean coal facility busbar, multiplied by (2) the quantity of electricity determined pursuant to the preceding clause (i); and

(iii) not require the utility to take physical delivery of the electricity produced by the facility;

(D) general provisions, which shall:

(i) specify a term of no more than 30 years, commencing on the commercial operation date of the facility;

(ii) provide that utilities shall maintain adequate records documenting purchases under the sourcing agreements entered into to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act;

(iii) provide that all costs associated with the initial clean coal facility will be periodically reported to the Federal Energy Regulatory Commission and to purchasers in accordance with applicable laws governing cost-based wholesale power contracts;

(iv) permit the Illinois Power Agency to assume ownership of the initial clean coal facility, without monetary consideration and otherwise on reasonable terms acceptable to the Agency, if the Agency so requests no less than 3 years prior to the end of the stated contract term;

(v) require the owner of the initial clean coal facility to provide documentation to the Commission each year, starting in the facility's first year of commercial operation, accurately reporting the quantity of carbon emissions from the facility that have been captured and sequestered and report any quantities of carbon released from the site or sites at which carbon emissions were sequestered in prior years, based on continuous monitoring of such sites. If, in any year after the first year of commercial operation, the owner of the facility fails to demonstrate that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon dioxide into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The cost of such offsets for the facility that are not recoverable shall not exceed $15 million in any given year. No costs of any such purchases of carbon offsets may be recovered from a utility or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements specified in paragraph (3) of this subsection (d) shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General. The Commission may, in the course of the review specified in item (vii), reduce the allowable return on equity for the facility if the facility willfully fails to comply with the carbon capture and sequestration requirements set forth in this item (v);

(vi) include limits on, and accordingly provide for modification of, the amount the utility is required to source under the sourcing agreement consistent with paragraph (2) of this subsection (d);

(vii) require Commission review: (1) to determine the justness, reasonableness, and prudence of the inputs to the formula referenced in subparagraphs (A)(i) through (A)(iii) of paragraph (3) of this subsection (d), prior to an adjustment in those inputs including, without limitation, the capital structure and return on equity, fuel costs, and other operations and maintenance costs and (2) to approve the costs to be passed through to customers under the sourcing agreement by which the utility satisfies its statutory obligations. Commission review shall occur no less than every 3 years, regardless of whether any adjustments have been proposed, and shall be completed within 9 months;

(viii) limit the utility's obligation to such amount as the utility is allowed to recover through tariffs filed with the Commission, provided that neither the clean coal facility nor the utility waives any right to assert federal pre-emption or any other argument in response to a purported disallowance of recovery costs;

(ix) limit the utility's or alternative retail electric supplier's obligation to incur any liability until such time as the facility is in commercial operation and generating power and energy and such power and energy is being delivered to the facility busbar;

(x) provide that the owner or owners of the initial clean coal facility, which is the counterparty to such sourcing agreement, shall have the right from time to time to elect whether the obligations of the utility party thereto shall be governed by the power purchase provisions or the contract for differences provisions;

(xi) append documentation showing that the formula rate and contract, insofar as they relate to the power purchase provisions, have been approved by the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act;

(xii) provide that any changes to the terms of the contract, insofar as such changes relate to the power purchase provisions, are subject to review under the public interest standard applied by the Federal Energy Regulatory Commission pursuant to Sections 205 and 206 of the Federal Power Act; and

(xiii) conform with customary lender requirements in power purchase agreements used as the basis for financing non-utility generators.

(4) Effective date of sourcing agreements with the initial clean coal facility. Any proposed sourcing agreement with the initial clean coal facility shall not become effective unless the following reports are prepared and submitted and authorizations and approvals obtained:

(i) Facility cost report. The owner of the initial clean coal facility shall submit to the Commission, the Agency, and the General Assembly a front-end engineering and design study, a facility cost report, method of financing (including but not limited to structure and associated costs), and an operating and maintenance cost quote for the facility (collectively "facility cost report"), which shall be prepared in accordance with the requirements of this paragraph (4) of subsection (d) of this Section, and shall provide the Commission and the Agency access to the work papers, relied upon documents, and any other backup documentation related to the facility cost report.

(ii) Commission report. Within 6 months following receipt of the facility cost report, the Commission, in consultation with the Agency, shall submit a report to the General Assembly setting forth its analysis of the facility cost report. Such report shall include, but not be limited to, a comparison of the costs associated with electricity generated by the initial clean coal facility to the costs associated with electricity generated by other types of generation facilities, an analysis of the rate impacts on residential and small business customers over the life of the sourcing agreements, and an analysis of the likelihood that the initial clean coal facility will commence commercial operation by and be delivering power to the facility's busbar by 2016. To assist in the preparation of its report, the Commission, in consultation with the Agency, may hire one or more experts or consultants, the costs of which shall be paid for by the owner of the initial clean coal facility. The Commission and Agency may begin the process of selecting such experts or consultants prior to receipt of the facility cost report.

(iii) General Assembly approval. The proposed sourcing agreements shall not take effect unless, based on the facility cost report and the Commission's report, the General Assembly enacts authorizing legislation approving (A) the projected price, stated in cents per kilowatthour, to be charged for electricity generated by the initial clean coal facility, (B) the projected impact on residential and small business customers' bills over the life of the sourcing agreements, and (C) the maximum allowable return on equity for the project; and

(iv) Commission review. If the General Assembly enacts authorizing legislation pursuant to subparagraph (iii) approving a sourcing agreement, the Commission shall, within 90 days of such enactment, complete a review of such sourcing agreement. During such time period, the Commission shall implement any directive of the General Assembly, resolve any disputes between the parties to the sourcing agreement concerning the terms of such agreement, approve the form of such agreement, and issue an order finding that the sourcing agreement is prudent and reasonable.

The facility cost report shall be prepared as follows:

(A) The facility cost report shall be prepared by duly licensed engineering and construction firms detailing the estimated capital costs payable to one or more contractors or suppliers for the engineering, procurement and construction of the components comprising the initial clean coal facility and the estimated costs of operation and maintenance of the facility. The facility cost report shall include:

(i) an estimate of the capital cost of the core plant based on one or more front end engineering and design studies for the gasification island and related facilities. The core plant shall include all civil, structural, mechanical, electrical, control, and safety systems.

(ii) an estimate of the capital cost of the balance of the plant, including any capital costs associated with sequestration of carbon dioxide emissions and all interconnects and interfaces required to operate the facility, such as transmission of electricity, construction or backfeed power supply, pipelines to transport substitute natural gas or carbon dioxide, potable water supply, natural gas supply, water supply, water discharge, landfill, access roads, and coal delivery.

The quoted construction costs shall be expressed in nominal dollars as of the date that the quote is prepared and shall include capitalized financing costs during construction, taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the construction cost quote is expressed.

(B) The front end engineering and design study for the gasification island and the cost study for the balance of plant shall include sufficient design work to permit quantification of major categories of materials, commodities and labor hours, and receipt of quotes from vendors of major equipment required to construct and operate the clean coal facility.

(C) The facility cost report shall also include an operating and maintenance cost quote that will provide the estimated cost of delivered fuel, personnel, maintenance contracts, chemicals, catalysts, consumables, spares, and other fixed and variable operations and maintenance costs. The delivered fuel cost estimate will be provided by a recognized third party expert or experts in the fuel and transportation industries. The balance of the operating and maintenance cost quote, excluding delivered fuel costs, will be developed based on the inputs provided by duly licensed engineering and construction firms performing the construction cost quote, potential vendors under long-term service agreements and plant operating agreements, or recognized third party plant operator or operators.

The operating and maintenance cost quote (including the cost of the front end engineering and design study) shall be expressed in nominal dollars as of the date that the quote is prepared and shall include taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the operating and maintenance cost quote is expressed.

(D) The facility cost report shall also include an analysis of the initial clean coal facility's ability to deliver power and energy into the applicable regional transmission organization markets and an analysis of the expected capacity factor for the initial clean coal facility.

(E) Amounts paid to third parties unrelated to the owner or owners of the initial clean coal facility to prepare the core plant construction cost quote, including the front end engineering and design study, and the operating and maintenance cost quote will be reimbursed through Coal Development Bonds.

(5) Re-powering and retrofitting coal-fired power plants previously owned by Illinois utilities to qualify as clean coal facilities. During the 2009 procurement planning process and thereafter, the Agency and the Commission shall consider sourcing agreements covering electricity generated by power plants that were previously owned by Illinois utilities and that have been or will be converted into clean coal facilities, as defined by Section 1-10 of this Act. Pursuant to such procurement planning process, the owners of such facilities may propose to the Agency sourcing agreements with utilities and alternative retail electric suppliers required to comply with subsection (d) of this Section and item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, covering electricity generated by such facilities. In the case of sourcing agreements that are power purchase agreements, the contract price for electricity sales shall be established on a cost of service basis. In the case of sourcing agreements that are contracts for differences, the contract price from which the reference price is subtracted shall be established on a cost of service basis. The Agency and the Commission may approve any such utility sourcing agreements that do not exceed cost-based benchmarks developed by the procurement administrator, in consultation with the Commission staff, Agency staff and the procurement monitor, subject to Commission review and approval. The Commission shall have authority to inspect all books and records associated with these clean coal facilities during the term of any such contract.

(6) Costs incurred under this subsection (d) or pursuant to a contract entered into under this subsection (d) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

(d-5) Zero emission standard.

(1) Beginning with the delivery year commencing on June 1, 2017, the Agency shall, for electric utilities that serve at least 100,000 retail customers in this State, procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the actual amount of electricity delivered by each electric utility to retail customers in the State during calendar year 2014. For an electric utility serving fewer than 100,000 retail customers in this State that requested, under Section 16-111.5 of the Public Utilities Act, that the Agency procure power and energy for all or a portion of the utility's Illinois load for the delivery year commencing June 1, 2016, the Agency shall procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the portion of power and energy to be procured by the Agency for the utility. The duration of the contracts procured under this subsection (d-5) shall be for a term of 10 years ending May 31, 2027. The quantity of zero emission credits to be procured under the contracts shall be all of the zero emission credits generated by the zero emission facility in each delivery year; however, if the zero emission facility is owned by more than one entity, then the quantity of zero emission credits to be procured under the contracts shall be the amount of zero emission credits that are generated from the portion of the zero emission facility that is owned by the winning supplier.

The 16% value identified in this paragraph (1) is the average of the percentage targets in subparagraph (B) of paragraph (1) of subsection (c) of this Section for the 5 delivery years beginning June 1, 2017.

The procurement process shall be subject to the following provisions:

(A) Those zero emission facilities that intend to participate in the procurement shall submit to the Agency the following eligibility information for each zero emission facility on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the zero emission facility;

(ii) the amount of power generated annually for each of the years 2005 through 2015, and the projected zero emission credits to be generated over the remaining useful life of the zero emission facility, which shall be used to determine the capability of each facility;

(iii) the annual zero emission facility cost projections, expressed on a per megawatthour basis, over the next 6 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; non-fuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this item (iii), that the costs could reasonably be avoided only by ceasing operations of the zero emission facility; and

(iv) a commitment to continue operating, for the duration of the contract or contracts executed under the procurement held under this subsection (d-5), the zero emission facility that produces the zero emission credits to be procured in the procurement.

The information described in item (iii) of this subparagraph (A) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(B) The price for each zero emission credit procured under this subsection (d-5) for each delivery year shall be in an amount that equals the Social Cost of Carbon, expressed on a price per megawatthour basis. However, to ensure that the procurement remains affordable to retail customers in this State if electricity prices increase, the price in an applicable delivery year shall be reduced below the Social Cost of Carbon by the amount ("Price Adjustment") by which the market price index for the applicable delivery year exceeds the baseline market price index for the consecutive 12-month period ending May 31, 2016. If the Price Adjustment is greater than or equal to the Social Cost of Carbon in an applicable delivery year, then no payments shall be due in that delivery year. The components of this calculation are defined as follows:

(i) Social Cost of Carbon: The Social Cost of Carbon is $16.50 per megawatthour, which is based on the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each year of the program. Beginning with the delivery year commencing June 1, 2023, the price per megawatthour shall increase by $1 per megawatthour, and continue to increase by an additional $1 per megawatthour each delivery year thereafter.

(ii) Baseline market price index: The baseline market price index for the consecutive 12-month period ending May 31, 2016 is $31.40 per megawatthour, which is based on the sum of (aa) the average day-ahead energy price across all hours of such 12-month period at the PJM Interconnection LLC Northern Illinois Hub, (bb) 50% multiplied by the Base Residual Auction, or its successor, capacity price for the rest of the RTO zone group determined by PJM Interconnection LLC, divided by 24 hours per day, and (cc) 50% multiplied by the Planning Resource Auction, or its successor, capacity price for Zone 4 determined by the Midcontinent Independent System Operator, Inc., divided by 24 hours per day.

(iii) Market price index: The market price index for a delivery year shall be the sum of projected energy prices and projected capacity prices determined as follows:

(aa) Projected energy prices: the projected energy prices for the applicable delivery year shall be calculated once for the year using the forward market price for the PJM Interconnection, LLC Northern Illinois Hub. The forward market price shall be calculated as follows: the energy forward prices for each month of the applicable delivery year averaged for each trade date during the calendar year immediately preceding that delivery year to produce a single energy forward price for the delivery year. The forward market price calculation shall use data published by the Intercontinental Exchange, or its successor.

(bb) Projected capacity prices:

(I) For the delivery years commencing June 1, 2017, June 1, 2018, and June 1, 2019, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the rest of the RTO zone group as determined by PJM Interconnection LLC, divided by 24 hours per day and, (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

(II) For the delivery year commencing June 1, 2020, and each year thereafter, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the ComEd zone as determined by PJM Interconnection LLC, divided by 24 hours per day, and (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

For purposes of this subsection (d-5):

"Rest of the RTO" and "ComEd Zone" shall have the meaning ascribed to them by PJM Interconnection, LLC.

"RTO" means regional transmission organization.

(C) No later than 45 days after June 1, 2017 (the effective date of Public Act 99-906), the Agency shall publish its proposed zero emission standard procurement plan. The plan shall be consistent with the provisions of this paragraph (1) and shall provide that winning bids shall be selected based on public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. In particular, the selection of winning bids shall take into account the incremental environmental benefits resulting from the procurement, such as any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would cease to exist if the procurements were not held, including the preservation of zero emission facilities. The plan shall also describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement and given full effect.

For purposes of developing the plan, the Agency shall consider any reports issued by a State agency, board, or commission under House Resolution 1146 of the 98th General Assembly and paragraph (4) of subsection (d) of this Section, as well as publicly available analyses and studies performed by or for regional transmission organizations that serve the State and their independent market monitors.

Upon publishing of the zero emission standard procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 10 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 60 days later than June 1, 2017 (the effective date of Public Act 99-906), the Agency shall revise the plan as necessary based on the comments received and file its zero emission standard procurement plan with the Commission.

If the Commission determines that the plan will result in the procurement of cost-effective zero emission credits, then the Commission shall, after notice and hearing, but no later than 45 days after the Agency filed the plan, approve the plan or approve with modification. For purposes of this subsection (d-5), "cost effective" means the projected costs of procuring zero emission credits from zero emission facilities do not cause the limit stated in paragraph (2) of this subsection to be exceeded.

(C-5) As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the winning bids satisfy the public interest criteria described in subparagraph (C) of this paragraph (1) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of winning bids takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would have ceased to exist if the procurements had not been held, such as the preservation of zero emission facilities;

(iii) quantify the environmental benefit of preserving the resources identified in item (ii) of this subparagraph (C-5), including the following:

(aa) the value of avoided greenhouse gas emissions measured as the product of the zero emission facilities' output over the contract term multiplied by the U.S. Environmental Protection Agency eGrid subregion carbon dioxide emission rate and the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each delivery year; and

(bb) the costs of replacement with other zero carbon dioxide resources, including wind and photovoltaic, based upon the simple average of the following:

(I) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale wind projects in the procurement events specified in item (i) of subparagraph (G) of paragraph (1) of subsection (c) of this Section; and

(II) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects in the procurement events specified in item (ii) of subparagraph (G) of paragraph (1) of subsection (c) of this Section and, after January 1, 2015, renewable energy credits from photovoltaic distributed generation projects in procurement events held under subsection (c) of this Section.

Each utility shall enter into binding contractual arrangements with the winning suppliers.

The procurement described in this subsection (d-5), including, but not limited to, the execution of all contracts procured, shall be completed no later than May 10, 2017. Based on the effective date of Public Act 99-906, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (C) and (D) of this paragraph (1). The procurement and plan approval processes required by this subsection (d-5) shall be conducted in conjunction with the procurement and plan approval processes required by subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. Notwithstanding whether a procurement event is conducted under Section 16-111.5 of the Public Utilities Act, the Agency shall immediately initiate a procurement process on June 1, 2017 (the effective date of Public Act 99-906).

(D) Following the procurement event described in this paragraph (1) and consistent with subparagraph (B) of this paragraph (1), the Agency shall calculate the payments to be made under each contract for the next delivery year based on the market price index for that delivery year. The Agency shall publish the payment calculations no later than May 25, 2017 and every May 25 thereafter.

(E) Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the zero emission facility may, as applicable, suspend or terminate performance under the contracts in the following instances:

(i) A zero emission facility shall be excused from its performance under the contract for any cause beyond the control of the resource, including, but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of the foregoing cases, by exercise of commercially reasonable efforts the zero emission facility could not reasonably have been expected to avoid, and which, by the exercise of commercially reasonable efforts, it has been unable to overcome. In such event, the zero emission facility shall be excused from performance for the duration of the event, including, but not limited to, delivery of zero emission credits, and no payment shall be due to the zero emission facility during the duration of the event.

(ii) A zero emission facility shall be permitted to terminate the contract if legislation is enacted into law by the General Assembly that imposes or authorizes a new tax, special assessment, or fee on the generation of electricity, the ownership or leasehold of a generating unit, or the privilege or occupation of such generation, ownership, or leasehold of generation units by a zero emission facility. However, the provisions of this item (ii) do not apply to any generally applicable tax, special assessment or fee, or requirements imposed by federal law.

(iii) A zero emission facility shall be permitted to terminate the contract in the event that the resource requires capital expenditures in excess of $40,000,000 that were neither known nor reasonably foreseeable at the time it executed the contract and that a prudent owner or operator of such resource would not undertake.

(iv) A zero emission facility shall be permitted to terminate the contract in the event the Nuclear Regulatory Commission terminates the resource's license.

(F) If the zero emission facility elects to terminate a contract under subparagraph (E) of this paragraph (1), then the Commission shall reopen the docket in which the Commission approved the zero emission standard procurement plan under subparagraph (C) of this paragraph (1) and, after notice and hearing, enter an order acknowledging the contract termination election if such termination is consistent with the provisions of this subsection (d-5).

(2) For purposes of this subsection (d-5), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d-5), the total amount paid for electric service includes, without limitation, amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the total of zero emission credits procured under a procurement plan shall be subject to the limitations of this paragraph (2). For each delivery year, the contractual volume receiving payments in such year shall be reduced for all retail customers based on the amount necessary to limit the net increase that delivery year to the costs of those credits included in the amounts paid by eligible retail customers in connection with electric service to no more than 1.65% of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009. The result of this computation shall apply to and reduce the procurement for all retail customers, and all those customers shall pay the same single, uniform cents per kilowatthour charge under subsection (k) of Section 16-108 of the Public Utilities Act. To arrive at a maximum dollar amount of zero emission credits to be paid for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the delivery year immediately prior to the procurement, to all retail customers in its service territory. Unpaid contractual volume for any delivery year shall be paid in any subsequent delivery year in which such payments can be made without exceeding the amount specified in this paragraph (2). The calculations required by this paragraph (2) shall be made only once for each procurement plan year. Once the determination as to the amount of zero emission credits to be paid is made based on the calculations set forth in this paragraph (2), no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. All costs incurred under those contracts and in implementing this subsection (d-5) shall be recovered by the electric utility as provided in this Section.

No later than June 30, 2019, the Commission shall review the limitation on the amount of zero emission credits procured under this subsection (d-5) and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of cost-effective zero emission credits.

(3) Six years after the execution of a contract under this subsection (d-5), the Agency shall determine whether the actual zero emission credit payments received by the supplier over the 6-year period exceed the Average ZEC Payment. In addition, at the end of the term of a contract executed under this subsection (d-5), or at the time, if any, a zero emission facility's contract is terminated under subparagraph (E) of paragraph (1) of this subsection (d-5), then the Agency shall determine whether the actual zero emission credit payments received by the supplier over the term of the contract exceed the Average ZEC Payment, after taking into account any amounts previously credited back to the utility under this paragraph (3). If the Agency determines that the actual zero emission credit payments received by the supplier over the relevant period exceed the Average ZEC Payment, then the supplier shall credit the difference back to the utility. The amount of the credit shall be remitted to the applicable electric utility no later than 120 days after the Agency's determination, which the utility shall reflect as a credit on its retail customer bills as soon as practicable; however, the credit remitted to the utility shall not exceed the total amount of payments received by the facility under its contract.

For purposes of this Section, the Average ZEC Payment shall be calculated by multiplying the quantity of zero emission credits delivered under the contract times the average contract price. The average contract price shall be determined by subtracting the amount calculated under subparagraph (B) of this paragraph (3) from the amount calculated under subparagraph (A) of this paragraph (3), as follows:

(A) The average of the Social Cost of Carbon, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract.

(B) The average of the market price indices, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract, minus the baseline market price index, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5).

If the subtraction yields a negative number, then the Average ZEC Payment shall be zero.

(4) Cost-effective zero emission credits procured from zero emission facilities shall satisfy the applicable definitions set forth in Section 1-10 of this Act.

(5) The electric utility shall retire all zero emission credits used to comply with the requirements of this subsection (d-5).

(6) Electric utilities shall be entitled to recover all of the costs associated with the procurement of zero emission credits through an automatic adjustment clause tariff in accordance with subsection (k) and (m) of Section 16-108 of the Public Utilities Act, and the contracts executed under this subsection (d-5) shall provide that the utilities' payment obligations under such contracts shall be reduced if an adjustment is required under subsection (m) of Section 16-108 of the Public Utilities Act.

(7) This subsection (d-5) shall become inoperative on January 1, 2028.

(d-10) Nuclear Plant Assistance; carbon mitigation credits.

(1) The General Assembly finds:

(A) The health, welfare, and prosperity of all Illinois citizens require that the State of Illinois act to avoid and not increase carbon emissions from electric generation sources while continuing to ensure affordable, stable, and reliable electricity to all citizens.

(B) Absent immediate action by the State to preserve existing carbon-free energy resources, those resources may retire, and the electric generation needs of Illinois' retail customers may be met instead by facilities that emit significant amounts of carbon pollution and other harmful air pollutants at a high social and economic cost until Illinois is able to develop other forms of clean energy.

(C) The General Assembly finds that nuclear power generation is necessary for the State's transition to 100% clean energy, and ensuring continued operation of nuclear plants advances environmental and public health interests through providing carbon-free electricity while reducing the air pollution profile of the Illinois energy generation fleet.

(D) The clean energy attributes of nuclear generation facilities support the State in its efforts to achieve 100% clean energy.

(E) The State currently invests in various forms of clean energy, including, but not limited to, renewable energy, energy efficiency, and low-emission vehicles, among others.

(F) The Environmental Protection Agency commissioned an independent audit which provided a detailed assessment of the financial condition of the Illinois nuclear fleet to evaluate its financial viability and whether the environmental benefits of such resources were at risk. The report identified the risk of losing the environmental benefits of several specific nuclear units. The report also identified that the LaSalle County Generating Station will continue to operate through 2026 and therefore is not eligible to participate in the carbon mitigation credit program.

(G) Nuclear plants provide carbon-free energy, which helps to avoid many health-related negative impacts for Illinois residents.

(H) The procurement of carbon mitigation credits representing the environmental benefits of carbon-free generation will further the State's efforts at achieving 100% clean energy and decarbonizing the electricity sector in a safe, reliable, and affordable manner. Further, the procurement of carbon emission credits will enhance the health and welfare of Illinois residents through decreased reliance on more highly polluting generation.

(I) The General Assembly therefore finds it necessary to establish carbon mitigation credits to ensure decreased reliance on more carbon-intensive energy resources, for transitioning to a fully decarbonized electricity sector, and to help ensure health and welfare of the State's residents.

(2) As used in this subsection:

"Baseline costs" means costs used to establish a customer protection cap that have been evaluated through an independent audit of a carbon-free energy resource conducted by the Environmental Protection Agency that evaluated projected annual costs for operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this definition, that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource.

"Carbon mitigation credit" means a tradable credit that represents the carbon emission reduction attributes of one megawatt-hour of energy produced from a carbon-free energy resource.

"Carbon-free energy resource" means a generation facility that: (1) is fueled by nuclear power; and (2) is interconnected to PJM Interconnection, LLC.

(3) Procurement.

(A) Beginning with the delivery year commencing on June 1, 2022, the Agency shall, for electric utilities serving at least 3,000,000 retail customers in the State, seek to procure contracts for no more than approximately 54,500,000 cost-effective carbon mitigation credits from carbon-free energy resources because such credits are necessary to support current levels of carbon-free energy generation and ensure the State meets its carbon dioxide emissions reduction goals. The Agency shall not make a partial award of a contract for carbon mitigation credits covering a fractional amount of a carbon-free energy resource's projected output.

(B) Each carbon-free energy resource that intends to participate in a procurement shall be required to submit to the Agency the following information for the resource on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the carbon-free energy resource;

(ii) the amount of power generated annually for each of the past 10 years, which shall be used to determine the capability of each facility;

(iii) a commitment to be reflected in any contract entered into pursuant to this subsection (d-10) to continue operating the carbon-free energy resource at a capacity factor of at least 88% annually on average for the duration of the contract or contracts executed under the procurement held under this subsection (d-10), except in an instance described in subparagraph (E) of paragraph (1) of subsection (d-5) of this Section or made impracticable as a result of compliance with law or regulation;

(iv) financial need and the risk of loss of the environmental benefits of such resource, which shall include the following information:

(I) the carbon-free energy resource's cost projections, expressed on a per megawatt-hour basis, over the next 5 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this subitem (I), that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource; and

(II) the carbon-free energy resource's revenue projections, including energy, capacity, ancillary services, any other direct State support, known or anticipated federal attribute credits, known or anticipated tax credits, and any other direct federal support.

The information described in this subparagraph (B) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of the Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(C) The Agency shall solicit bids for the contracts described in this subsection (d-10) from carbon-free energy resources that have satisfied the requirements of subparagraph (B) of this paragraph (3). The contracts procured pursuant to a procurement event shall reflect, and be subject to, the following terms, requirements, and limitations:

(i) Contracts are for delivery of carbon mitigation credits, and are not energy or capacity sales contracts requiring physical delivery. Pursuant to item (iii), contract payments shall fully deduct the value of any monetized federal production tax credits, credits issued pursuant to a federal clean energy standard, and other federal credits if applicable.

(ii) Contracts for carbon mitigation credits shall commence with the delivery year beginning on June 1, 2022 and shall be for a term of 5 delivery years concluding on May 31, 2027.

(iii) The price per carbon mitigation credit to be paid under a contract for a given delivery year shall be equal to an accepted bid price less the sum of:

(I) one of the following energy price indices, selected by the bidder at the time of the bid for the term of the contract:

(aa) the weighted-average hourly day-ahead price for the applicable delivery year at the busbar of all resources procured pursuant to this subsection (d-10), weighted by actual production from the resources; or

(bb) the projected energy price for the PJM Interconnection, LLC Northern Illinois Hub for the applicable delivery year determined according to subitem (aa) of item (iii) of subparagraph (B) of paragraph (1) of subsection (d-5).

(II) the Base Residual Auction Capacity Price for the ComEd zone as determined by PJM Interconnection, LLC, divided by 24 hours per day, for the applicable delivery year for the first 3 delivery years, and then any subsequent delivery years unless the PJM Interconnection, LLC applies the Minimum Offer Price Rule to participating carbon-free energy resources because they supply carbon mitigation credits pursuant to this Section at which time, upon notice by the carbon-free energy resource to the Commission and subject to the Commission's confirmation, the value under this subitem shall be zero, as further described in the carbon mitigation credit procurement plan; and

(III) any value of monetized federal tax credits, direct payments, or similar subsidy provided to the carbon-free energy resource from any unit of government that is not already reflected in energy prices.

If the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net positive value, then the electric utility counterparty to the contract shall multiply such net value by the applicable contract quantity and remit the amount to the supplier.

To protect retail customers from retail rate impacts that may arise upon the initiation of carbon policy changes, if the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net negative value, then the supplier counterparty to the contract shall multiply such net value by the applicable contract quantity and remit such amount to the electric utility counterparty. The electric utility shall reflect such amounts remitted by suppliers as a credit on its retail customer bills as soon as practicable.

(iv) To ensure that retail customers in Northern Illinois do not pay more for carbon mitigation credits than the value such credits provide, and notwithstanding the provisions of this subsection (d-10), the Agency shall not accept bids for contracts that exceed a customer protection cap equal to the baseline costs of carbon-free energy resources.

The baseline costs for the applicable year shall be the following:

(I) For the delivery year beginning June 1, 2022, the baseline costs shall be an amount equal to $30.30 per megawatt-hour.

(II) For the delivery year beginning June 1, 2023, the baseline costs shall be an amount equal to $32.50 per megawatt-hour.

(III) For the delivery year beginning June 1, 2024, the baseline costs shall be an amount equal to $33.43 per megawatt-hour.

(IV) For the delivery year beginning June 1, 2025, the baseline costs shall be an amount equal to $33.50 per megawatt-hour.

(V) For the delivery year beginning June 1, 2026, the baseline costs shall be an amount equal to $34.50 per megawatt-hour.

An Environmental Protection Agency consultant forecast, included in a report issued April 14, 2021, projects that a carbon-free energy resource has the opportunity to earn on average approximately $30.28 per megawatt-hour, for the sale of energy and capacity during the time period between 2022 and 2027. Therefore, the sale of carbon mitigation credits provides the opportunity to receive an additional amount per megawatt-hour in addition to the projected prices for energy and capacity.

Although actual energy and capacity prices may vary from year-to-year, the General Assembly finds that this customer protection cap will help ensure that the cost of carbon mitigation credits will be less than its value, based upon the social cost of carbon identified in the Technical Support Document issued in February 2021 by the U.S. Interagency Working Group on Social Cost of Greenhouse Gases and the PJM Interconnection, LLC carbon dioxide marginal emission rate for 2020, and that a carbon-free energy resource receiving payment for carbon mitigation credits receives no more than necessary to keep those units in operation.

(D) No later than 7 days after the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall publish its proposed carbon mitigation credit procurement plan. The Plan shall provide that winning bids shall be selected by taking into consideration which resources best match public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. The selection of winning bids shall also take into account the incremental environmental benefits resulting from the procurement or procurements, such as any existing environmental benefits that are preserved by a procurement held under this subsection (d-10) and would cease to exist if the procurement were not held, including the preservation of carbon-free energy resources. For those bidders having the same public interest criteria score, the relative ranking of such bidders shall be determined by price. The Plan shall describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement. The Plan shall, to the extent practical and permissible by federal law, ensure that successful bidders make commercially reasonable efforts to apply for federal tax credits, direct payments, or similar subsidy programs that support carbon-free generation and for which the successful bidder is eligible. Upon publishing of the carbon mitigation credit procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 7 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 19 days later than the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall revise the plan as necessary based on the comments received and file its carbon mitigation credit procurement plan with the Commission.

(E) If the Commission determines that the plan is likely to result in the procurement of cost-effective carbon mitigation credits, then the Commission shall, after notice and hearing and opportunity for comment, but no later than 42 days after the Agency filed the plan, approve the plan or approve it with modification. For purposes of this subsection (d-10), "cost-effective" means carbon mitigation credits that are procured from carbon-free energy resources at prices that are within the limits specified in this paragraph (3). As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the selected carbon-free energy resources satisfy the public interest criteria described in this paragraph (3) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of carbon-free energy resources takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under this amendatory Act of the 102nd General Assembly and would have ceased to exist if the procurements had not been held, such as the preservation of carbon-free energy resources;

(iii) quantify the environmental benefit of preserving the carbon-free energy resources procured pursuant to this subsection (d-10), including the following:

(I) an assessment value of avoided greenhouse gas emissions measured as the product of the carbon-free energy resources' output over the contract term, using generally accepted methodologies for the valuation of avoided emissions; and

(II) an assessment of costs of replacement with other carbon-free energy resources and renewable energy resources, including wind and photovoltaic generation, based upon an assessment of the prices paid for renewable energy credits through programs and procurements conducted pursuant to subsection (c) of Section 1-75 of this Act, and the additional storage necessary to produce the same or similar capability of matching customer usage patterns.

(F) The procurements described in this paragraph (3), including, but not limited to, the execution of all contracts procured, shall be completed no later than December 3, 2021. The procurement and plan approval processes required by this paragraph (3) shall be conducted in conjunction with the procurement and plan approval processes required by Section 16-111.5 of the Public Utilities Act, to the extent practicable. However, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (D) and (E) of this paragraph (3) to meet the December 3, 2021 contract execution deadline. Following the completion of such procurements, and consistent with this paragraph (3), the Agency shall calculate the payments to be made under each contract in a timely fashion.

(F-1) Costs incurred by the electric utility pursuant to a contract authorized by this subsection (d-10) shall be deemed prudently incurred and reasonable in amount, and the electric utility shall be entitled to full cost recovery pursuant to a tariff or tariffs filed with the Commission.

(G) The counterparty electric utility shall retire all carbon mitigation credits used to comply with the requirements of this subsection (d-10).

(H) If a carbon-free energy resource is sold to another owner, the rights, obligations, and commitments under this subsection (d-10) shall continue to the subsequent owner.

(I) This subsection (d-10) shall become inoperative on January 1, 2028.

(d-20) Energy storage system portfolio standard.

(1) The General Assembly finds that the deployment of energy storage systems is necessary to successfully integrate high levels of renewable energy, to avoid the creation and increase of carbon emissions from electric generation sources, and to ensure affordable, stable, clean, reliable, and resilient electricity.

(2) The Agency shall develop an energy storage system resources procurement plan that includes the competitive procurement events, procurement programs, or both, as necessary (i) to meet the goals set forth in this subsection (d-20), (ii) to meet the planning requirements established under Sections 16-201 and 16-202 of the Public Utilities Act, (iii) to meet the clean energy policy established by Public Act 102-662, and (iv) to cause electric utilities serving more than 300,000 customers in the State as of January 1, 2019 to contract for energy storage resources. The energy storage system resources procurement plan approval processes shall be conducted consistent with the processes outlined in paragraph (6) of subsection (b) of Section 16-111.5 of the Public Utilities Act, with the initial energy storage system resources procurement plan released for comment in calendar year 2027. The Agency shall review and may revise the energy storage system resources procurement plan at least every 2 years. The Agency shall establish, and the Commission shall approve or approve as modified, an energy storage system resources procurement plan that includes:

(A) storage targets in addition to the initial procurements specified in paragraph (3) of this subsection (d-20) at levels identified through the integrated resource planning process outlined in Section 16-202 of the Public Utilities Act;

(B) a bid selection process that is based on the bid price, when compared with an equal energy storage duration and interconnected to the same independent system operator (ISO) or regional transmission organization (RTO), and that may provide for consideration of the following:

(i) the project's viability and ability to meet or exceed operational date targets;

(ii) the developer's experience;

(iii) requirements for demonstration of binding site control that are sufficient for proposed energy storage facilities;

(iv) the availability or dependence on any transmission expansion or upgrades needed; and

(v) other resource adequacy and reliability considerations;

(C) consideration of the need to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time;

(D) proposals for the financial support of energy storage systems using contract models, which may include, but are not limited to, the following:

(i) an indexed storage credit procurement, including payments to energy storage system owners or operators with any offsets and refunds for potential energy and capacity revenues;

(ii) support for energy storage system resources through contract structures that do not create contractual obligations on utilities that are not contingent on full and timely cost recovery, that avoid negative financial impacts on the utilities, and that are agreed upon by the utilities; and

(iii) other approaches as deemed suitable by the Agency and the Commission; and

(E) consideration that the Agency may include a methodology that could prioritize procurement of energy storage resources that are located in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act.

In developing its procurement plan and conducting the storage procurements outlined in this paragraph (2) and in paragraph (3), the Agency may use the services of expert consulting firms identified in paragraphs (1) and (2) of subsection (a) of this Section.

(3) Notwithstanding whether an energy storage system resources procurement plan has been approved, the following provisions shall apply to the Agency's initial procurement of energy storage system resources under this subsection (d-20):

(A) The Agency shall conduct an initial energy storage procurement on or before August 26, 2026 or 90 days after the effective date of this amendatory Act of the 104th General Assembly, whichever is earlier. For the purposes of this initial energy storage procurement, the Agency shall conduct a procurement that results in electric utilities that served more than 300,000 customers in the State as of January 1, 2019 contracting for at least 1,038 megawatts of cost-effective stand-alone energy storage systems that can achieve commercial operation on or before December 31, 2029 or an alternative date proposed by the Agency that is no later than December 31, 2030. The procurement target shall be separated for projects interconnected within Midcontinent Independent System Operator Local Resource Zone 4 (MISO Zone 4) and for projects interconnected within the PJM Interconnection, LLC ComEd Locational Deliverability Area (PJM ComEd Area) as follows:

(i) 450 megawatts in MISO Zone 4; and

(ii) 588 megawatts in the PJM ComEd Area.

For purposes of this subsection (d-20), "stand-alone" means systems that are (i) separately metered by a revenue-quality meter that satisfies the requirements of the RTO; (ii) operate independently without constraints or hindrances from other generation units; and (iii) demonstrate the ability to charge and discharge independent of any generation unit output.

(B) The Agency shall conduct a series of additional energy storage procurements that result in electric utilities contracting for energy storage resources in an amount of 3,000 megawatts of cumulative energy storage capacity for projects committed to reaching commercial operation on or before December 31, 2030, or an alternative date proposed by the Agency, subject to extension for a delay due to interconnection of the energy storage system, a delay in obtaining permits necessary to build or operate the energy storage system, or other circumstances at the discretion of the Agency.

The additional energy storage resources procurements shall be conducted in calendar years 2027 and 2028 in a manner that ensures the quantities listed in this subparagraph (B), and as updated in the integrated resource plan approved by the Commission pursuant to Section 16-201 of the Public Utilities Act, are met in the specified timeframe. To the extent the integrated resource planning process outlined in Section 16-202 of the Public Utilities Act authorizes energy storage system procurement amounts above the amount identified in this subparagraph (B), the Agency shall conduct additional energy storage procurements in 2028, 2029, 2030, and thereafter that result in electric utilities contracting for energy storage resources at those additional identified levels. The procurements shall be conducted in a manner that maximizes projects available in the MISO and PJM queues, ensures the likelihood of project development through the development of project maturity requirements, enables sufficient competition for price competitiveness, and aligns to the extent practicable with regional transmission organization study phases. The procurements shall select projects interconnected to MISO Zone 4 and the PJM ComEd Area and shall follow either (i) a similar geographic split to the ratio of quantities established in subparagraph (A) of this paragraph (3), (ii) an alternative geographic split proposed by the Agency based on project availability in advanced stages of the MISO and PJM queues, or (iii) that is informed by MISO and PJM planning activities, auctions, or reports that indicate capacity resource shortages or impending shortages and that reflect the assessments made through the processes outlined in subparagraph (A) of paragraph (2). The additional energy storage capacity procurements may be adjusted upward if determined necessary through the planning process outlined in Section 16-201 of the Public Utilities Act at times determined by the Commission.

(C) The initial energy storage resources procurement under subparagraph (A) of this paragraph (3) shall adopt a standard indexed storage credit contract modeled after the contract and follow a process modeled after the process included in the staff report submitted to the Governor, General Assembly, and Commission pursuant to subsection (g) of Section 16-135 of the Public Utilities Act on May 1, 2025. In developing the procurement rules and procurement process for the initial procurement, the Agency shall provide an opportunity for comment on the indexed storage credit contract included in the May 1, 2025 staff report and shall adopt modifications to the contract consistent with the process outlined in paragraph (2) of subsection (e) of Section 16-111.5 of the Public Utilities Act.

(D) For the additional energy storage resources procurements conducted in accordance with subparagraph (B) of this paragraph (3), the Agency may, among other considerations, consider other contract structures if such contract structures and agreements do not create contractual obligations on utilities that are not contingent on full and timely cost recovery, avoid negative financial impacts on the utilities, and are agreed upon by the participating utility.

(E) The initial and additional energy storage resources procurements under this paragraph (3) shall solicit 20-year contracts.

(F) The Agency shall submit its proposed selection of successful bids for each procurement event pursuant to paragraphs (2) and (3) to the Commission for approval consistent with the processes outlined in Section 16-111.5 of the Public Utilities Act to the extent practicable.

(4) The energy storage system resources procurement plans developed by the Agency may consider alternatives to the initial and additional procurement terms described in paragraph (3) of this subsection (d-20), including, but not limited to:

(A) alternatives to the standard indexed storage credit contract used in the initial terms described in subparagraph (C) of paragraph (3) of this subsection (d-20);

(B) energy storage systems that are not stand-alone;

(C) proportionate allocations between MISO Zone 4 and the PJM ComEd Area that are not based upon load share, including allocations reflecting the assessments made through the processes outlined in subparagraph (A) of paragraph (2);

(D) contract lengths other than 20 years;

(E) energy storage system durations other than 4 hours; and

(F) energy storage systems connected to the distribution systems of the electric utilities.

The Agency may propose specific timelines for energy storage system resources procurements, which may differ across RTO zones, that are based in part upon a consideration of (i) the timing of the release of interconnection cost information through both MISO and PJM interconnection queue processes, (ii) factors that maximize the likelihood of successful project development, (iii) enabling sufficient competition for price competitiveness, and (iv) aligning to the extent practicable with RTO study phases.

(5) The Agency shall procure cost-effective energy storage credits or other contract instruments intended to facilitate the successful development of energy storage projects. The procurement administrator shall establish confidential price benchmarks based on publicly available data on regional technology costs. Confidential price benchmarks shall be developed by the procurement administrator, in consultation with Commission staff, Agency staff, and the procurement monitor, and shall be subject to Commission review and approval. Price benchmarks shall reflect development costs, financing costs, and related costs resulting from requirements imposed through other provisions of State law. As used in this paragraph (5), "cost-effective" means a bidder's bid price that does not exceed confidential price benchmarks.

(6) All procurements under this subsection (d-20) shall comply with the geographic requirements in subparagraph (I) of paragraph (1) of subsection (c) of Section 1-75 and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. The processes and procedures may be expedited to accommodate the schedule established by this Section. The Agency shall require all bidders to pay to the Agency a nonrefundable deposit determined by the Agency and no less than $10,000 per bid as practical. The Agency may also assess bidder and supplier fees to cover the cost of procurement events and develop collateral requirements to maximize the likelihood of successful project development. Bidders in the initial and additional procurements described in paragraph (3) of this subsection (d-20) shall also demonstrate experience in developing to commercial readiness. As used in this paragraph (6), "developing to commercial readiness" means having notice to proceed in owning or operating energy facilities with a combined nameplate capacity of at least 100 megawatts.

(7) In order to advance priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes, the Agency shall apply its equity accountability system and minimum equity standards established under subsections (c-10), (c-15), (c-20), (c-25), and (c-30) of this Section to energy storage procurement and programs and may include any proposed modifications to the equity accountability system and minimum equity standards that may be warranted with respect to energy storage resources in its plan submission to the Commission under Section 16-111.5 of the Public Utilities Act.

(8) Projects shall be developed in compliance with the prevailing wage and project labor agreement requirements for renewable energy projects in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75.

(9) An entity operating an energy storage facility shall demonstrate that it has entered into a labor peace agreement with a bona fide labor organization that is actively engaged in representing its employees. The labor peace agreement shall apply to the employees necessary for the ongoing maintenance and operation of the energy storage facility. The existence of a labor peace agreement shall be an ongoing material condition of an entity's authorization to maintain and operate the energy storage facility.

(10) In order to promote the competitive development of energy storage systems in furtherance of the State's interest in the health, safety, and welfare of its residents, storage credits shall not be eligible to be selected under this subsection (d-20) if the energy storage resources are sourced from an energy storage system whose costs were being recovered through rates regulated by the State or any other state or states on or after January 1, 2017. No entity shall be permitted to bid unless it certifies to the Agency that it is not an electric utility, as defined in Section 16-102 of the Public Utilities Act, serving more than 10,000 customers in the State.

(11) The Agency shall require, as a prerequisite to payment for any storage credits, that the winning bidder provide the Agency or its designee a copy of the interconnection agreement under which the applicable energy storage system is connected to the transmission or distribution system.

(12) Contracts shall provide that, if the cost recovery mechanism referenced in subsection (k) of Section 16-108 of the Public Utilities Act remains in full force without amendment or the utility is otherwise authorized or entitled to full, prompt, and uninterrupted recovery of its costs through any other mechanism, then such seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this paragraph (12).

(e) The draft procurement plans are subject to public comment, as required by Section 16-111.5 of the Public Utilities Act.

(f) The Agency shall submit the final procurement plan to the Commission. The Agency shall revise a procurement plan if the Commission determines that it does not meet the standards set forth in Section 16-111.5 of the Public Utilities Act.

(g) The Agency shall assess fees to each affected utility to recover the costs incurred in preparation of procurement plans and in the operation of programs.

(h) The Agency shall assess fees to each bidder to recover the costs incurred in connection with a competitive procurement process.

(i) A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit can only be used once to comply with a single portfolio or other standard as set forth in subsection (c), subsection (d), or subsection (d-5) of this Section, respectively. A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit cannot be used to satisfy the requirements of more than one standard. If more than one type of credit is issued for the same megawatt hour of energy, only one credit can be used to satisfy the requirements of a single standard. After such use, the credit must be retired together with any other credits issued for the same megawatt hour of energy.

(Source: P.A. 103-380, eff. 1-1-24; 103-580, eff. 12-8-23; 103-1066, eff. 2-20-25; 104-458, eff. 6-1-26.)

Section 25. The Public Utilities Act is amended by changing Sections 8-103B, 16-107.5, 16-107.6, 16-107.9, 16-202, 20-140, and 23-115 as follows:

(220 ILCS 5/8-103B)

(Text of Section before amendment by P.A. 104-458)

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, 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;

(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, 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;

(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, 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;

(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 0.6 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 0.4 percentage point annual increases in total cumulative persisting annual savings. The Commission may only establish goals that represent less than 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 0.4 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-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 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).

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. 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, public institutions of higher education, 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 $40,000,000 per year for electric utilities that serve more than 3,000,000 retail customers in the State and no less than $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 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 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 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), 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) 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) 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 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 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 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):

(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

(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) 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) 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 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) 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) 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; 103-613, eff. 7-1-24.)

(Text of Section after amendment by P.A. 104-458)

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 2026, 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;

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

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

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 and through calendar year 2026, 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;

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

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

(b-10) For purposes of this Section, through calendar year 2026, 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;

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

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

(b-15) Beginning in 2018 and through calendar year 2026, 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; and

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

(b-16) In 2027 and each year thereafter, each electric utility subject to this Section shall achieve the following savings goals:

(1) A utility that serves more than 3,000,000 retail customers in the State must achieve incremental annual energy savings for customers in an amount that is equal to 2% of the utility's average annual electricity sales from 2021 through 2023 to customers 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. A utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State must achieve incremental annual energy savings for customers in an amount that is equal to 1.4% in 2027, 1.7% in 2028, and 2% in 2029 and every year thereafter of the utility's average annual electricity sales from 2021 through 2023 to customers 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. The incremental annual energy savings requirements set forth in this paragraph (1) may be reduced by 0.025 percentage points for every percentage point increase, above the 25% minimum to be targeted at low-income households as specified in paragraph (c) of this Section, in the portion of total efficiency program spending that is on low-income or moderate-income efficiency programs. The incremental annual energy savings requirement shall not be reduced to a level less than 0.25 percentage points less than the energy savings requirement applicable to the calendar year, even if the sum of low-income spending and moderate-income spending is greater than 35% of total spending.

(2) A utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State must achieve an incremental annual coincident peak demand savings goal from energy efficiency measures installed as a result of the utility's programs by customers in an amount that is equal to the energy savings goal from paragraph (1) of this Section divided by the actual average ratio of kilowatt-hour savings to coincident peak demand reduction achieved by the utility through its energy efficiency programs in 2023. If the season in which coincident peak demands are experienced, the hours of the day that peak demands are experienced, and the methods by which peak demand impacts from efficiency measures are estimated are different in the future than when 2023 peak demand impacts were originally estimated, the 2023 peak demand impacts shall be recomputed using such updated peak definitions and estimation methods for the purpose of establishing future coincident peak demand savings goals. To the extent that a utility counts either improvements to the efficiency of the use of gas and other fuels or the electrification of gas and other fuels toward its energy savings goal, as permitted under paragraphs (b-25) and (b-27) of this Section, it must estimate the actual impacts on coincident peak demand from such measures and count them, whether positive or negative, toward its coincident peak demand savings goal. Only coincident peak demand savings from efficiency measures shall count toward this goal. To the extent that some efficiency measures enable demand response, only the peak demand savings from the energy efficiency upgrade shall count toward the goal. Nothing in this Section shall limit the ability of peak demand savings from such enabled demand-response initiatives to count for other, non-energy efficiency performance standard performance metrics established for the utility.

(3) Each utility's incremental annual energy savings, and coincident peak demand savings if a utility serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, must be achieved with an average savings life of at least 12 years. In no event can more than one-fifth of the incremental annual energy savings or the coincident peak demand savings counted toward a utility's annual savings goal in any given year be derived from efficiency measures with average savings lives of less than 5 years. Average savings lives may be shorter than the average operational lives of measures installed if the measures do not produce savings in every year in which the measures operate or if the savings that measures produce decline during the measures' operational lives.

For the purposes of this Section, "incremental annual energy savings" means the total electric energy savings from all measures installed in a calendar year that will be realized within 12 months of each measure's installation; "moderate-income" means (i) for an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, income between 80% of area median income and 300% of the federal poverty limit and (ii) for an electric utility that serves more than 3,000,000 retail customers in the State, income between 80% of area median income and 100% of area median income; "incremental annual coincident peak demand savings" means the total coincident peak reduction from all energy efficiency measures installed in a calendar year that will be realized within 12 months of each measure's installation; "average savings life" means the lifetime energy or coincident peak demand savings that would be realized as a result of a utility's efficiency programs divided by the incremental annual energy or coincident peak demand savings such programs produce.

(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.

For an electric utility that serves more than 3,000,000 retail customers in the State, on and after January 1, 2027, the electric utility may only count savings of other fuels under this subsection (b-25) toward the achievement of its annual electric energy savings goal when such other fuel savings are from weatherization measures that reduce heat loss through the building envelope, insulating mechanical systems, or the heating distribution system, including, but not limited to, air sealing and building shell measures. This limitation on counting other fuel savings from efficiency measures toward a utility's energy savings goal shall not affect the utility's ability to claim savings from electrification measures installed pursuant to the requirements in subsection (b-27).

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 be met through savings of fuels other than electricity. For an electric utility that serves more than 3,000,000 retail customers in the State, in no event shall more than 30% of each year's incremental annual energy savings requirement, as defined in subsection (b-16) of this Section, be met through savings of fuels other than electricity. For an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, in no event shall more than 20% of each year's incremental annual energy savings requirement, as defined in subsection (b-16) of this Section, 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 33% of all costs of offering and promoting electrification measures under this subsection (b-27) must be for supporting installation of electrification measures through programs exclusively targeted to low-income households. The percentage requirement may be reduced if the utility can demonstrate that it is not possible to achieve the level of low-income electrification spending, while supporting programs for non-low-income residential and business electrification, because of limitations regarding the number of low-income households in its service territory that would be able to meet program eligibility requirements set forth in the multi-year energy efficiency plan. If the 33% low-income electrification spending requirement is reduced, the utility must prioritize support of low-income electrification in housing that meets program eligibility requirements over electrification spending on non-low-income residential or business customers.

The ratio of spending on electrification measures targeted to low-income, multifamily buildings to spending on electrification measures targeted to low-income, single-family buildings shall be designed to achieve levels of electrification savings from each building type that are approximately proportional to the magnitude of cost-effective electrification savings potential in each building type.

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, or counted toward each year's incremental annual energy savings, as defined in paragraph (b-16) of this Section, be greater than:

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

(2) 20% per year for 2026 and all subsequent years; and

(3) (blank). 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 counted toward each year's incremental annual energy savings, as defined in paragraph (b-16) of this Section. Prior to installing or promoting electrification measures, the utility shall provide customers with estimates of the impact of the new measures 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, public institutions of higher education, 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 25% of total energy efficiency program spending approved by the Commission pursuant to review of plans filed under subsection (f) of this Section 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. For a utility that serves more than 3,000,000 retail customers in the State, if a facilitator is used, they shall be retained by Commission staff.

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 that shall be equal to the baseline cost of equity approved by the Commission for the utility's electric distribution rates effective during the applicable year, whether those rates are set pursuant to Section 9-201, subparagraph (B) of paragraph (3) of subsection (d) of Section 16-108.18, or any successor electric distribution ratemaking paradigm.

(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 determined as set forth in subparagraph (C) of paragraph (2) of subsection of this Section, 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.

(2.5) Provisions of the multi-year plans for calendar years 2026 through 2029 that relate to calendar year 2026 and that were filed by the electric utilities on February 28, 2025 shall remain in effect through calendar year 2026. Provisions of the plans for calendar years 2027 through 2029 shall be modified and resubmitted to the Commission by the electric utilities pursuant to paragraph (3) of this subsection (f).

(3) No later than the effective date of this amendatory Act of the 104th General Assembly, each electric utility shall file a 3-year energy efficiency plan commencing on January 1, 2027 that is designed to achieve, through implementation of energy efficiency measures, lifetime energy savings equal to the product of the incremental annual energy savings goals defined by paragraph (1) of subsection (b-16) and the minimum average savings life defined by paragraph (3) of subsection (b-16). The 3-year energy efficiency plan of a utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State must also be designed to achieve lifetime peak demand savings equal to the product of the incremental annual peak demand savings goals defined by paragraph (2) of subsection (b-16) and the minimum average savings life defined by paragraph (3) of subsection (b-16) through implementation of energy efficiency measures. The savings goals may be reduced if: (i) clear and convincing evidence and independent analysis demonstrates that the expenditure limits in subsection (m) of this Section preclude full achievement of the goals, (ii) each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings 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 multi-year plan period, or (iii) changes in federal law, programs, or tariffs have a significant and demonstrable impact on the cost of delivering measures and programs. If there is not clear and convincing evidence that achieving the savings goals specified in subsection (b-16) is not 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), annual savings goals during the applicable multi-year plan period shall not be reduced to amounts that are less than the maximum amount of annual savings that is forecasted to be cost-effectively achievable during the applicable multi-year plan period. The Commission shall review any proposed goal reduction as 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, through implementation of energy efficiency measures, lifetime energy savings equal to the product of the incremental annual energy savings goals defined by paragraph (1) of subsection (b-16) and the minimum average savings life described in paragraph (3) (C) of subsection (b-16) of this Section. The multi-year energy efficiency plan of a utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State must also be designed to achieve lifetime peak demand savings equal to the product of the incremental annual peak demand savings goals defined by paragraph (2) of subsection (b-16) and the minimum average savings life defined by paragraph (3) of subsection (b-16) through implementation of energy efficiency measures. However, the goals may be reduced if: (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; (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 multi-year plan period; or (3) changes in federal law, programs, or tariffs have a significant and demonstrable impact on the cost of delivering measures and programs. If there is not clear and convincing evidence that achieving the savings goals specified in subsection paragraph (b-16) 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 savings goals during the applicable multi-year plan period shall not be reduced to amounts that are less than the maximum amount of annual savings that is forecast to be cost-effectively achievable during the applicable multi-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), (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), (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), (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) If the utility chooses, present a third-party energy efficiency implementation program subject to the following requirements:

(A) (blank);

(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 3,000,000 retail customers in the State:

(A) Through December 31, 2026, 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) (Blank).

(C) (Blank).

(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) 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) 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, 2026, 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) (Blank).

(C) (Blank).

(D) (Blank).

(8.5) Beginning January 1, 2027, a utility that serves greater than 500,000 retail customers in the State shall have the utility's return on equity modified for performance on the utility's energy savings and peak demand savings goals as follows:

(A) The return on equity for a utility that serves more than 3,000,000 retail customers in the State may be adjusted up or down by a maximum of 200 basis points for its performance relative to the product of its incremental annual energy savings goal and average energy savings life. The return on equity for a utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State may be adjusted up or down by a maximum of 100 basis points for its performance relative to the product of its incremental annual energy savings goal and average energy savings life and a maximum of 100 basis points for its performance relative to the product of its incremental annual coincident peak demand savings goal and average peak demand savings life.

(B) A utility's performance on its savings goals shall be established by comparing the actual lifetime energy savings, and the actual lifetime coincident peak demand savings if a utility serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, achieved from efficiency measures installed in a given year to the product of the incremental annual goals established in paragraphs (1) and (2) of subsection (b-16) and the minimum average savings lives established in paragraph (3) of subsection (b-16), as modified, if applicable, by the Commission under paragraph (4) of subsection (f) of this Section. For the purposes of this paragraph (8.5), "lifetime energy savings" means the total incremental savings that installed efficiency measures are projected to produce, relative to what would have occurred absent to the utility's efficiency programs, over the useful lives of the measures. Performance on the energy savings goal, and coincident peak demand savings if a utility serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, shall be assessed separately, such that it is possible to earn penalties on both, earn bonuses on both, or earn a bonus for performance on one goal and a penalty on the other.

(C) No bonus shall be earned if a utility does not achieve greater than 100% of an approved goal. The maximum bonus for a goal shall be earned if the utility achieves 125% of the unmodified goal. For a utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, the bonus earned for achieving more than 100% of an approved goal but less than 125% of the unmodified goal shall be linearly interpolated. For a utility with more than 3,000,000 retail customers, the maximum bonus for a goal shall be earned if the utility achieves 125% of the unmodified goal. For a utility with more than 3,000,000 retail customers, the bonus earned for achieving more than 100% of an approved goal but less than 125% of the unmodified goal shall be linearly interpolated.

(D) For utilities with greater than 3,000,000 retail customers, the return on equity shall be unmodified due to performance on an individual goal only if the utility achieves exactly 100% of the goal. For utilities with more than 500,000 but fewer than 3,000,000 retail customers, the return on equity shall be unmodified for achieving between 85% and 100% of the goal.

(E) Penalties may be earned for falling short of goals, with the magnitude of any penalty being a function of both the size of the utility and whether goals established in subsection (b-16) are modified by the Commission under paragraph (4) of subsection (f) of this Section, as follows:

(i) If the savings goals specified in subsection (b-16) of this Section are unmodified, a utility with more than 3,000,000 retail customers shall earn the maximum penalty allocated to a goal for achieving 75% or less of the goal. The penalty for achieving greater than 75% but less than 100% of the goal shall be linearly interpolated.

(ii) If the savings goals specified in subsection (b-16) of this Section are unmodified, a utility with more than 500,000 but fewer than 3,000,000 retail customers shall earn the maximum penalty allocated to a goal for achieving at least 33.3 percentage points less than the bottom end of the deadband specified in subparagraph (D) of this paragraph (8.5). The penalty for achieving less than the bottom end of the deadband and greater than 33.3 percentage points less than the bottom end of the deadband shall be linearly interpolated.

(iii) If either the energy or peak demand savings goals specified in subsection (b-16) are reduced under paragraph (3) or (4) of subsection (f) of this Section, the maximum penalty allocated to a goal shall be earned if the utility achieves 80% or less of the modified goal. The penalty for achieving more than 80% but less than 100% of a modified goal shall be linearly interpolated.

(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 and annual incremental 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 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. For all construction, installation, or other related services procured under this Section, an electric utility must:

(A) award a bid preference of 2% to a contractor if the contractor certifies under oath that the contractor's primary place of business is located within the utility's service area; and

(B) award a bid preference of 2% to a contractor if the contractor certifies under oath that at least 85% of the workforce to be utilized for such construction, installation, or other related services reside in the utility's service area.

(9.6) Utilities shall collect data necessary to ensure compliance with paragraph (9.5) no less than quarterly and shall communicate progress toward compliance with 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), (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) and the proportion of total program dollars awarded to firms that meet the criteria of subparagraphs (A) and (B) of paragraph (9.5). 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) 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,

(3.5) 4.25% for 2026,

(4) 4.25% for electric utilities that serve more than 3,000,000 retail customers in the State, and 4.21% for 2027, 5.25% for 2028, and 6.06% for 2029 for electric utilities with less than 3,000,000 retail customers but more than 500,000 retail customers in the State, for the 3 years beginning January 1, 2027, and

(5) the percentage specified in paragraph (4) applicable to 2029 plus an increase sufficient to account for the rate of inflation between January 1, 2027 and January 1 of the first year of each subsequent 4-year plan cycle, of the average amount paid per kilowatthour by residential eligible retail customers during calendar year 2015 for plans in effect through 2026 and during calendar year 2023 for plans commencing in 2027 and thereafter. An electric utility may plan to spend up to 10% more in any year during an applicable multi-year plan period, including any transition period authorized under paragraph (2.5) of subsection (f), to cost-effectively achieve additional savings so long as the average over the applicable multi-year plan period, which shall include any transition 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 (i) the total amount of energy delivered by such electric utility in the calendar year 2015 for plans in effect through 2026, (ii) for an electric utility that serves more than 3,000,000 retail customers in the State, the average amount of energy delivered by such electric utility in calendar years 2021 through 2023 for plans commencing in 2027 and thereafter, and (iii) for an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, the total amount of energy delivered by such electric utility in the calendar year 2023 and during calendar year 2023 for plans commencing in 2027 and thereafter, adjusted to reflect the proportion of the utility's load attributable to customers that have opted out of subsections (a) through (j) of this Section under subsection (l) of this Section. 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. 103-154, eff. 6-30-23; 103-613, eff. 7-1-24; 104-458, eff. 6-1-26.)

(220 ILCS 5/16-107.5)

(Text of Section before amendment by P.A. 104-458)

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.

(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.)

(Text of Section after amendment by P.A. 104-458)

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 and storage 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 or an eligible storage device 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 colocation 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.

(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.

(x) "Vehicle storage system" means a vehicle that when connected to an electric utility's distribution system is capable of being an energy storage system, as defined in Section 16-107.6.

(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.

(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 1% of the subscription fee. 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. An electric utility shall use the same net crediting format for subscribers on payment plans and subscribers participating in budget billing programs. For the purposes of this paragraph (4), "net crediting" means a program offered by an electric utility under which the electric utility, upon authorization by or on behalf of a subscriber, remits the cash value of the subscription fee to the owner or operator of the community renewable generation facility without regard to whether the subscriber has paid the subscriber's monthly electric bill and places the cash value of the remaining bill credit on the subscriber's bill.

(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.

(l-10) Within 30 days after the effective date of this amendatory Act of the 104th General Assembly, each electricity provider shall modify its tariffs to allow net metering as set forth in this subsection for an energy storage system or vehicle storage system energized after the effective date of this amendatory Act of the 104th General Assembly with a nameplate capacity of not more than 5,000 kilowatts. If the Commission chooses to suspend the modified tariffs, the Commission shall issue a final order approving, or approving with modification, the modified tariffs no later than 90 days after the Commission initiates the docket.

An energy storage system or vehicle storage system eligible for net metering under this subsection may be interconnected behind the meter of a retail customer or at the distribution system level of an electric utility as follows:

(A) if the energy storage system or vehicle storage system is interconnected behind the meter of a retail customer, in order to receive net metering under this subsection, the eligible customer behind whose meter the energy storage system is interconnected must receive service from an electricity provider under an hourly supply tariff, a time-of-use supply tariff, or a time-of-use contract with an alternative retail electric supplier; or

(B) if the energy storage system or vehicle storage system is interconnected at the distribution system level of an electric utility and not behind the meter of a retail customer, the energy storage system or vehicle storage system must receive service from an electricity provider as a retail customer under an hourly supply tariff authorized by Section 16-107, a supply tariff or contract on substantially similar terms and conditions with an alternative retail electric supplier, a time-of-use supply tariff, or a time-of-use supply contract with an alternative retail electric supplier.

If the energy storage system or vehicle storage system is interconnected behind the meter of an eligible customer, the eligible customer shall receive net metering based on hourly or time-of-use rates in accordance with the terms of subsection (d-5) or (f) or paragraph (2) of subsection (n) of this Section, as applicable to the eligible customer. If the energy storage system or vehicle storage system is interconnected at the distribution system level of an electric utility and not behind the meter of a retail customer, then the energy storage system or vehicle storage system shall receive net metering pursuant to the terms of subsection (f) of this Section.

(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 or time-of-use 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. 104-458, eff. 6-1-26.)

(220 ILCS 5/16-107.6)

(Text of Section before amendment by P.A. 104-458)

Sec. 16-107.6. Distributed generation rebate.

(a) In this Section:

"Additive services" means the services that distributed energy resources provide to the energy system and society that are not (1) already included in the base rebates for system-wide grid services; or (2) otherwise already compensated. Additive services may reflect, but shall not be limited to, any geographic, time-based, performance-based, and other benefits of distributed energy resources, as well as the present and future technological capabilities of distributed energy resources and present and future grid needs.

"Distributed energy resource" means a wide range of technologies that are located on the customer side of the customer's electric meter, including, but not limited to, distributed generation, energy storage, electric vehicles, and demand response technologies.

"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.

"Smart inverter" means a device that converts direct current into alternating current and meets the IEEE 1547-2018 equipment standards. Until devices that meet the IEEE 1547-2018 standard are available, devices that meet the UL 1741 SA standard are acceptable.

"Subscriber" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act.

"Subscription" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act.

"System-wide grid services" means the benefits that a distributed energy resource provides to the distribution grid for a period of no less than 25 years. System-wide grid services do not vary by location, time, or the performance characteristics of the distributed energy resource. System-wide grid services include, but are not limited to, avoided or deferred distribution capacity costs, resilience and reliability benefits, avoided or deferred distribution operation and maintenance costs, distribution voltage and power quality benefits, and line loss reductions.

"Threshold date" means December 31, 2024 or the date on which the utility's tariff or tariffs setting the new compensation values established under subsection (e) take effect, whichever is later.

(b) An electric utility that serves more than 200,000 customers in the State shall file a petition with the Commission requesting approval of the utility's tariff to provide a rebate to the owner or operator of distributed generation, including third-party owned systems, that meets the following criteria:

(1) has a nameplate generating capacity no greater than 5,000 kilowatts and is primarily used to offset a customer's electricity load;

(2) is located on the customer's side of the billing meter and for the customer's own use;

(3) is interconnected to electric distribution facilities owned by the electric utility under rules adopted by the Commission by means of one or more inverters or smart inverters required by this Section, as applicable.

For purposes of this Section, "distributed generation" shall satisfy the definition of distributed renewable energy generation device set forth in Section 1-10 of the Illinois Power Agency Act to the extent such definition is consistent with the requirements of this Section.

In addition, any new photovoltaic distributed generation that is installed after June 1, 2017 (the effective date of Public Act 99-906) must be installed by a qualified person, as defined by subsection (i) of Section 1-56 of the Illinois Power Agency Act.

The tariff shall include a base rebate that compensates distributed generation for the system-wide grid services associated with distributed generation and, after the proceeding described in subsection (e) of this Section, an additional payment or payments for the additive services. The tariff shall provide that the smart inverter or smart inverters associated with the distributed generation shall provide autonomous response to grid conditions through its default settings as approved by the Commission. Default settings may not be changed after the execution of the interconnection agreement except by mutual agreement between the utility and the owner or operator of the distributed generation. Nothing in this Section shall negate or supersede Institute of Electrical and Electronics Engineers equipment standards or other similar standards or requirements. The tariff shall not limit the ability of the smart inverter or smart inverters or other distributed energy resource to provide wholesale market products such as regulation, demand response, or other services, or limit the ability of the owner of the smart inverter or the other distributed energy resource to receive compensation for providing those wholesale market products or services.

(b-5) Within 30 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric public utility with 3,000,000 or more retail customers shall file a tariff with the Commission that further compensates any retail customer that installs or has installed photovoltaic facilities paired with energy storage facilities on or adjacent to its premises for the benefits the facilities provide to the distribution grid. The tariff shall provide that, in addition to the other rebates identified in this Section, the electric utility shall rebate to such retail customer (i) the previously incurred and future costs of installing interconnection facilities and related infrastructure to enable full participation in the PJM Interconnection, LLC or its successor organization frequency regulation market; and (ii) all wholesale demand charges incurred after the effective date of this amendatory Act of the 102nd General Assembly. The Commission shall approve, or approve with modification, the tariff within 120 days after the utility's filing.

(c) The proposed tariff authorized by subsection (b) of this Section shall include the following participation terms for rebates to be applied under this Section for distributed generation that satisfies the criteria set forth in subsection (b) of this Section:

(1) The owner or operator of distributed generation that services customers not eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act may apply for a rebate as provided for in this Section. Until the threshold date, the value of the rebate shall be $250 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of that customer's distributed generation. To the extent the distributed generation also has an associated energy storage, then the energy storage system shall be separately compensated with a base rebate of $250 per kilowatt-hour of nameplate capacity. Any distributed generation device that is compensated for storage in this subsection (1) before the threshold date shall participate in one or more programs determined through the Multi-Year Integrated Grid Planning process that are designed to meet peak reduction and flexibility. After the threshold date, the value of the base rebate and additional compensation for any additive services shall be as determined by the Commission in the proceeding described in subsection (e) of this Section, provided that the value of the base rebate for system-wide grid services shall not be lower than $250 per kilowatt of nameplate generating capacity of distributed generation or community renewable generation project.

(2) The owner or operator of distributed generation that, before the threshold date, would have been eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act and that has not previously received a distributed generation rebate, may apply for a rebate as provided for in this Section. Until the threshold date, the value of the base rebate shall be $300 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of the distributed generation. The owner or operator of distributed generation that, before the threshold date, is eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act may apply for a base rebate for an associated energy storage device behind the same retail customer meter as the distributed generation, regardless of whether the distributed generation applies for a rebate for the distributed generation device. The energy storage system shall be separately compensated at a base payment of $300 per kilowatt-hour of nameplate capacity. Any distributed generation device that is compensated for storage in this subsection (2) before the threshold date shall participate in a peak time rebate program, hourly pricing program, or time-of-use rate program offered by the applicable electric utility. After the threshold date, the value of the base rebate and additional compensation for any additive services shall be as determined by the Commission in the proceeding described in subsection (e) of this Section, provided that, prior to December 31, 2029, the value of the base rebate for system-wide services shall not be lower than $300 per kilowatt of nameplate generating capacity of distributed generation, after which it shall not be lower than $250 per kilowatt of nameplate capacity. The eligibility of energy storage devices that are interconnected behind the same retail customer meter as the distributed generation shall not be limited to energy storage devices interconnected after the effective date of this amendatory Act of the 103rd General Assembly. To the extent that an electric utility's tariffs are inconsistent with the requirements of this paragraph (2) as modified by this amendatory Act of the 103rd General Assembly, such electric utility shall, within 30 days, file modified tariffs consistent with the requirements of this paragraph (2).

(3) Upon approval of a rebate application submitted under this subsection (c), the retail customer shall no longer be entitled to receive any delivery service credits for the excess electricity generated by its facility and shall be subject to the provisions of subsection (n) of Section 16-107.5 of this Act unless the owner or operator receives a rebate only for an energy storage device and not for the distributed generation device.

(4) To be eligible for a rebate described in this subsection (c), the owner or operator of the distributed generation must have a smart inverter installed and in operation on the distributed generation.

(d) The Commission shall review the proposed tariff authorized by subsection (b) of this Section and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff. Upon the effective date of this amendatory Act of the 102nd General Assembly, an electric utility shall file a petition with the Commission to amend and update any existing tariffs to comply with subsections (b) and (c).

(e) By no later than June 30, 2023, the Commission shall open an independent, statewide investigation into the value of, and compensation for, distributed energy resources. The Commission shall conduct the investigation, but may arrange for experts or consultants independent of the utilities and selected by the Commission to assist with the investigation. The cost of the investigation shall be shared by the utilities filing tariffs under subsection (b) of this Section but may be recovered as an expense through normal ratemaking procedures.

(1) The Commission shall ensure that the investigation includes, at minimum, diverse sets of stakeholders; a review of best practices in calculating the value of distributed energy resource benefits; a review of the full value of the distributed energy resources and the manner in which each component of that value is or is not otherwise compensated; and assessments of how the value of distributed energy resources may evolve based on the present and future technological capabilities of distributed energy resources and based on present and future grid needs.

(2) The Commission's final order concluding this investigation shall establish an annual process and formula for the compensation of distributed generation and energy storage systems, and an initial set of inputs for that formula. The Commission's final order concluding this investigation shall establish base rebates that compensate distributed generation, community renewable generation projects and energy storage systems for the system-wide grid services that they provide. Those base rebate values shall be consistent across the state, and shall not vary by customer, customer class, customer location, or any other variable. With respect to rebates for distributed generation or community renewable generation projects, that rebate shall not be lower than $250 per kilowatt of nameplate generating capacity of the distributed generation or community renewable generation project. The Commission's final order concluding this proceeding shall also direct the utilities to update the formula, on an annual basis, with inputs derived from their integrated grid plans developed pursuant to Section 16-105.17. The base rebate shall be updated annually based on the annual updates to the formula inputs, but, with respect to rebates for distributed generation or community renewable generation projects, shall be no lower than $250 per kilowatt of nameplate generating capacity of the distributed generation or community renewable generation project.

(3) The Commission shall also determine, as a part of its investigation under this subsection, whether distributed energy resources can provide any additive services. Those additive services may include services that are provided through utility-controlled responses to grid conditions. If the Commission determines that distributed energy resources can provide additive grid services, the Commission shall determine the terms and conditions for the operation and compensation of those services. That compensation shall be above and beyond the base rebate that the distributed energy generation, community renewable generation project and energy storage system receives. Compensation for additive services may vary by location, time, performance characteristics, technology types, or other variables.

(4) The Commission shall ensure that compensation for distributed energy resources, including base rebates and any payments for additive services, shall reflect all reasonably known and measurable values of the distributed generation over its full expected useful life. Compensation for additive services shall reflect, but shall not be limited to, any geographic, time-based, performance-based, and other benefits of distributed generation, as well as the present and future technological capabilities of distributed energy resources and present and future grid needs.

(5) The Commission shall consider the electric utility's integrated grid plan developed pursuant to Section 16-105.17 of this Act to help identify the value of distributed energy resources for the purpose of calculating the compensation described in this subsection.

(6) The Commission shall determine additional compensation for distributed energy resources that creates savings and value on the distribution system by being co-located or in close proximity to electric vehicle charging infrastructure in use by medium-duty and heavy-duty vehicles, primarily serving environmental justice communities, as outlined in the utility integrated grid planning process under Section 16-105.17 of this Act.

No later than 60 days after the Commission enters its final order under this subsection (e), each utility shall file its updated tariff or tariffs in compliance with the order, including new tariffs for the recovery of costs incurred under this subsection (e) that shall provide for volumetric-based cost recovery, and the Commission shall approve, or approve with modification, the tariff or tariffs within 240 days after the utility's filing.

(f) Notwithstanding any provision of this Act to the contrary, the owner or operator of a community renewable generation project as defined in Section 1-10 of the Illinois Power Agency Act shall also be eligible to apply for the rebate described in this Section. The owner or operator of the community renewable generation project may apply for a rebate only if the owner or operator, or previous owner or operator, of the community renewable generation project has not already submitted an application, and, regardless of whether the subscriber is a residential or non-residential customer, may be allowed the amount identified in paragraph (1) of subsection (c) applicable on the date that the application is submitted.

(g) The owner of the distributed generation or community renewable generation project may apply for the rebate or rebates approved under this Section at the time of execution of an interconnection agreement with the distribution utility and shall receive the value available at that time of execution of the interconnection agreement, provided the project reaches mechanical completion within 24 months after execution of the interconnection agreement. If the project has not reached mechanical completion within 24 months after execution, the owner may reapply for the rebate or rebates approved under this Section available at the time of application and shall receive the value available at the time of application. The utility shall issue the rebate no later than 60 days after the project is energized. In the event the application is incomplete or the utility is otherwise unable to calculate the payment based on the information provided by the owner, the utility shall issue the payment no later than 60 days after the application is complete or all requested information is received.

(h) An electric utility shall recover from its retail customers all of the costs of the rebates made under a tariff or tariffs approved under subsection (d) of this Section, including, but not limited to, the value of the rebates and all costs incurred by the utility to comply with and implement subsections (b) and (c) of this Section, but not including costs incurred by the utility to comply with and implement subsection (e) of this Section, consistent with the following provisions:

(1) The utility shall defer the full amount of its costs as a regulatory asset. The total costs deferred as a regulatory asset shall be amortized over a 15-year period. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the unamortized balance of the regulatory assets, less any deferred taxes related to the unamortized balance, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end 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 (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.

When an electric utility creates a regulatory asset under the provisions of this paragraph (1) of subsection (h), 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 paragraph (1) shall recover all of the associated costs, including, but not limited to, its cost of capital as set forth in this paragraph (1). 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. 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) The utility, at its election, may recover all of the costs as part of a filing for a general increase in rates under Article IX of this Act, as part of an annual filing to update a performance-based formula rate under subsection (d) of Section 16-108.5 of this Act, or through an automatic adjustment clause tariff, provided that nothing in this paragraph (2) permits the double recovery of such costs from customers. If the utility elects to recover the costs it incurs under subsections (b) and (c) through an automatic adjustment clause tariff, the utility may file its proposed tariff together with the tariff it files under subsection (b) of this Section or at a later time. The proposed tariff shall provide for an annual reconciliation, 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 as calculated under paragraph (1) of this subsection (h), 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 revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its automatic adjustment clause tariff under this subsection (h), 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 Commission shall review the proposed tariff and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff.

(i) An electric utility shall recover from its retail customers, on a volumetric basis, all of the costs of the rebates made under a tariff or tariffs placed into effect under subsection (e) of this Section, including, but not limited to, the value of the rebates and all costs incurred by the utility to comply with and implement subsection (e) of this Section, consistent with the following provisions:

(1) The utility may defer a portion of its costs as a regulatory asset. The Commission shall determine the portion that may be appropriately deferred as a regulatory asset. Factors that the Commission shall consider in determining the portion of costs that shall be deferred as a regulatory asset include, but are not limited to: (i) whether and the extent to which a cost effectively deferred or avoided other distribution system operating costs or capital expenditures; (ii) the extent to which a cost provides environmental benefits; (iii) the extent to which a cost improves system reliability or resilience; (iv) the electric utility's distribution system plan developed pursuant to Section 16-105.17 of this Act; (v) the extent to which a cost advances equity principles; and (vi) such other factors as the Commission deems appropriate. The remainder of costs shall be deemed an operating expense and shall be recoverable if found prudent and reasonable by the Commission.

The total costs deferred as a regulatory asset shall be amortized over a 15-year period. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the unamortized balance of the regulatory assets, less any deferred taxes related to the unamortized balance, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end 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: (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.

(2) The utility may recover all of the costs through an automatic adjustment clause tariff, on a volumetric basis. The utility may file its proposed cost-recovery tariff together with the tariff it files under subsection (e) of this Section or at a later time. The proposed tariff shall provide for an annual reconciliation, 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 as calculated under paragraph (1) of this subsection (i), 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 revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its automatic adjustment clause tariff under this subsection (i), 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 Commission shall review the proposed tariff and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff.

(j) No later than 90 days after the Commission enters an order, or order on rehearing, whichever is later, approving an electric utility's proposed tariff under this Section, the electric utility shall provide notice of the availability of rebates under this Section.

(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22; 103-1066, eff. 2-20-25.)

(Text of Section after amendment by P.A. 104-458)

Sec. 16-107.6. Distributed generation and storage rebate.

(a) In this Section:

"Additive services" means the services that distributed energy resources provide to the energy system and society that are described in Section 16-107.9.

"Distributed energy resource" means a wide range of technologies that are located on the customer side of the customer's electric meter, including, but not limited to, distributed generation, energy storage, electric vehicles, and demand response technologies.

"Distributed storage" means energy storage systems that are interconnected behind the customer's meter to the distribution system or interconnected behind the storage system's own meter to the distribution system and that are permanently fixed to the distribution grid and capable of discharging to the distribution grid. "Distributed storage" does not include vehicle storage systems.

"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, that and may be interconnected behind the customer's meter or interconnected behind its own meter, and that is permanently fixed to the distribution grid and capable of discharging to the distribution grid.

"Smart inverter" means a device that converts direct current into alternating current and meets the IEEE 1547-2018 equipment standards. Until devices that meet the IEEE 1547-2018 standard are available, devices that meet the UL 1741 SA standard are acceptable.

"Stand-alone energy storage system" means distributed storage that is not paired with distributed generation.

"Subscriber" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act.

"Subscription" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act.

"System-wide grid services" means the benefits that a distributed energy resource provides to the distribution grid for a period of no less than 25 years. System-wide grid services do not vary by location, time, or the performance characteristics of the distributed energy resource. System-wide grid services include, but are not limited to, avoided or deferred distribution capacity costs, resilience and reliability benefits, avoided or deferred distribution operation and maintenance costs, distribution voltage and power quality benefits, and line loss reductions.

"Threshold date" means the date 2 years after the effective date of this amendatory Act of the 104th General Assembly or the date on which the utility's tariff or tariffs authorized by Section 16-107.9 take effect, whichever is later.

(b) An electric utility that serves more than 200,000 customers in the State shall file a petition with the Commission requesting approval of the utility's tariff to provide a rebate to the owner or operator of distributed generation or distributed storage, including third-party owned systems, that meets the following criteria:

(1) has a nameplate generating capacity no greater than 5,000 kilowatts alternating current (AC) and is primarily used to offset a customer's electricity load, or as otherwise as defined for community renewable generation projects in Section 1-10 of the Illinois Power Agency Act;

(2) is located on the customer's side of the billing meter and for the customer's own use;

(3) is interconnected to electric distribution facilities owned by the electric utility under rules adopted by the Commission by means of one or more inverters or smart inverters required by this Section, as applicable.

For purposes of this Section, "distributed generation" shall satisfy the definition of distributed renewable energy generation device set forth in Section 1-10 of the Illinois Power Agency Act to the extent such definition is consistent with the requirements of this Section.

In addition, any new photovoltaic distributed generation that is installed after June 1, 2017 (the effective date of Public Act 99-906) must be installed by a qualified person, as defined by subsection (i) of Section 1-56 of the Illinois Power Agency Act.

The tariff shall include a base rebate that compensates distributed generation and distributed storage for the system-wide grid services associated with distributed generation and distributed storage and an additional payment or payments for any additive services identified by the Commission under Section 16-107.9. The distributed generation and distributed storage tariff shall provide that the smart inverter or smart inverters associated with the distributed generation and distributed storage shall provide autonomous response to grid conditions through its default settings as approved by the Commission. Default settings may not be changed after the execution of the interconnection agreement except by mutual agreement between the utility and the owner or operator of the distributed generation and distributed storage. Nothing in this Section shall negate or supersede Institute of Electrical and Electronics Engineers equipment standards or other similar standards or requirements. The tariff shall not limit the ability of the smart inverter or smart inverters or other distributed energy resource to provide wholesale market products such as regulation, demand response, or other services, or limit the ability of the owner of the smart inverter or the other distributed energy resource to receive compensation for providing those wholesale market products or services.

(b-5) Within 30 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric public utility with 3,000,000 or more retail customers shall file a tariff with the Commission that further compensates any retail customer that installs or has installed photovoltaic facilities paired with energy storage facilities on or adjacent to its premises for the benefits the facilities provide to the distribution grid. The tariff shall provide that, in addition to the other rebates identified in this Section, the electric utility shall rebate to such retail customer (i) the previously incurred and future costs of installing interconnection facilities and related infrastructure to enable full participation in the PJM Interconnection, LLC or its successor organization frequency regulation market; and (ii) all wholesale demand charges incurred after the effective date of this amendatory Act of the 102nd General Assembly. The Commission shall approve, or approve with modification, the tariff within 120 days after the utility's filing.

To be eligible for a rebate described in this subsection (b-5), the owner or operator of the distributed generation shall provide proof of participation in the frequency regulation market. Upon providing proof of participation, the retail customer shall be entitled to a rebate equal to the cost of the interconnection facilities paid to ComEd, regardless of whether the retail customer would have incurred the interconnection costs in the absence of participating in the frequency regulation market, plus the cost of software, telecommunications hardware, and telemetry paid to enable communication with PJM for purposes of participating in the frequency regulation market. A utility providing rebates described in this subsection (b-5) shall be entitled to recover the costs of the rebates as provided for in subsection (h) of this Section. To the extent the electric utility's tariff is modified to comply with this subsection (b-5), it shall file a revised tariff with the Commission within 120 days after the effective date of this amendatory Act of the 104th General Assembly, and the Commission shall approve, or approve with modification, the tariff within 240 days after the Commission initiates the docket.

(c) The proposed tariff authorized by subsection (b) of this Section shall include the following participation terms for rebates to be applied under this Section for distributed generation and distributed storage that satisfies the criteria set forth in subsection (b) of this Section:

(1) The owner or operator of distributed generation or distributed storage that services customers not eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act may apply for a rebate as provided for in this Section. The value of the rebate shall be $250 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of that customer's distributed generation. To the extent the distributed generation also has an associated energy storage, then until the threshold date for systems other than community renewable generation projects paired with an energy storage system, the energy storage system shall be separately compensated with a rebate of $250 per kilowatt-hour of nameplate capacity. To the extent that a community renewable generation project is paired with an energy storage system or an energy storage system that is paired with distributed generation, the energy storage system shall be separately compensated with a rebate of $250 per kilowatt-hour of nameplate capacity. A stand-alone energy storage system shall be compensated with a rebate of $250 per kilowatt-hour of nameplate capacity. Any distributed generation device that is compensated for storage in this paragraph subsection (1) after the effective date of this amendatory Act of the 104th General Assembly shall participate in one or more programs authorized by paragraph (1) of subsection (e). Compensation for any additive services shall be as determined by the Commission in the proceeding described in Section 16-107.9. Except for distributed storage projects that have obtained a signed interconnection agreement on or before June 1, 2026, the compensation provided for distributed storage under this paragraph (1) shall be limited to payment for no more than 30,000 kilowatt-hours of nameplate energy capacity and no more than 6 kilowatt-hours of nameplate energy capacity for every one kilowatt of participating power capacity, or an alternative nameplate energy capacity to participating power capacity ratio determined by the Commission to enable participation in an approved scheduled dispatch program under paragraph (1) of subsection (e) or any additive services or other programs as determined by the Commission in a proceeding described under Section 16-107.9. Notwithstanding any limitation on compensation for distributed storage under this paragraph (1), for distributed storage projects with more than 30,000 kilowatt-hours of nameplate energy capacity that demonstrate that the project's interconnection application under 83 Ill. Adm. Code 466 or 83 Ill. Adm. Code 467 was deemed complete by the applicable utility before June 1, 2026, the compensation provided for distributed storage under this paragraph (1) shall be limited to payment for no more than 100,000 kilowatt-hours of nameplate energy capacity and no more than 6 kilowatt-hours of nameplate energy capacity for every one kilowatt of participating power capacity for any single meter, but for no more than 2 meters per entity. Commitments to dispatch by such storage systems in an approved scheduled dispatch program under subsection (e) shall be mandatory. To the extent that an electric utility's tariffs are inconsistent with the requirements of this paragraph (1) as modified by this amendatory Act of the 104th General Assembly, the electric utility shall, within 60 days after the effective date of this amendatory Act of the 104th General Assembly, file modified tariffs consistent with the requirements of this paragraph (1). If the Commission chooses to suspend the modified tariffs following notice and hearing, the Commission shall issue an order approving, or approving with modification, the modified tariffs no later than 90 days after the Commission initiates the docket.

(2) The owner or operator of distributed generation that, before January 1, 2025 the threshold date, would have been eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act and that has not previously received a distributed generation rebate, may apply for a rebate as provided for in this Section. Until December 31, 2029, the value of the base rebate shall be $300 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of the distributed generation. On or after January 1, 2030, the value of the base rebate shall be $250 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of the distributed generation. The owner or operator of distributed generation that, before January 1, 2025 the threshold date, is eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act may apply for a base rebate for an associated energy storage device behind the same retail customer meter as the distributed generation, regardless of whether the distributed generation applies for a rebate for the distributed generation device. Distributed storage An energy storage system, whether or not paired with distributed generation, shall be separately compensated at a base payment of $300 per kilowatt-hour of nameplate capacity until December 31, 2029 the threshold date. After December 31, 2029 the threshold date, a stand-alone energy storage system shall be compensated with a rebate of $250 per kilowatt-hour of nameplate capacity. Any distributed generation device that is compensated for storage in this subsection (2) has the option to participate in either an hourly pricing program or time-of-use rate program and any distributed generation device that is compensated for storage in this subsection (2) after the effective date of this amendatory Act of the 104th General Assembly shall participate in a scheduled dispatch program set forth in paragraph (1) of subsection (e) when it becomes available. Compensation for any additive services or other programs shall be as determined by the Commission in the proceeding described in Section 16-107.9. Except for distributed storage projects that have obtained a signed interconnection agreement on or before June 1, 2026, the compensation provided for distributed storage under this paragraph (2) shall be limited to payment for no more than 30,000 kilowatt-hours of nameplate energy capacity and no more than 6 kilowatt-hours of nameplate energy capacity for every one kilowatt of participating power capacity, or an alternative nameplate energy capacity to participating power capacity ratio determined by the Commission to enable participation in an approved scheduled dispatch program under paragraph (1) of subsection (e) or any additive services or other programs as determined by the Commission in a proceeding described under Section 16-107.9. Notwithstanding any limitation on compensation for distributed storage under this paragraph (2), for distributed storage projects with more than 30,000 kilowatt-hours of nameplate energy capacity that demonstrate that the project's interconnection application under 83 Ill. Adm. Code 466 or 83 Ill. Adm. Code 467 was deemed complete by the applicable utility before June 1, 2026, the compensation provided for distributed storage under this paragraph (2) shall be limited to payment for no more than 100,000 kilowatt-hours of nameplate energy capacity and no more than 6 kilowatt-hours of nameplate energy capacity for every one kilowatt of participating power capacity for any single meter, but for no more than 2 meters per entity. Commitments to dispatch by such storage systems in an approved scheduled dispatch program under subsection (e) shall be mandatory. To the extent that an electric utility's tariffs are inconsistent with the requirements of this paragraph (2) as modified by this amendatory Act of the 104th General Assembly, such electric utility shall, within 60 days, file modified tariffs consistent with the requirements of this paragraph (2).

(3) Upon approval of a rebate application submitted under this subsection (c), the retail customer shall no longer be entitled to receive any delivery service credits for the excess electricity generated by its facility and shall be subject to the provisions of subsection (n) of Section 16-107.5 of this Act unless the owner or operator receives a rebate only for an energy storage device and not for the distributed generation device.

(4) To be eligible for a rebate described in this subsection (c), the owner or operator of the distributed generation must have a smart inverter installed and in operation on the distributed generation.

(5) The owner or operator of any distributed generation or distributed storage system whose electric service has not been declared competitive under Section 16-113 as of July 1, 2011 or the owner or operator of a community renewable generation project participating in the Adjustable Block Program as a community-driven community solar project as defined in item (v) of subparagraph (K) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act and that has an interconnection agreement dated after the effective date of this amendatory Act of the 104th General Assembly shall be eligible for an additional payment or payments to the applicable rebate under paragraphs (1) or (2) of this subsection (c) in an amount set by tariff and approved by the Commission if located in an equity investment eligible community, as defined in Section 1-10 of the Illinois Power Agency Act, at the time the interconnection agreement is signed.

(d) The Commission shall review the proposed tariff authorized by subsection (b) of this Section and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff. Upon the effective date of this amendatory Act of the 102nd General Assembly, an electric utility shall file a petition with the Commission to amend and update any existing tariffs to comply with subsections (b) and (c).

(e) By no later than June 30, 2026, the Commission shall establish a scheduled dispatch virtual power plant program in which customers that own or operate an energy storage system for which that receive a rebate for the distributed storage portion was provided under paragraphs (1) and (2) of subsection (c) are required to participate.

(1) The scheduled dispatch virtual power plant program shall require an enrollment period of 5 years and require each participating system to commit to dispatch each weekday during the months of June, July, August, and September from 4 p.m. to 6 p.m. for systems interconnected behind the meter of a retail customer and from 4 p.m. to 7 p.m. for systems interconnected on the distribution system of an electric utility and not behind the meter of a retail customer. For stand-alone storage that is not paired with distributed generation or any electric load beyond the electric load that is used by the energy storage system itself, commitments to dispatch shall be voluntary. Upon petition by the applicable electric utility or on its own motion, the Commission may approve different dispatch schedules provided that dispatch events do not exceed 80 days and shall not exceed 2 hours for systems interconnected behind the meter of a retail customer or 3 hours for systems interconnected on the distribution system of an electric utility and not behind the meter of a retail customer.

(2) The scheduled dispatch virtual power plant program shall be open to all customer classes with eligible distributed storage energy resources and shall measure performance based on combined export of paired resources if the eligible device is inverter-based renewables paired with storage through at least December 31, 2030 and until the Commission approves and the utility implements a tariff under subsection (d) of Section 16-107.9 of this Act, at which time such customers shall be transitioned to that tariff in a manner prescribed in the tariff. The scheduled dispatch virtual power plant program shall be required for all community renewable generation projects paired with distributed storage energy resources without regard to the threshold date. For the purposes of this subsection (e), "dispatch" includes any offsets of customer usage and any exports to the utility's distribution system.

(3) Compensation shall be set by the Commission but shall not be less than $10 per kilowatt of average dispatch during identified hours, paid to enrolled customers or project owners at end of program year. For distributed storage generation interconnected to an electric utility's distribution system and not behind the meter of a retail customer, dispatch to determine compensation shall be measured at point of interconnection. For distributed generation and storage interconnected behind the meter of a retail customer, dispatch to determine compensation shall be measured at the inverter connected to the storage device.

(4) No later than June 1, 2026, each public utility shall file an initial scheduled dispatch virtual power plant tariff. The Commission shall approve, or approve with modifications, the initial scheduled dispatch virtual power plant tariff for each utility not later than June 30, 2026.

(5) The Commission, by its own motion or by petition by an electric utility, may establish other additive services programs in addition to the virtual power plant program under Section 16-107.9. Nothing in this Section is intended to preempt or delay the implementation of other utility programs for devices that are not a part of the scheduled dispatch virtual power plant program that the Commission or utility may propose or require.

(6) No later than December 31, 2028, the utilities shall file with the Commission a report that includes information on the following: (A) the number of participants in the scheduled dispatch program; (B) impacts to energy supply prices and wholesale market activities; (C) impacts on distribution system investments and planning; and (D) any potential pathways by which the virtual power plan program described in Section 16-107.9 may be designed to capture wholesale market value through participation in the wholesale market and apply that wholesale market revenue to reduce utility distribution or electric supply rates for customers.

(f) Notwithstanding any provision of this Act to the contrary, the owner or operator of a community renewable generation project as defined in Section 1-10 of the Illinois Power Agency Act whether or not a paired energy storage system or the owner or operator of an energy storage system that is eligible for net metering under subsection (l-10) of Section 16-107.5 shall also be eligible to apply for the rebate described in this Section. The owner or operator of the community renewable generation project whether or not a paired energy storage system or the owner or operator of an energy storage system that is eligible for net metering under subsection (l-10) of Section 16-107.5 may apply for a rebate only if the owner or operator, or previous owner or operator, of the community renewable generation project whether or not a paired energy storage system or the owner or operator of an energy storage system that is eligible for net metering under subsection (l-10) of Section 16-107.5 has not already submitted an application, and, regardless of whether the subscriber is a residential or non-residential customer, may be allowed the amount identified in paragraph (1) of subsection (c) applicable on the date that the application is submitted.

(g) The owner of a distributed storage system, whether or not paired with distributed generation, may apply for the rebate or rebates approved under this Section at the time of execution of an interconnection agreement with the distribution utility and shall receive the value available at that time of execution of the interconnection agreement. The utility shall issue the rebate no later than 60 days after the project is energized. In the event the application is incomplete or the utility is otherwise unable to calculate the payment based on the information provided by the owner, the utility shall issue the payment no later than 60 days after the application is complete or all requested information is received.

(h) An electric utility shall recover from its retail customers all of the costs of the rebates made under a tariff or tariffs approved under this Section, including, but not limited to, the value of the rebates and all costs incurred by the utility to comply with and implement subsections (b), (b-5), (c), and (e) of this Section, consistent with the following provisions:

(1) The utility shall defer the full amount of its costs as a regulatory asset. The total costs deferred as a regulatory asset shall be amortized over a 15-year period. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the unamortized balance of the regulatory assets, less any deferred taxes related to the unamortized balance, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end capital structure, the utility's actual cost of debt for the applicable calendar year and a cost of equity, which shall be equal to the baseline cost of equity approved by the Commission for the utility's electric distribution rates case effective during the applicable year, whether those rates are set pursuant to Section 9-201, subparagraph (B) of paragraph (3) of subsection (d) of Section 16-108.18, or any successor electric distribution ratemaking paradigm.

When an electric utility creates a regulatory asset under the provisions of this paragraph (1) of subsection (h), 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 paragraph (1) shall recover all of the associated costs, including, but not limited to, its cost of capital as set forth in this paragraph (1). 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. 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) The utility, at its election, may recover all of the costs as part of a filing for a general increase in rates under Article IX of this Act, as part of an annual filing to update a performance-based rate under Section 16-108.18, or through an automatic adjustment clause tariff, provided that nothing in this paragraph (2) permits the double recovery of such costs from customers. If the utility elects to recover the costs it incurs under subsections (b), (b-5), (c), and (e) through an automatic adjustment clause tariff, the utility may file its proposed tariff together with the tariff it files under subsection (b) of this Section or at a later time. The proposed tariff shall provide for an annual reconciliation, 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 as calculated under paragraph (1) of this subsection (h), 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 revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its automatic adjustment clause tariff under this subsection (h), 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 Commission shall review the proposed tariff and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff.

(i) (Blank).

(j) No later than 90 days after the Commission enters an order, or order on rehearing, whichever is later, approving an electric utility's proposed tariff under this Section, the electric utility shall provide notice of the availability of rebates under this Section.

(k) No later than January 1, 2030, the utilities shall file with the Commission a report that includes:

(1) the number and geographic distribution of participants receiving rebates pursuant to this Section;

(2) impacts to energy supply prices and wholesale market activities;

(3) impacts on distribution system investments and planning; and

(4) any other values deemed relevant by the Commission.

(l) Upon petition by the applicable electric utility or on its own motion, the Commission may adjust rebate levels for new customers and make other appropriate changes to the rebate program in a manner that is consistent with the State's clean energy goals and the public interest.

(m) A vehicle storage system, as defined in Section 16-107.5, is not eligible for a rebate under this Section.

(Source: P.A. 103-1066, eff. 2-20-25; 104-458, eff. 6-1-26.)

(220 ILCS 5/16-107.9)

(This Section may contain text from a Public Act with a delayed effective date)

Sec. 16-107.9. Virtual power plant program.

(a) As used in this Section:

"Aggregator" means a third-party entity that participates in the program, other than the electric utility or its affiliate, that (i) represents and aggregates the load of participating customers who collectively have the ability to deploy 100 kilowatts or more of deployment of eligible devices and (ii) is responsible for performance of the aggregation in the program.

"Battery" means a behind-the-meter energy storage device and associated equipment that operate together to fulfill program requirements.

"Commission" means the Illinois Commerce Commission.

"Customer" means an active electric service account holder of a utility.

"Direct participant" means a customer that enrolls in the program directly with the utility, rather than participating in the program through an aggregator.

"Distributed energy resource" has the meaning set forth in Section 16-107.6.

"Distributed energy resources management system" means a platform that may be used by distribution system operators or utilities to integrate grid resources, such as distributed energy resources, into system operations.

"Eligible device" means a customer or third party-owned distributed energy resource that satisfies the requirements for participation in the program as specified in the relevant program rider. "Eligible device" also means any device that can be controlled to respond to pricing, provide services, including decrease peak electricity demand or shift demand from peak to off-peak periods, or inject power to the grid. "Eligible device" includes, but is not limited to, behind-the-meter energy storage systems, smart thermostats, electric vehicle batteries, including fleets, and distributed renewable energy devices paired with one or more energy storage systems.

"Emergency event" means an event called by the utility with fewer than 24 hours notice.

"Energy storage system" has the meaning set forth in subsection (a) of Section 16-107.6.

"Enrolled customer" means a customer that participates in the program through either an aggregator or as a direct participant.

"Enrolled device" means an enrolled customer's eligible device, as specified in the relevant tariff.

"Enterprise distributed energy resources management system" means a platform operated by the electric utility that interfaces with a grid-edge distributed energy resources management system to integrate distributed energy resources into utility electric system operations.

"Grid-edge distributed energy resources management system" means a platform owned by a party other than the electric utility that may be used to integrate distributed energy resources.

"Grid event" means a grid condition for which the utility schedules or remotely dispatches enrolled devices to respond to, as specified in the grid service opportunities for each tariff.

"Grid service" means a capacity, energy, or ancillary service that supports grid operations.

"Participating customer" means an aggregator or a direct retail customer, as defined in Section 16-102, with one or more eligible devices.

"Performance payment" means a payment made to the participant based on the performance of an enrolled device providing a grid service during a grid event.

"Performance payment rate" means the compensation rate paid to participants for providing a particular grid service during a grid event.

"Smart inverter" has the meaning set forth in subsection (a) of Section 16-107.6.

"Upfront payment" means a one-time payment made at the time of enrollment.

"Virtual power plant" means an aggregation of behind-the-meter distributed energy resources operated in coordination to provide one or more grid services.

(b) The General Assembly finds that:

(1) virtual power plants are dynamic load management and energy supply resources that can support grid operations, reduce ratepayer costs, and achieve other important public policy goals;

(2) virtual power plants can reduce demand for grid supplied electricity during peak periods, shift electricity consumption out of peak periods, make renewable energy generated during off-peak periods available for use during peak periods, supply energy to the grid at desired times, provide frequency regulation, voltage support, and other ancillary services, reduce strain on the distribution system, manage localized peaks, improve system resiliency and reliability, and provide other grid services;

(3) virtual power plants can facilitate and optimize the utilization of electrical generation from wind and solar energy to help utilities increase hosting capacity and integrate more renewable energy resources;

(4) virtual power plants can reduce costs to ratepayers by utilizing customer-sited resources to provide grid services, avoiding or reducing reliance on fossil-fuel fired peaker plants, avoiding or deferring the need to construct new and more costly grid scale resources, optimizing the use of existing assets, and avoiding or deferring distribution and transmission system upgrades and other grid investments;

(5) virtual power plants can promote equity by reducing costs for all ratepayers, expanding access to distributed energy resources among low-income and moderate-income customers through improved distributed energy resource finance ability, and providing other important co-benefits, including reduction in emissions of greenhouse gases and other pollutants, especially in environmental justice and other disadvantaged communities that host fossil fuel generation plants;

(6) the United States Department of Energy estimates that the United States could deploy 80 to 160 gigawatts of virtual power plants by 2030, a tripling of current levels, to support the rapid electrification of vehicles and homes and provide on the order of $10,000,000,000 in ratepayer savings annually. The deployment of virtual power plants can provide energy cost savings and other benefits to the people of Illinois;

(7) there are significant barriers to deployment and operation of virtual power plants, including the need for statutory and regulatory guidance and support, greater consistency in virtual power plant programs across regulatory jurisdictions, and for utility commitments to incorporate the use of virtual power plants into system operations and long-term resource planning;

(8) it is in the public interest to advance customer choice and leverage the expertise of private, non-utility entities to advance innovation and implement cost-effective clean energy solutions; and

(9) the policy of Illinois shall be to maximize the use of virtual power plants comprised of customer-owned and third party-owned distributed energy resources to deliver system services and other benefits through utility administered virtual power plant programs in accordance with the provisions of this amendatory Act of the 104th General Assembly.

(c) No later than December 31, 2028, the Commission shall approve at least one virtual power plant tariff for each electric utility serving more than 300,000 customers in the State as of January 1, 2023. Each utility shall file a tariff or tariffs for approval no later than December 31, 2027 to allow retail customers in the electric utility's service areas to participate in a virtual power plant program proposal consistent with the provisions of this Section. The Commission shall provide opportunities for stakeholders to provide input on the virtual power plant programs proposed for implementation by each utility, which the Commission shall take into consideration in its review of each utility's filing. No later than one year after the utility's filing, the Commission shall approve or modify and approve each utility's virtual power plant program proposal for immediate implementation by the utility.

(d) The virtual power plant program filed under subsection (c) shall be developed for implementation through a tariff offering with standard terms and conditions for participation. The virtual power plant program tariff shall allow for customers with battery storage, non-battery storage and electric vehicle technologies to enroll the devices in the program through aggregators or directly with the utility. The virtual power plant program tariff shall:

(1) provide a mechanism to incorporate existing programs, such as smart thermostat demand-response or electric vehicle charging programs currently offered by the utility, under the virtual power plant program framework;

(2) provide grid services opportunities for each eligible technology that customers and aggregators may provide, which shall include, at minimum, reducing the utility's applicable capacity and transmission obligations and capturing daily wholesale energy arbitrage opportunities through provision of grid services;

(3) provide additional functions and grid service opportunities that the Commission determines are supportive of efficient planning and operation of the electrical grid, including:

(A) minimizing the use of fossil fuels at peak times;

(B) local peak demand reductions;

(C) locational value;

(D) the avoidance or deferral of local transmission or distribution upgrades or capacity expansion;

(E) voltage support and other ancillary services; and

(F) emergency grid services;

(4) provide operational parameters, which shall include, at a minimum:

(A) minimum and maximum numbers of grid events for which the utility may require dispatch from the enrolled distributed energy resources;

(B) months of the year that grid events may occur;

(C) days of the week that grid events may occur;

(D) times of day that grid events may occur;

(E) maximum duration of grid events; and

(F) minimum day-ahead advance notification requirement of grid events, except for emergency events, as applicable;

(5) include provisions for aggregators to participate in the virtual power plant program, participate in the utility's distributed energy resource management system as available, automatically enroll and manage their customers' participation, receive dispatch signals and other communications from the utility, deliver performance measurement and verification data to the utility, and receive virtual power plant program payments directly from the utility;

(6) include provisions that provide a standardized process for any eligible aggregator to enroll in the program and authorize the eligible aggregators to manage individual customer device participation without additional authorizations from the utility;

(7) include provisions that allow a participating customer with multiple eligible devices to enroll the technologies either directly without an aggregator or through one or more aggregators in applicable programs under the tariff approved under this Section, provided that no particular device is accounted for more than once;

(8) include provisions for direct participant customers to participate with the utility's distributed energy resource management system as available, receive dispatch signals and other communications from the utility, deliver performance measurement and verification data to the utility, and receive virtual power plant program payments directly from the utility. Any provisions implementing this subpart that necessitate the installation of equipment to enable direct participation via the utility shall apply to customers who elect to participate as a direct participant and shall not be required of customers who participate via an aggregator or to customers who do not participate in the virtual power plant program;

(9) provide for measurement and verification of battery non-battery, and electric vehicle technologies performance directly at the device without the requirement for the installation of an additional meter;

(10) include upfront payment or performance payment compensation mechanisms for the peak reduction service, as well as for non-battery and electric vehicle technologies as the Commission deems appropriate. The performance payment shall be based on the average capacity provided during grid events. The Commission shall approve additional compensation mechanisms as it determines appropriate for other grid services provided under the battery, non-battery and electric vehicle riders. The virtual power plant program shall not assess penalties for non-performance; provided, however, that the Commission may approve reasonable mechanisms to disenroll customers for continued non-performance;

(11) enable low-to-moderate income customers, community-driven community solar projects, and customers whose electric service has not been declared competitive pursuant to Section 16-113 as of July 1, 2011 located in equity investment eligible investment communities to receive a higher upfront enrollment payment. The Commission shall coordinate with State energy officials and departments to make funding from federal programs and such other sources as may be available for use in providing higher upfront payments to customers classes as may be approved by the Commission in accordance with this subsection;

(12) provide that the performance payment rate applicable at the time of enrollment shall be for 5 years, after which time the participant may reenroll at the then applicable performance payment rate for an additional 5-year term;

(13) provide for a transition of customers from the scheduled dispatch program described in Section 16-107.6 to the virtual power plant program; and

(14) allow enrolled customers to participate in other applicable interconnection tariffs and grid service programs outside the virtual power plant program, so long as it does not result in double-counting of benefits for the same grid services.

(e) The Commission may adopt other reasonable requirements for participation consistent with this subsection, provided that collateral from an aggregator shall not be required for participation.

(f) The utility may contract with a third party-owned distributed energy resource management system provider to assist with program implementation; however, implementation shall not be delayed due to the lack of utility-owned distributed energy resource management system capabilities or third party-owned distributed energy resource management system capabilities.

(g) The utility shall not send or receive dispatch signals directly to or from any participating customer represented by an aggregator for an event under the virtual power plant program described in this Section.

(h) Participating aggregators shall have capabilities to receive event signals from utilities or utility-contracted distributed energy resources management system providers. To facilitate the adoption of and participation in the virtual power plant program, the utility shall allow and enable participating customers to expeditiously share their customer information with aggregators in order to serve any contracted customers and comply with any reporting requirements.

(i) Utilities shall recover reasonably and prudently incurred costs to facilitate the virtual power plant program approved under subsection (c), including, but not limited to, distributed energy resource management systems provider and other service contract costs, operations and maintenance expenses, information technology costs, and other costs, expenses, and investments that the Commission finds necessary and prudent for the development and implementation of the program. The utility shall recover the cost of virtual power plant program upfront payments and performance payments and such other payments made to participants through the tariff filed pursuant to subsection (h) of Section 16-107.6.

(j) No later than January 31 of each year, each utility shall file an annual report that includes, but is not limited to:

(1) the total capacity enrolled in each program rider developed in accordance with the requirements of Section, broken down by technology type, customer class, and aggregator and direct participant status for each grid service opportunity offered in the prior calendar year;

(2) recommendations to increase participation in the virtual power plant program; and

(3) any other information that the Commission may require.

(k) Each utility shall amend existing tariffs and procedures that limit the ability of customers to participate in providing grid services under the program, such as limitations on charging energy storage devices with grid energy or exporting energy to the grid from battery discharge.

(l) The tariffs approved by the Commission shall not reflect any additional charges, fees, or insurance requirements imposed on those owning or operating demand-response technologies beyond those imposed on similarly situated customers that do not own or operate demand-response technologies.

(m) As a condition of participating in the programs described in this Section, prior to enrollment of a customer by an aggregator, the aggregator shall disclose the following:

(1) the payments, expressed as an amount or a formula, to be provided to the customer;

(2) between the aggregator and customer, who is responsible for paying penalties or fees; and

(3) between the aggregator and customer, who is responsible for posting collateral, if required.

Any tariff authorized by this Section shall incorporate the requirements under this subsection and shall require the electric utility to establish a complaint and Commission notification process and, on order of the Commission, suspend any aggregator repeatedly or egregiously violating such requirements.

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

(220 ILCS 5/16-202)

(This Section may contain text from a Public Act with a delayed effective date)

Sec. 16-202. Integrated resource plan review and approval.

(a) The Commission shall enter its order approving or approving with modifications an integrated resource plan within 180 days after the agencies filing the plan and any companion reports or other information. The Commission may extend the period of review of the plan for no more than an additional 180 days.

(b) The Commission may approve a plan or a modified plan and authorize its implementation only if, after notice and hearing, including the conduct of discovery and taking of evidence, it finds that the plan:

(1) addresses any resource adequacy challenges in the 5 years immediately following approval of the plan, while also taking into account the 10 years following the plan;

(2) prepares the State to best address issues of resource adequacy at the least amount of CO_2e and copollutant emissions;

(3) considers the emissions' impacts on environmental justice communities while taking into account all applicable labor and equity standards;

(4) supports the provisioning of adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time; and

(5) utilizes the expansion of renewable energy, energy storage, virtual power plants and distributed energy storage, energy efficiency, demand response, time-of-use rates or other mechanisms designed to manage peak load, transmission development, carbon mitigation credits or any other clean energy strategies to the maximum extent practicable to resolve any identified resource adequacy shortfall or reliability violation in a cost-effective, affordable, timely, and clean manner.

(c) The Commission may, as a part of its decision to approve a plan or modified plan and to the extent consistent with the uniform allocation of costs required under subsection (k) of Section 16-108, order changes to existing plans or programs, direct specific actions within existing plans or programs, including the authorization to support the expansion of an existing plan or program, including, but not limited to:

(1) any of the following plans or programs designed to increase the amount of generation and capacity available:

(i) the Long-Term Renewable Resources Procurement Plan, including programs and procurements authorized through that Plan, and to increase the limitations placed on the procurement of renewable energy resources established pursuant to subparagraph (E) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act in order to increase, direct, or adjust procurements of renewable energy resources to support new renewable energy projects;

(ii) the Energy Storage Resources Procurement Plan, including programs and procurements authorized through that Plan, and to increase the procurement of energy storage established pursuant to subsection (d-20) of Section 1-75 of the Illinois Power Agency Act in order to increase or adjust procurements for new energy storage;

(iii) the carbon mitigation credit procurement plans established pursuant to subsection (d-10) of Section 1-75 of the Illinois Power Agency Act in order to preserve existing carbon-free energy resources, including extending or expanding carbon mitigation credit contract awards in accordance with a new schedule of baseline costs;

(iv) the Illinois Power Agency's annual electricity procurement plans established pursuant to paragraph (2) of subsection (d) of Section 16-111.5, including modification of the products to be procured and allowing for costs associated with the purchase of new or additional products to be socialized across all retail customers or all load-serving entities, as applicable; and

(v) any plan to reduce or delay CO₂e and copollutant emissions reductions requirements that is submitted by the Illinois Power Agency and Environmental Protection Agency and approved by the Commission under subsection (o) of Section 9.15 of the Environmental Protection Act; and

(vi) (v) any additional plans or programs designed to procure appropriate sources of new clean energy and capacity resources, including any associated clean attribute credits; and

(2) any of the following designed to manage energy demand, including, but not limited to:

(i) extending or expanding the energy efficiency programs implemented by electric utilities and the limitation on the amount of energy efficiency and demand-response measures implemented pursuant to Section 8-103B in order to gain increased load reductions; and

(ii) the Multi-Year Integrated Grid Plans implemented by electric utilities pursuant to Section 16-105.17 in order to extend or expand programs related to peak load management and reduction, including, but not limited to, virtual power plants, front of the meter distributed storage, demand response, and time-of-use rates.

(d) If all of the changes made to the plans or programs pursuant to this Section would reasonably be insufficient to balance supply and demand and avoid a resource adequacy shortfall, then the Commission may delay, in whole or in part, the CO_2e and copollutant emissions reductions requirements found in Section 9.15 of the Environmental Protection Act but only to the minimum extent and duration necessary to address the resource adequacy shortfall needs of the State. If the Commission finds that reducing or delaying the emissions reductions requirements is necessary, despite any or all of the changes made pursuant to this Section, then it shall also include in its final order recommendations to the General Assembly on what additional policies may be adopted that could avoid future modifications to the emissions reductions.

(e) Unless otherwise specified by the Commission, the order approving the plan or modified plan shall become effective January 1 of the calendar year immediately following the issuance of the order. The agencies, electric utilities, and any other impacted entities shall comply with any of the Commission's orders, and when required seek approval from the Commission and make any required modifications to their plans, programs, or related initiatives in a manner consistent with the process and timing for those changes as outlined in the approved plans or, if none is specified, as soon as practicable. If the integrated resource plan approved by the Commission contains recommendations that are outside the Commission's authority, the Commission shall communicate any such recommendations to the Governor and the General Assembly.

(f) Given the critical and rapid actions required under this Section, the Commission may procure the services of any facilitator, expert, or consultant, including the procurement monitor retained by the Commission pursuant to paragraph (2) of subsection (c) of Section 16-111.5. Such procurement is exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-10 of that Code.

(g) Costs that are prudently and reasonably incurred by electric utilities to comply with the requirements of this Section shall be recovered and shall be excluded from the calculation performed under paragraph (6) of subsection (f) of Section 16-108.18. Nothing in the Commission's order directing changes to a prior approved plan as enumerated in this Section shall be the sole basis for a finding of imprudence or unreasonableness or the lack of use or usefulness of any investment or expenditure.

(h) If the Commission's final order under this Section includes the approval of rate increases through the expansion of existing plans or programs, the creation of new plans or programs, or the increase of limitations placed on procurements as described under paragraphs (1) and (2) of subsection (c), the Commission shall submit notice to the General Assembly of the increases included in the final order, including the estimated monthly cost impact on customers and the expected costs savings or benefits of such actions. After receipt of a notice, any member of the General Assembly may introduce in the General Assembly a joint resolution stating that the General Assembly desires to suspend the rate increases, or suspend a portion of the rate increases, identified in the final order and specifying the rationale for the General Assembly's determination.

(1) If the General Assembly passes a joint resolution under this subsection (h) that takes effect prior to the effective date of the Commission's final order, the General Assembly shall send notice to the Commission of the resolution, and the Commission shall suspend its final order. Within 30 days of receipt of the General Assembly's notice, the Commission shall reopen the docket approving the plan or modified plan in order to take into account the General Assembly's reduction or elimination of the rate increases. The Commission shall approve the modified plan within 120 days of reopening the docket, including the conduct of discovery and the taking of evidence, and send notice to the General Assembly of its modified plan. The General Assembly may rescind its desire to suspend the rate increases, or suspend a portion of the rate increases, by adoption of a subsequent joint resolution by each chamber of the General Assembly within 30 days of receipt of the Commission's notice that would put into effect the Commission's original final order.

(2) If the General Assembly fails to pass a joint resolution under this subsection (h) prior to the effective date of the Commission's final order, the associated rate increases shall go into effect pursuant to the schedule specified in the Commission's final order approving the plan or modified plan.

(i) The Commission may adopt rules to implement the requirements of this Section.

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

(220 ILCS 5/20-140)

(This Section may contain text from a Public Act with a delayed effective date)

Sec. 20-140. Interconnection Working Group.

(a) The Commission shall establish an Interconnection Working Group. The Working Group shall include representatives from electric utilities, developers of renewable electric generating facilities, representatives of new large loads seeking grid interconnection, other industries that regularly apply for interconnection with the electric utilities as appropriate, representatives of distributed generation customers, the Commission staff, and other stakeholders with a substantial interest in the topics addressed by the Interconnection Working Group.

(b) The Interconnection Working Group shall address at least the following issues in relation to new generation and new large loads:

(1) the cost of and the best available technology for interconnection and metering, including the standardization and publication of standard costs;

(2) transparency, accuracy, and use of the distribution interconnection queue and hosting capacity maps;

(3) distribution system upgrade cost avoidance through use of advanced inverter functions, energy storage, and load management;

(4) predictability of the queue management process and enforcement of timelines;

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

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

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

(8) options for metering distributed energy resources, including energy storage;

(9) interconnection of new technologies, including smart inverters and energy storage;

(10) collection, examination, and sharing of data on Level 1 interconnection costs, including cost and type of upgrades required for interconnection, and the use of this data to inform the final standardized cost of Level 1 interconnection;

(11) determination of a single standardized cost for Level 1 interconnections, which shall not exceed $200; and

(12) such other technical, policy, and tariff issues related to and affecting interconnection performance and customer service as determined by the Interconnection Working Group.

(c) The Commission may create subcommittees of the Interconnection Working Group to focus on specific issues of importance, as appropriate.

(d) The Interconnection Working Group shall report to the Commission on recommended improvements to interconnection rules, tariffs, and policies as determined by the Interconnection Working Group at least every year. A report shall include consensus recommendations of the Interconnection Working Group and, if applicable, additional recommendations for which consensus was not reached. Non-consensus shall not be a basis for excluding recommendations that are majority or minority recommendations. 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. The Interconnection Working Group shall provide the reports under this subsection (d) to the Commission on at least the following topics in the order listed below within a reasonable time, but no later than 12 months, after the effective date of this amendatory Act of the 104th General Assembly: (A) a mechanism for good cause extensions to construction timelines as long as the interconnection customer reasonably demonstrates progress; (B) a mechanism for all electric utilities to accept cash, letters of credit, or bonds for any deposits required under the interconnection agreement; (C) cost sharing for distribution system upgrades and interconnection facilities for multiple interconnection customers attempting to interconnect on the same feeder or substation; (D) requirements that utilities initiate the interconnection study process interconnection studies process without delay based on queue position or status of applications ahead in the queue, and associated requirements for disclosure of contingent upgrades; (E) provisions allowing for queue reservation for the interconnection of projects installed on public school land to accommodate timing constraints of school board approval and budgeting; and (F) if feasible within the time allotted for the initial report, parameters for utility interconnection studies of energy storage systems not paired with distributed generation that are based on the proposed operational profile of the energy storage systems.

(d-5) Within 12 months after the report directed by subsection (d) has been submitted, the Working Group shall report to the Commission on the following: (A) mandatory disclosures on the hosting capacity map and studies for contingent upgrades including timelines for notice of responsibility and payment; (B) a framework for concurrent study on multiple feeders for a distributed energy resource; and (C) if not provided in the initial report required under subsection (d), parameters for utility interconnection studies of energy storage systems not paired with distributed generation that are based on the proposed operational profile of the energy storage systems.

(d-10) Within 12 months after the report directed by subsection (d-5) has been submitted, the Working Group shall report to the Commission on the following: (A) dynamic hosting capacity maps; (B) standards for public queue and hosting capacity map information regarding individual projects in queue, including (i) distributed generation nameplate capacity, (ii) paired or stand-alone energy storage system nameplate capacity, (iii) detailed estimated upgrade costs, and (iv) systems that have completed upgrades and withdrawn projects; and (C) timelines for refund of deposits if the interconnection agreement is terminated. Within the same time period, utilities shall publish all final interconnection agreements, facilities studies, and system impact studies.

(d-15) Within 12 months after the report directed by subsection (d-10) has been submitted, the Working Group shall report to the Commission on the following: (A) level of detail of costs in system impact and facilities studies and level 2 studies; and (B) a cap on charges to the interconnection customer based on a percentage of the non-binding cost estimate in the facilities study, system impact study, or level 2 study.

(e) In collaboration with the General Counsel of the Commission, the Office of Retail Market Development shall develop policies and procedures to facilitate employees of the Office in leading the Interconnection Working Group without interference with docketed proceedings. The policies and procedures developed under this subsection (e) shall be designed to allow the Interconnection Working Group to work without interruption.

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

(220 ILCS 5/23-115)

(This Section may contain text from a Public Act with a delayed effective date)

Sec. 23-115. Resolution of disputes between facility owners and units of local government related to the siting of qualified energy facilities.

(a) The expedited procedures in this Section shall be used to enforce the provisions of the applicable State siting law.

(b) No petition may be filed under this Section until the facility owner that intends to file the petition has first notified the respondent of the alleged violation of the applicable State siting law and offered the respondent 7 days to correct or take substantial steps to begin and diligently pursue curing the alleged violation. Provision of notice and the opportunity to correct the situation creates a rebuttable presumption of knowledge under this Section. After the filing of a petition under this Section, the parties may agree to follow the mediation process under Section 10-101.1 of this Act. The time periods specified in subdivision (c)(7) of this Section shall be tolled during the time spent in mediation under Section 10-101.1.

(c) A facility owner may file a petition with the Commission alleging a violation of the applicable State siting law in accordance with this subsection. The following procedures shall govern the dispute resolution process:

(1) The petition shall be filed with the Chief Clerk of the Commission and shall be served in hand upon the respondent, the executive director, and the general counsel of the Commission at the time of the filing.

(2) A petition filed under this subsection shall include a statement that the requirements of subsection (b) have been fulfilled and that the respondent did not correct the situation as requested.

(3) Reasonable discovery specific to the issue of the petition may commence upon filing of the petition.

(4) An answer and any other responsive pleading to the petition shall be filed with the Commission and served at the same time upon the complainant, the executive director, and the general counsel of the Commission within 7 days after the date on which the petition is filed.

(5) If the answer or responsive pleading raises the issue that the petition violates subsection (f) of this Section, the complainant may file a reply to such allegation within 3 days after actual service of such answer or responsive pleading. Within 4 days after the time for filing a reply has expired, the administrative law judge shall either issue a written decision dismissing the petition as frivolous in violation of subsection (f) of this Section including the reasons for such disposition or shall issue an order directing that the petition shall proceed.

(6) A pre-hearing conference shall be held within 14 days after the date on which the petition is filed.

(7) The hearing shall commence within 45 days of the date on which the petition is filed and shall be conducted by an administrative law judge. Parties and the Commission staff shall be entitled to present evidence and legal argument in oral or written form as deemed appropriate by the administrative law judge. The administrative law judge shall issue a proposed order within 90 days after the date on which the petition is filed. The proposed order shall include reasons for the disposition of the petition and, if a violation of the applicable State siting law is found, directions and a deadline for correction of the violation.

(8) Any party may file a petition requesting the Commission to review the proposed order of the administrative law judge or arbitrator within 5 days after the proposed order is issued and file exceptions to the proposed order. Any party may file a response to a petition for review within 3 business days after actual service of the petition. After the time for filing of the petition for review, but no later than 60 days after the proposed order of the administrative law judge, the Commission shall decide to adopt the proposed order of the administrative law judge or shall issue its own final order.

(d) In resolving disputes filed under this Section, the administrative law judge and the Commission shall make determinations based on the requirements and intent of the applicable State siting law.

(e) In resolving disputes under this Section, the Commission shall have authority to issue a siting certificate for a qualified energy facility if the Commission determines that the qualified energy facility is in compliance with the applicable State siting law for a qualified energy facility and that the respondent:

(1) has the respondent denied the qualified energy facility a siting certificate; or and

(2) has failed or declined to issue the qualified energy facility a siting certificate in a timely manner. the qualified energy facility is in compliance with the applicable State siting laws for a qualified energy facility.

For the purposes of this Section, a commercial wind energy facility and commercial solar energy facility shall be in compliance with Section 5-12020 of the Counties Code and an energy storage system shall be in compliance with Section 5-12024 of the Counties Code. If the Commission determines that there is substantial harm to the facility owner, the Commission may, notwithstanding any other provision of this Act, seek temporary, preliminary, or permanent injunctive relief from a court of competent jurisdiction either before or after the hearing.

(f) A party shall not bring or defend a proceeding brought under this Section or assert or controvert an issue in a proceeding brought under this Section, unless there is a non-frivolous basis for doing so. By presenting a pleading, written motion, or other paper in petition or defense of the actions or inaction of a party under this Section, a party is certifying to the Commission that to the best of that party's knowledge, information, and belief, formed after a reasonable inquiry of the subject matter of the petition or defense, that the petition or defense is well grounded in law and fact, and under the circumstances:

(1) it is not being presented to harass the other party, cause unnecessary delay, or create needless increases in the cost of litigation; and

(2) the allegations and other factual contentions have evidentiary support or, if specifically so identified, are likely to have evidentiary support after reasonable opportunity for further investigation or discovery as defined herein.

(g) If, after notice and a reasonable opportunity to respond, the Commission determines that subsection (f) has been violated, the Commission shall impose appropriate sanctions upon the party or parties that have violated subsection (f) (i) or are responsible for the violation.

(h) An appeal of a Commission order made pursuant to this Section shall not effectuate a stay of the order unless a court of competent jurisdiction specifically finds that the party seeking the stay will likely succeed on the merits, that the party will suffer irreparable harm without the stay, and that the stay is in the public interest.

(i) The Commission shall assess the parties under this subsection for all of the Commission's costs of investigation and conduct of the proceedings brought under this Section including, but not limited to, the prorated salaries of staff, attorneys, administrative law judges, and support personnel and including any travel and per diem, directly attributable to the petition brought pursuant to this Section, but excluding those costs provided for in subsection (g), dividing the costs according to the resolution of the petition brought under this Section. All assessments made under this subsection shall be paid into the Public Utility Fund within 60 days after receiving notice of the assessments from the Commission. Interest at the statutory rate shall accrue after the expiration of the 60-day period. The Commission is authorized to apply to a court of competent jurisdiction for an order requiring payment.

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

Section 30. The Utility Data Access Act is amended by changing Sections 5-10 and 5-15 as follows:

(220 ILCS 33/5-10)

(This Section may contain text from a Public Act with a delayed effective date)

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

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

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

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

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

"Commission" means the Illinois Commerce Commission.

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

"Data recipient" means:

(1) an owner of the property or building;

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

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

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

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

"Property" means:

(1) a single tax parcel;

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

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

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

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

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

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

"Utility" means an entity that is an electric or gas utility with over 100,000 500,000 customers in this State and that is a public utility, as defined in Section 3-105 of the Public Utilities Act.

"Utility data type" means electric or gas.

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

(220 ILCS 33/5-15)

(This Section may contain text from a Public Act with a delayed effective date)

Sec. 5-15. Utility data access.

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

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

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

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

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

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

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

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

Notwithstanding any other law, aggregated usage data from multiple customer accounts shall not be deemed customer utility usage information, personally identifiable information, or confidential information and shall not be subject to protections for customer utility usage information, personally identifiable information, or confidential information.

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

(1) The covered usage data must be available to be requested online. A utility's validation of the requester's identity shall be consistent with, and no more onerous than, the utility's then-current practices.

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

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

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

(2) for any initial upload of data to a data recipient and subject to subsection (j) of this Section, a data recipient must include all the data for the time period required in paragraph (1) of subsection (b), regardless of whether the data recipient had a business relationship with the building or property during that period;

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

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

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

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

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

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

(e) The Commission shall direct that covered usage data shall be delivered to the data recipient in a standard format consistent with the benchmarking tool at the data recipient's request. The Commission shall direct electric utilities that serve at least 100,000 500,000 customers in the State to provide requested data by direct upload to the benchmarking tool and associate the data with the data recipient's benchmarking tool account.

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

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

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

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

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

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

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

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

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

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

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

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

Section 35. The Environmental Protection Act is amended by changing Section 9.15 as follows:

(415 ILCS 5/9.15)

(Text of Section before amendment by P.A. 104-458)

Sec. 9.15. Greenhouse gases.

(a) An air pollution construction permit shall not be required due to emissions of greenhouse gases if the equipment, site, or source is not subject to regulation, as defined by 40 CFR 52.21, as now or hereafter amended, for greenhouse gases or is otherwise not addressed in this Section or by the Board in regulations for greenhouse gases. These exemptions do not relieve an owner or operator from the obligation to comply with other applicable rules or regulations.

(b) An air pollution operating permit shall not be required due to emissions of greenhouse gases if the equipment, site, or source is not subject to regulation, as defined by Section 39.5 of this Act, for greenhouse gases or is otherwise not addressed in this Section or by the Board in regulations for greenhouse gases. These exemptions do not relieve an owner or operator from the obligation to comply with other applicable rules or regulations.

(c) (Blank).

(d) (Blank).

(e) (Blank).

(f) As used in this Section:

"Carbon dioxide emission" means the plant annual CO₂ total output emission as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrated Database (eGrid), or its successor.

"Carbon dioxide equivalent emissions" or "CO₂e" means the sum total of the mass amount of emissions in tons per year, calculated by multiplying the mass amount of each of the 6 greenhouse gases specified in Section 3.207, in tons per year, by its associated global warming potential as set forth in 40 CFR 98, subpart A, table A-1 or its successor, and then adding them all together.

"Cogeneration" or "combined heat and power" refers to any system that, either simultaneously or sequentially, produces electricity and useful thermal energy from a single fuel source.

"Copollutants" refers to the 6 criteria pollutants that have been identified by the United States Environmental Protection Agency pursuant to the Clean Air Act.

"Electric generating unit" or "EGU" means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system that serves a generator that has a nameplate capacity greater than 25 MWe and produces electricity for sale.

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

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

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

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

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

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

(2) persons whose primary residence is in a municipality, or a county with a population under 100,000, where the closure of an electric generating unit or mine has been publicly announced or the electric generating unit or mine is in the process of closing or closed within the last 5 years;

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

(4) persons who were formerly incarcerated.

"Existing emissions" means:

(1) for CO₂e, the total average tons-per-year of CO₂e emitted by the EGU or large GHG-emitting unit either in the years 2018 through 2020 or, if the unit was not yet in operation by January 1, 2018, in the first 3 full years of that unit's operation; and

(2) for any copollutant, the total average tons-per-year of that copollutant emitted by the EGU or large GHG-emitting unit either in the years 2018 through 2020 or, if the unit was not yet in operation by January 1, 2018, in the first 3 full years of that unit's operation.

"Green hydrogen" means a power plant technology in which an EGU creates electric power exclusively from electrolytic hydrogen, in a manner that produces zero carbon and copollutant emissions, using hydrogen fuel that is electrolyzed using a 100% renewable zero carbon emission energy source.

"Large greenhouse gas-emitting unit" or "large GHG-emitting unit" means a unit that is an electric generating unit or other fossil fuel-fired unit that itself has a nameplate capacity or serves a generator that has a nameplate capacity greater than 25 MWe and that produces electricity, including, but not limited to, coal-fired, coal-derived, oil-fired, natural gas-fired, and cogeneration units.

"NO_x emission rate" means the plant annual NO_x total output emission rate as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrated Database (eGrid), or its successor, in the most recent year for which data is available.

"Public greenhouse gas-emitting units" or "public GHG-emitting unit" means large greenhouse gas-emitting units, including EGUs, that are wholly owned, directly or indirectly, by one or more municipalities, municipal corporations, joint municipal electric power agencies, electric cooperatives, or other governmental or nonprofit entities, whether organized and created under the laws of Illinois or another state.

"SO₂ emission rate" means the "plant annual SO₂ total output emission rate" as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrated Database (eGrid), or its successor, in the most recent year for which data is available.

(g) All EGUs and large greenhouse gas-emitting units that use coal or oil as a fuel and are not public GHG-emitting units shall permanently reduce all CO₂e and copollutant emissions to zero no later than January 1, 2030.

(h) All EGUs and large greenhouse gas-emitting units that use coal as a fuel and are public GHG-emitting units shall permanently reduce CO₂e emissions to zero no later than December 31, 2045. Any source or plant with such units must also reduce their CO₂e emissions by 45% from existing emissions by no later than January 1, 2035. If the emissions reduction requirement is not achieved by December 31, 2035, the plant shall retire one or more units or otherwise reduce its CO₂e emissions by 45% from existing emissions by June 30, 2038.

(i) All EGUs and large greenhouse gas-emitting units that use gas as a fuel and are not public GHG-emitting units shall permanently reduce all CO₂e and copollutant emissions to zero, including through unit retirement or the use of 100% green hydrogen or other similar technology that is commercially proven to achieve zero carbon emissions, according to the following:

(1) No later than January 1, 2030: all EGUs and large greenhouse gas-emitting units that have a NO_x emissions rate of greater than 0.12 lbs/MWh or a SO₂ emission rate of greater than 0.006 lb/MWh, and are located in or within 3 miles of an environmental justice community designated as of January 1, 2021 or an equity investment eligible community.

(2) No later than January 1, 2040: all EGUs and large greenhouse gas-emitting units that have a NO_x emission rate of greater than 0.12 lbs/MWh or a SO₂ emission rate greater than 0.006 lb/MWh, and are not located in or within 3 miles of an environmental justice community designated as of January 1, 2021 or an equity investment eligible community. After January 1, 2035, each such EGU and large greenhouse gas-emitting unit shall reduce its CO₂e emissions by at least 50% from its existing emissions for CO₂e, and shall be limited in operation to, on average, 6 hours or less per day, measured over a calendar year, and shall not run for more than 24 consecutive hours except in emergency conditions, as designated by a Regional Transmission Organization or Independent System Operator.

(3) No later than January 1, 2035: all EGUs and large greenhouse gas-emitting units that began operation prior to the effective date of this amendatory Act of the 102nd General Assembly and have a NO_x emission rate of less than or equal to 0.12 lb/MWh and a SO₂ emission rate less than or equal to 0.006 lb/MWh, and are located in or within 3 miles of an environmental justice community designated as of January 1, 2021 or an equity investment eligible community. Each such EGU and large greenhouse gas-emitting unit shall reduce its CO₂e emissions by at least 50% from its existing emissions for CO₂e no later than January 1, 2030.

(4) No later than January 1, 2040: All remaining EGUs and large greenhouse gas-emitting units that have a heat rate greater than or equal to 7000 BTU/kWh. Each such EGU and Large greenhouse gas-emitting unit shall reduce its CO₂e emissions by at least 50% from its existing emissions for CO₂e no later than January 1, 2035.

(5) No later than January 1, 2045: all remaining EGUs and large greenhouse gas-emitting units.

(j) All EGUs and large greenhouse gas-emitting units that use gas as a fuel and are public GHG-emitting units shall permanently reduce all CO₂e and copollutant emissions to zero, including through unit retirement or the use of 100% green hydrogen or other similar technology that is commercially proven to achieve zero carbon emissions by January 1, 2045.

(k) All EGUs and large greenhouse gas-emitting units that utilize combined heat and power or cogeneration technology shall permanently reduce all CO₂e and copollutant emissions to zero, including through unit retirement or the use of 100% green hydrogen or other similar technology that is commercially proven to achieve zero carbon emissions by January 1, 2045.

(k-5) No EGU or large greenhouse gas-emitting unit that uses gas as a fuel and is not a public GHG-emitting unit may emit, in any 12-month period, CO₂e or copollutants in excess of that unit's existing emissions for those pollutants.

(l) Notwithstanding subsections (g) through (k-5), large GHG-emitting units including EGUs may temporarily continue emitting CO₂e and copollutants after any applicable deadline specified in any of subsections (g) through (k-5) if it has been determined, as described in paragraphs (1) and (2) of this subsection, that ongoing operation of the EGU is necessary to maintain power grid supply and reliability or ongoing operation of large GHG-emitting unit that is not an EGU is necessary to serve as an emergency backup to operations. Up to and including the occurrence of an emission reduction deadline under subsection (i), all EGUs and large GHG-emitting units must comply with the following terms:

(1) if an EGU or large GHG-emitting unit that is a participant in a regional transmission organization intends to retire, it must submit documentation to the appropriate regional transmission organization by the appropriate deadline that meets all applicable regulatory requirements necessary to obtain approval to permanently cease operating the large GHG-emitting unit;

(2) if any EGU or large GHG-emitting unit that is a participant in a regional transmission organization receives notice that the regional transmission organization has determined that continued operation of the unit is required, the unit may continue operating until the issue identified by the regional transmission organization is resolved. The owner or operator of the unit must cooperate with the regional transmission organization in resolving the issue and must reduce its emissions to zero, consistent with the requirements under subsection (g), (h), (i), (j), (k), or (k-5), as applicable, as soon as practicable when the issue identified by the regional transmission organization is resolved; and

(3) any large GHG-emitting unit that is not a participant in a regional transmission organization shall be allowed to continue emitting CO₂e and copollutants after the zero-emission date specified in subsection (g), (h), (i), (j), (k), or (k-5), as applicable, in the capacity of an emergency backup unit if approved by the Illinois Commerce Commission.

(m) No variance, adjusted standard, or other regulatory relief otherwise available in this Act may be granted to the emissions reduction and elimination obligations in this Section.

(n) By June 30 of each year, beginning in 2025, the Agency shall prepare and publish on its website a report setting forth the actual greenhouse gas emissions from individual units and the aggregate statewide emissions from all units for the prior year.

(o) Every 5 years beginning in 2025, the Environmental Protection Agency, Illinois Power Agency, and Illinois Commerce Commission shall jointly prepare, and release publicly, a report to the General Assembly that examines the State's current progress toward its renewable energy resource development goals, the status of CO₂e and copollutant emissions reductions, the current status and progress toward developing and implementing green hydrogen technologies, the current and projected status of electric resource adequacy and reliability throughout the State for the period beginning 5 years ahead, and proposed solutions for any findings. The Environmental Protection Agency, Illinois Power Agency, and Illinois Commerce Commission shall consult PJM Interconnection, LLC and Midcontinent Independent System Operator, Inc., or their respective successor organizations regarding forecasted resource adequacy and reliability needs, anticipated new generation interconnection, new transmission development or upgrades, and any announced large GHG-emitting unit closure dates and include this information in the report. The report shall be released publicly by no later than December 15 of the year it is prepared. If the Environmental Protection Agency, Illinois Power Agency, and Illinois Commerce Commission jointly conclude in the report that the data from the regional grid operators, the pace of renewable energy development, the pace of development of energy storage and demand response utilization, transmission capacity, and the CO₂e and copollutant emissions reductions required by subsection (i) or (k-5) reasonably demonstrate that a resource adequacy shortfall will occur, including whether there will be sufficient in-state capacity to meet the zonal requirements of MISO Zone 4 or the PJM ComEd Zone, per the requirements of the regional transmission organizations, or that the regional transmission operators determine that a reliability violation will occur during the time frame the study is evaluating, then the Illinois Power Agency, in conjunction with the Environmental Protection Agency shall develop a plan to reduce or delay CO₂e and copollutant emissions reductions requirements only to the extent and for the duration necessary to meet the resource adequacy and reliability needs of the State, including allowing any plants whose emission reduction deadline has been identified in the plan as creating a reliability concern to continue operating, including operating with reduced emissions or as emergency backup where appropriate. The plan shall also consider the use of renewable energy, energy storage, demand response, transmission development, or other strategies to resolve the identified resource adequacy shortfall or reliability violation.

(1) In developing the plan, the Environmental Protection Agency and the Illinois Power Agency shall hold at least one workshop open to, and accessible at a time and place convenient to, the public and shall consider any comments made by stakeholders or the public. Upon development of the plan, copies of the plan shall be posted and made publicly available on the Environmental Protection Agency's, the Illinois Power Agency's, and the Illinois Commerce Commission's websites. All interested parties shall have 60 days following the date of posting to provide comment to the Environmental Protection Agency and the Illinois Power Agency on the plan. All comments submitted to the Environmental Protection Agency and the Illinois Power Agency shall be encouraged to be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Environmental Protection Agency's, the Illinois Power Agency's, and the Illinois Commerce Commission's websites. Within 30 days following the end of the 60-day review period, the Environmental Protection Agency and the Illinois Power Agency shall revise the plan as necessary based on the comments received and file its revised plan with the Illinois Commerce Commission for approval.

(2) Within 60 days after the filing of the revised plan at the Illinois Commerce Commission, any person objecting to the plan shall file an objection with the Illinois Commerce Commission. Within 30 days after the expiration of the comment period, the Illinois Commerce Commission shall determine whether an evidentiary hearing is necessary. The Illinois Commerce Commission shall also host 3 public hearings within 90 days after the plan is filed. Following the evidentiary and public hearings, the Illinois Commerce Commission shall enter its order approving or approving with modifications the reliability mitigation plan within 180 days.

(3) The Illinois Commerce Commission shall only approve the plan if the Illinois Commerce Commission determines that it will resolve the resource adequacy or reliability deficiency identified in the reliability mitigation plan at the least amount of CO₂e and copollutant emissions, taking into consideration the emissions impacts on environmental justice communities, and that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account the impact of increases in emissions.

(4) If the resource adequacy or reliability deficiency identified in the reliability mitigation plan is resolved or reduced, the Environmental Protection Agency and the Illinois Power Agency may file an amended plan adjusting the reduction or delay in CO₂e and copollutant emission reduction requirements identified in the plan.

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

(Text of Section after amendment by P.A. 104-458)

Sec. 9.15. Greenhouse gases.

(a) An air pollution construction permit shall not be required due to emissions of greenhouse gases if the equipment, site, or source is not subject to regulation, as defined by 40 CFR 52.21, as now or hereafter amended, for greenhouse gases or is otherwise not addressed in this Section or by the Board in regulations for greenhouse gases. These exemptions do not relieve an owner or operator from the obligation to comply with other applicable rules or regulations.

(b) An air pollution operating permit shall not be required due to emissions of greenhouse gases if the equipment, site, or source is not subject to regulation, as defined by Section 39.5 of this Act, for greenhouse gases or is otherwise not addressed in this Section or by the Board in regulations for greenhouse gases. These exemptions do not relieve an owner or operator from the obligation to comply with other applicable rules or regulations.

(c) (Blank).

(d) (Blank).

(e) (Blank).

(f) As used in this Section:

"Carbon dioxide emission" means the plant annual CO₂ total output emission as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrated Database (eGrid), or its successor.

"Carbon dioxide equivalent emissions" or "CO₂e" means the sum total of the mass amount of emissions in tons per year, calculated by multiplying the mass amount of each of the 6 greenhouse gases specified in Section 3.207, in tons per year, by its associated global warming potential as set forth in 40 CFR 98, subpart A, table A-1 or its successor, and then adding them all together.

"Cogeneration" or "combined heat and power" refers to any system that, either simultaneously or sequentially, produces electricity and useful thermal energy from a single fuel source.

"Copollutants" refers to the 6 criteria pollutants that have been identified by the United States Environmental Protection Agency pursuant to the Clean Air Act.

"Electric generating unit" or "EGU" means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system that serves a generator that has a nameplate capacity greater than 25 MWe and produces electricity for sale.

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

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

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

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

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

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

(2) persons whose primary residence is in a municipality, or a county with a population under 100,000, where the closure of an electric generating unit or mine has been publicly announced or the electric generating unit or mine is in the process of closing or closed within the last 5 years;

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

(4) persons who were formerly incarcerated.

"Existing emissions" means:

(1) for CO₂e, the total average tons-per-year of CO₂e emitted by the EGU or large GHG-emitting unit either in the years 2018 through 2020 or, if the unit was not yet in operation by January 1, 2018, in the first 3 full years of that unit's operation; and

(2) for any copollutant, the total average tons-per-year of that copollutant emitted by the EGU or large GHG-emitting unit either in the years 2018 through 2020 or, if the unit was not yet in operation by January 1, 2018, in the first 3 full years of that unit's operation.

"Green hydrogen" means a power plant technology in which an EGU creates electric power exclusively from electrolytic hydrogen, in a manner that produces zero carbon and copollutant emissions, using hydrogen fuel that is electrolyzed using a 100% renewable zero carbon emission energy source.

"Large greenhouse gas-emitting unit" or "large GHG-emitting unit" means a unit that is an electric generating unit or other fossil fuel-fired unit that itself has a nameplate capacity or serves a generator that has a nameplate capacity greater than 25 MWe and that produces electricity, including, but not limited to, coal-fired, coal-derived, oil-fired, natural gas-fired, and cogeneration units.

"NO_x emission rate" means the plant annual NO_x total output emission rate as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrated Database (eGrid), or its successor, in the most recent year for which data is available.

"Public greenhouse gas-emitting units" or "public GHG-emitting unit" means large greenhouse gas-emitting units, including EGUs, that are wholly owned, directly or indirectly, by one or more municipalities, municipal corporations, joint municipal electric power agencies, electric cooperatives, or other governmental or nonprofit entities, whether organized and created under the laws of Illinois or another state.

"SO₂ emission rate" means the "plant annual SO₂ total output emission rate" as measured by the United States Environmental Protection Agency in its Emissions & Generation Resource Integrated Database (eGrid), or its successor, in the most recent year for which data is available.

(g) All EGUs and large greenhouse gas-emitting units that use coal or oil as a fuel and are not public GHG-emitting units shall permanently reduce all CO₂e and copollutant emissions to zero no later than January 1, 2030.

(h) All EGUs and large greenhouse gas-emitting units that use coal as a fuel and are public GHG-emitting units shall permanently reduce CO₂e emissions to zero no later than December 31, 2045. Any source or plant with such units must also reduce their CO₂e emissions by 45% from existing emissions by no later than January 1, 2035. If the emissions reduction requirement is not achieved by December 31, 2035, the plant shall retire one or more units or otherwise reduce its CO₂e emissions by 45% from existing emissions by June 30, 2038.

(i) All EGUs and large greenhouse gas-emitting units that use gas as a fuel and are not public GHG-emitting units shall permanently reduce all CO₂e and copollutant emissions to zero, including through unit retirement or the use of 100% green hydrogen or other similar technology that is commercially proven to achieve zero carbon emissions, according to the following:

(1) No later than January 1, 2030: all EGUs and large greenhouse gas-emitting units that have a NO_x emissions rate of greater than 0.12 lbs/MWh or a SO₂ emission rate of greater than 0.006 lb/MWh, and are located in or within 3 miles of an environmental justice community designated as of January 1, 2021 or an equity investment eligible community.

(2) No later than January 1, 2040: all EGUs and large greenhouse gas-emitting units that have a NO_x emission rate of greater than 0.12 lbs/MWh or a SO₂ emission rate greater than 0.006 lb/MWh, and are not located in or within 3 miles of an environmental justice community designated as of January 1, 2021 or an equity investment eligible community. After January 1, 2035, each such EGU and large greenhouse gas-emitting unit shall reduce its CO₂e emissions by at least 50% from its existing emissions for CO₂e, and shall be limited in operation to, on average, 6 hours or less per day, measured over a calendar year, and shall not run for more than 24 consecutive hours except in emergency conditions, as designated by a Regional Transmission Organization or Independent System Operator.

(3) No later than January 1, 2035: all EGUs and large greenhouse gas-emitting units that began operation prior to the effective date of this amendatory Act of the 102nd General Assembly and have a NO_x emission rate of less than or equal to 0.12 lb/MWh and a SO₂ emission rate less than or equal to 0.006 lb/MWh, and are located in or within 3 miles of an environmental justice community designated as of January 1, 2021 or an equity investment eligible community. Each such EGU and large greenhouse gas-emitting unit shall reduce its CO₂e emissions by at least 50% from its existing emissions for CO₂e no later than January 1, 2030.

(4) No later than January 1, 2040: All remaining EGUs and large greenhouse gas-emitting units that have a heat rate greater than or equal to 7000 BTU/kWh. Each such EGU and Large greenhouse gas-emitting unit shall reduce its CO₂e emissions by at least 50% from its existing emissions for CO₂e no later than January 1, 2035.

(5) No later than January 1, 2045: all remaining EGUs and large greenhouse gas-emitting units.

(j) All EGUs and large greenhouse gas-emitting units that use gas as a fuel and are public GHG-emitting units shall permanently reduce all CO₂e and copollutant emissions to zero, including through unit retirement or the use of 100% green hydrogen or other similar technology that is commercially proven to achieve zero carbon emissions by January 1, 2045.

(k) All EGUs and large greenhouse gas-emitting units that utilize combined heat and power or cogeneration technology shall permanently reduce all CO₂e and copollutant emissions to zero, including through unit retirement or the use of 100% green hydrogen or other similar technology that is commercially proven to achieve zero carbon emissions by January 1, 2045.

(k-5) No EGU or large greenhouse gas-emitting unit that uses gas as a fuel and is not a public GHG-emitting unit may emit, in any 12-month period, CO₂e or copollutants in excess of that unit's existing emissions for those pollutants.

(l) Notwithstanding subsections (g) through (k-5), large GHG-emitting units including EGUs may temporarily continue emitting CO₂e and copollutants after any applicable deadline specified in any of subsections (g) through (k-5) if it has been determined, as described in paragraphs (1) and (2) of this subsection, that ongoing operation of the EGU is necessary to maintain power grid supply and reliability or ongoing operation of large GHG-emitting unit that is not an EGU is necessary to serve as an emergency backup to operations. Up to and including the occurrence of an emission reduction deadline under subsection (i), all EGUs and large GHG-emitting units must comply with the following terms:

(1) if an EGU or large GHG-emitting unit that is a participant in a regional transmission organization intends to retire, it must submit documentation to the appropriate regional transmission organization by the appropriate deadline that meets all applicable regulatory requirements necessary to obtain approval to permanently cease operating the large GHG-emitting unit;

(2) if any EGU or large GHG-emitting unit that is a participant in a regional transmission organization receives notice that the regional transmission organization has determined that continued operation of the unit is required, the unit may continue operating until the issue identified by the regional transmission organization is resolved. The owner or operator of the unit must cooperate with the regional transmission organization in resolving the issue and must reduce its emissions to zero, consistent with the requirements under subsection (g), (h), (i), (j), (k), or (k-5), as applicable, as soon as practicable when the issue identified by the regional transmission organization is resolved; and

(3) any large GHG-emitting unit that is not a participant in a regional transmission organization shall be allowed to continue emitting CO₂e and copollutants after the zero-emission date specified in subsection (g), (h), (i), (j), (k), or (k-5), as applicable, in the capacity of an emergency backup unit if approved by the Illinois Commerce Commission.

(m) No variance, adjusted standard, or other regulatory relief otherwise available in this Act may be granted to the emissions reduction and elimination obligations in this Section.

(n) By June 30 of each year, beginning in 2025, the Agency shall prepare and publish on its website a report setting forth the actual greenhouse gas emissions from individual units and the aggregate statewide emissions from all units for the prior year.

(o) The Environmental Protection Agency, Illinois Power Agency, and Illinois Commerce Commission shall jointly prepare, and release publicly, a report to the General Assembly that examines the State's current progress toward its renewable energy resource development goals, the status of CO₂e and copollutant emissions reductions, the current status and progress toward developing and implementing green hydrogen technologies, the current and projected status of electric resource adequacy and reliability throughout the State for the period beginning 5 years ahead, and proposed solutions for any findings. The Environmental Protection Agency, Illinois Power Agency, and Illinois Commerce Commission shall consult PJM Interconnection, LLC and Midcontinent Independent System Operator, Inc., or their respective successor organizations regarding forecasted resource adequacy and reliability needs, anticipated new generation interconnection, new transmission development or upgrades, and any announced large GHG-emitting unit closure dates and include this information in the report. The report shall be released publicly by no later than December 15 of the year it is prepared. If the Environmental Protection Agency, Illinois Power Agency, and Illinois Commerce Commission jointly conclude in the report that the data from the regional grid operators, the pace of renewable energy development, the pace of development of energy storage and demand response utilization, transmission capacity, and the CO₂e and copollutant emissions reductions required by subsection (i) or (k-5) reasonably demonstrate that a resource adequacy shortfall will occur, including whether there will be sufficient in-state capacity to meet the zonal requirements of MISO Zone 4 or the PJM ComEd Zone, per the requirements of the regional transmission organizations, or that the regional transmission operators determine that a reliability violation will occur during the time frame the study is evaluating, then the Illinois Power Agency, in conjunction with the Environmental Protection Agency shall develop a plan to reduce or delay CO₂e and copollutant emissions reductions requirements only to the extent and for the duration necessary to meet the resource adequacy and reliability needs of the State, including allowing any plants whose emission reduction deadline has been identified in the plan as creating a reliability concern to continue operating, including operating with reduced emissions or as emergency backup where appropriate. The plan shall also consider the use of renewable energy, energy storage, demand response, transmission development, or other strategies to resolve the identified resource adequacy shortfall or reliability violation.

(1) In developing the plan, the Environmental Protection Agency and the Illinois Power Agency shall hold at least one workshop open to, and accessible at a time and place convenient to, the public and shall consider any comments made by stakeholders or the public. Upon development of the plan, copies of the plan shall be posted and made publicly available on the Environmental Protection Agency's, the Illinois Power Agency's, and the Illinois Commerce Commission's websites. All interested parties shall have 60 days following the date of posting to provide comment to the Environmental Protection Agency and the Illinois Power Agency on the plan. All comments submitted to the Environmental Protection Agency and the Illinois Power Agency shall be encouraged to be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Environmental Protection Agency's, the Illinois Power Agency's, and the Illinois Commerce Commission's websites. Within 30 days following the end of the 60-day review period, the Environmental Protection Agency and the Illinois Power Agency shall revise the plan as necessary based on the comments received and file its revised plan with the Illinois Commerce Commission for approval.

(2) Within 60 days after the filing of the revised plan at the Illinois Commerce Commission, any person objecting to the plan shall file an objection with the Illinois Commerce Commission. Within 30 days after the expiration of the comment period, the Illinois Commerce Commission shall determine whether an evidentiary hearing is necessary. The Illinois Commerce Commission shall also host 3 public hearings within 90 days after the plan is filed. Following the evidentiary and public hearings, the Illinois Commerce Commission shall enter its order approving or approving with modifications the reliability mitigation plan within 180 days. The Illinois Commerce Commission may extend the period of review of the revised plan for no more than an additional 180 days.

(3) The Illinois Commerce Commission shall only approve the plan if the Illinois Commerce Commission determines that it will resolve the resource adequacy or reliability deficiency identified in the reliability mitigation plan at the least amount of CO₂e and copollutant emissions, taking into consideration the emissions impacts on environmental justice communities, and that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account the impact of increases in emissions.

(4) If the resource adequacy or reliability deficiency identified in the reliability mitigation plan is resolved or reduced, the Environmental Protection Agency and the Illinois Power Agency may file an amended plan adjusting the reduction or delay in CO₂e and copollutant emission reduction requirements identified in the plan.

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

Section 95. No acceleration or delay. Where this Act makes changes in a statute that is represented in this Act by text that is not yet or no longer in effect (for example, a Section represented by multiple versions), the use of that text does not accelerate or delay the taking effect of (i) the changes made by this Act or (ii) provisions derived from any other Public Act.".