Rep. Jay Hoffman
Filed: 10/21/2025
 
 

 
 

 
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1
AMENDMENT TO SENATE BILL 25 

2    AMENDMENT NO. ______. Amend Senate Bill 25 by replacing 
3everything after the enacting clause with the following:
 
4
"ARTICLE 1.

 
5    Section 1-1. Short title. This Article may be cited as the 
6Municipal and Cooperative Electric Utility Transparent 
7Planning Act. References in this Article to "this Act" mean 
8this Article.
 
9    Section 1-5. Legislative findings and objectives. The 
10General Assembly finds:
11        (1) Municipal and cooperative electric utilities 
12    provide electricity to more than 1,000,000 State 
13    residents.
14        (2) Municipal utilities are public bodies governed and 
15    managed by elected public officials or their appointees. 
 
 
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1    Electric cooperatives are not-for-profit, member-owned 
2    entities governed and managed by elected boards of 
3    directors chosen by their member consumers. Due to their 
4    governance structures, municipal and cooperative electric 
5    utilities are exempt from certain regulatory requirements 
6    under State and federal law.
7        (3) Because democratic elections by member-ratepayers 
8    or customers are the ultimate guarantor of the integrity 
9    and cost-effectiveness of these utilities' operations, 
10    access to information and decision-making is crucial to 
11    ensuring management of these utilities is prudent and 
12    responsive.
13        (4) While not always applicable to municipal and 
14    electric cooperatives, integrated resource planning 
15    processes have been used in other states to attempt to 
16    avoid capacity shortfalls, minimize ratepayer costs, and 
17    increase public participation in and knowledge of electric 
18    generation portfolio choices.
19        (5) It is in the long-term best interests of State 
20    electricity customers and member-ratepayers that 
21    electricity is provided by a diverse portfolio of 
22    generation resources that may include generation 
23    ownership, power supply contracts, storage resources, and 
24    demand-side programs that minimizes costs and strives to 
25    ensure reliable service to customers while considering 
26    environmental impacts and that long-term utility planning 
 
 
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1    can help facilitate the achievement of reasonable and 
2    stable rates, reliability, and State and federal 
3    environmental law through such portfolios.
4        (6) Municipal and electric cooperatives utilities 
5    should perform a comprehensive analysis of their existing 
6    portfolio and identify opportunities to minimize 
7    member-ratepayer and customer costs while maintaining 
8    reliability and meeting State and federal environmental 
9    law. 
10        (7) To ensure utilities minimize ratepayer costs while 
11    maintaining reliability and meeting State and federal 
12    environmental law, and to increase transparency and 
13    democratic participation, it is important that municipal 
14    and cooperative electric utilities participate in an 
15    integrated resource planning process with meaningful and 
16    appropriate participation and engagement.
 
17    Section 1-10. Definitions. As used in this Act:
18    "Agency" means the Illinois Power Agency.
19    "Demand-side program" means a program implemented by or on 
20behalf of a utility to reduce retail customer consumption 
21(MWh) or shift the time of consumption of energy (MW) from end 
22users, including energy efficiency programs, demand-response 
23programs, and programs for the promotion or aggregation of 
24distributed generation.
25    "Electric cooperative" has the meaning given to that term 
 
 
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1in Section 3-119 of the Public Utilities Act.
2    "Generation resource" means a facility for the generation 
3of electricity.
4    "Integrated resource plan" or "IRP" means the planning 
5process for a municipal power agency, municipality, or 
6electric cooperative to evaluate energy supply and demand in 
7order to meet long-term energy needs while minimizing costs 
8and complying with federal and State environmental 
9requirements, consistent with this Act.
10    "Municipality" has the meaning given to that term in 
11Section 11-119.1-3 of the Illinois Municipal Code.
12    "Municipal power agency" has the meaning given to that 
13term in Section 11-119.1-3 of the Illinois Municipal Code 
14excluding single project municipal power agencies that do not 
15plan for the full requirements of their members. 
16    "Renewable generation resource" means a resource for 
17generating electricity that uses wind, solar, hydro, or 
18geothermal energy.
19    "Storage resource" means a commercially available 
20technology that uses mechanical, chemical, or thermal 
21processes to store energy and deliver the stored energy as 
22electricity for use at a later time and is capable of being 
23controlled by the distribution or transmission entity managing 
24it, to enable and optimize the safe and reliable operation of 
25the electric system.
26    "Utility" means a municipal power agency, municipality, or 
 
 
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1electric cooperative, including a generation and transmission 
2electric cooperative that provides wholesale electricity to 
3one or more distribution electric cooperatives.
 
4    Section 1-15. Purpose and contents of integrated resource 
5plan. 
6    (a) Beginning on or before January 1, 2027, and every 5 
7years thereafter on or before January 1, all generation and 
8transmission electric cooperatives with members in this State, 
9all municipal power agencies, and all municipalities and 
10distribution electric cooperatives that provide electricity 
11for service to more than 7,000 retail electric customer meters 
12shall initiate an integrated resource planning process to 
13prepare and issue a preliminary integrated resource plan to be 
14posted on its website by January 1 of the following year. 
15Municipalities and electric cooperatives that are members of, 
16and have a full requirements contract with, a municipal power 
17agency or generation and transmission electric cooperative may 
18adopt the integrated resource plan of such other utility. In 
19the alternative, a municipality or electric cooperative that 
20is a member of, and has other than a full requirements contract 
21with, a municipal power agency or generation and transmission 
22electric cooperative may include the resources or resource 
23planning of the municipal power agency or generation and 
24transmission electric cooperative in its integrated resource 
25plan, and the municipal power agency or generation and 
 
 
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1transmission electric cooperative may adopt such 
2municipality's or electric cooperative's integrated resource 
3plan. An integrated resource plan completed by a utility on or 
4after January 1, 2024 shall satisfy the first integrated 
5resource plan requirement if it meets the criteria set forth 
6in subsections (b) through (d).
7    (b) The purposes of the integrated resource plan are to 
8consider and evaluate the utility's current portfolio, 
9including electrical generation, power supply contracts, 
10storage, and demand-side programs; to forecast future load 
11changes; to facilitate prudent planning with respect to 
12reliability, resources, energy and capacity procurements, 
13power supply contract expiration, and timing of generation 
14retirement; to determine what resource portfolio will maintain 
15reliability consistent with RTO obligations; to minimize cost 
16and meet State and federal environmental law; and to 
17articulate steps the utility will take to minimize customer 
18costs and consider environmental impacts through changes to 
19its current generation portfolio through construction, 
20procurement, retirement, demand-side programs, or other 
21applicable technology or processes.
22    (c) As part of the integrated resource plan development 
23process, a utility shall consider all resources reasonably 
24available or reasonably likely to be available during the 
25relevant time period to satisfy the demand for electricity 
26services for a planning period of at least 5 years, taking into 
 
 
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1account both supply-side and demand-side electric power 
2resources and cost and benefits projections for at least the 
3next 20 years.
4    (d) A utility may include the results of an all-source 
5request for proposals for generation resources and capacity 
6contracts for delivery beginning within the next 5 years in 
7its integrated resource plan. If the utility chooses not to 
8include such results, the utility must provide notice to the 
9utility's ratepayers upon issuance of the integrated resource 
10plan that states why the utility has chosen not to include the 
11results. A utility also shall include the following, at a 
12minimum, in its integrated resource plan:
13        (1) A list of all electricity generation facilities 
14    owned by the utility, in whole or in part. For each such 
15    facility, the integrated resource plan shall report:
16            (A) general location;
17            (B) ownership information, if ownership is shared 
18        with another entity;
19            (C) type of fuel;
20            (D) the date of commercial operation;
21            (E) expected useful life;
22            (F) expected retirement date for any resource 
23        expected to retire within the next 8 years, and an 
24        explanation of the reason for the retirement;
25            (G) nameplate, maximum output, and accredited 
26        capacity;
 
 
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1            (H) total MWh generated at the facility during the 
2        previous calendar year;
3            (I) the date on which the facility is anticipated 
4        to be fully depreciated; and
5            (J) any known and measurable compliance 
6        obligations, or compliance obligations reasonably 
7        expected to apply within the next 8 years, and an 
8        estimate of reasonably anticipated expenditures 
9        intended to meet those obligations.
10        (2) A list of all power purchase agreements to which 
11    the utility is a party, whether as purchaser or seller, 
12    including the following, if specified: the counterparty, 
13    general location and type of generation resource providing 
14    power per the agreement, date on which the agreement was 
15    entered into, duration of the agreement, and the energy 
16    and capacity terms of the agreement.
17        (3) A list of any sale transactions of any capacity to 
18    any purchaser.
19        (4) A list of any demand-side programs and known 
20    distributed generation.
21        (5) A narrative description of all existing 
22    transmission facilities owned by the utility, in whole or 
23    in part, that identifies anticipated transmission 
24    constraints or critical contingencies, and identification 
25    of the regional transmission organization, if any, that 
26    exercises operational control over the transmission 
 
 
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1    facility.
2        (6) A description of all transmission investment 
3    costs, disaggregated by expenditure, related to 
4    interconnection costs and other transmission system 
5    upgrades associated with a new generating resource or 
6    increased injection rights from an existing generating 
7    resource costing greater than $1,000,000 over the term of 
8    the agreement.
9        (7) A copy of the most recent FERC Form 1 filed by the 
10    utility. If no such FERC Form 1 has been filed, the utility 
11    shall provide Form EIA 860, Form EIA 861, Form EIA 412, or 
12    information applicable to the utility included in the 
13    sections of FERC Form 1 or Form EIA 412 relating to 
14    electric operating revenues, sales for resale, electric 
15    operating and maintenance expenses, purchased power, 
16    common utility plant and expenses, and electric energy 
17    accounts for the prior calendar year. The utility shall 
18    not be required to disclose any information required to be 
19    protected from disclosure by the regional transmission 
20    organizations. 
21        (8) A range of load forecasts for the 5-year planning 
22    period that incorporate varying assumptions regarding 
23    electrification, economic growth, new regulation, and 
24    major new customers, sufficient for capacity planning for 
25    the utility. Such forecasts shall include:
26            (A) all relevant underlying assumptions;
 
 
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1            (B) (i) historical analysis of hourly loads 
2        consistent with NERC and regional transmission 
3        organization reporting requirements; (ii) known or 
4        projected changes to future loads; and (iii) growth 
5        forecasts and trends by customer class or load type;
6            (C) analysis of the annual capacity and energy 
7        impact of any demand-side programs, and energy 
8        efficiency programs both current and projected;
9            (D) any reserve margin or other obligations placed 
10        on the utility by regional transmission organizations 
11        or other entity responsible for reliability standards 
12        under State or federal law; and
13            (E) a comparison of past load forecasts and actual 
14        realized load and a brief narrative description of any 
15        unforeseen events to which any discrepancy may be 
16        attributed.
17        (9) A 5-year action plan for meeting the forecasted 
18    load that reasonably minimizes customer cost taking into 
19    account load, fuel price, and regulatory uncertainty, that 
20    ensures reliability consistent with RTO obligations, and 
21    meets State and federal environmental law. As part of the 
22    action plan, the utility shall:
23            (A) Identify any generation or storage resources 
24        reasonably anticipated to be removed from service in 
25        the 5 years following the date on which the integrated 
26        resource plan is due to be completed.
 
 
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1            (B) Determine whether given forecasted load growth 
2        or unit retirements, or both, the utility will need to 
3        procure additional accredited capacity and energy, and 
4        provide a quantitative estimate of any such gap 
5        between forecasted load and supply-side resources.
6            (C) Provide a narrative description of the 
7        utility's process for evaluating possible resources to 
8        secure additional needed capacity and energy.
9            (D) Provide a narrative description of the 
10        utility's processes for assessing the economic value 
11        of existing generation; and consistent with these 
12        processes, explain whether any currently operating 
13        units could be replaced by other resources at lower 
14        cost to ratepayers while maintaining reliability.
15            (E) Identify a preferred portfolio of generation 
16        resources, which may include storage, and demand-side 
17        programs that, in the utility's judgment, meets its 
18        forecasted load and complies with State and federal 
19        environmental law, while minimizing ratepayer cost to 
20        the extent reasonably achievable in the planning 
21        period covered by the action plan. The portfolio shall 
22        incorporate any accredited capacity or other 
23        reliability requirements of any regional transmission 
24        organization of which the utility is a member.
25            (F) Describe any anticipated capital expenditures 
26        by the utility in excess of $1,000,000 at existing 
 
 
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1        generation facilities and the reason for such 
2        expenditures.
3        (10) A description of all models and methodologies 
4    used in performing the integrated resource planning 
5    process. The utility shall provide, to any member of a 
6    joint action agency or member of a generation and 
7    transmission electric cooperative, reasonable access to 
8    computer models used in the analysis that are not 
9    proprietary to the owner of the model, such as software 
10    that cannot be used without a licensing agreement, or 
11    otherwise subject to confidentiality by the modeler.
12    (e) As part of the initial integrated resource plan, the 
13utility shall identify all programs, grants, loans, or tax 
14benefits for which the utility has applied for or plans to 
15apply for pursuant to the federal Inflation Reduction Act of 
162022 and shall state whether the utility has applied for or 
17otherwise used the program, grant, loan, or tax benefit.
18    (f) Each utility shall consider and include, as part of 
19its integrated resource plan, technically feasible least-cost 
20portfolio scenarios, consistent with RTO reliability 
21obligations, for constructing or procuring renewable energy 
22resources to meet 40% of its energy needs by 2030, meeting the 
23emissions reductions requirements under Public Act 102-662, 
24and supplying 100% of its total projected load through 
25carbon-free resources in combination with storage resources 
26and demand-side programs by 2045.
 
 
 
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1    Section 1-20. Stakeholder process for municipal power 
2agencies and municipalities. Prior to the issuance of a final 
3integrated resource plan, a municipal power agency or 
4municipality required to prepare and issue an integrated 
5resource plan shall hold one or more stakeholder meetings open 
6to the municipal power agency's or municipality's ratepayers 
7and members of the public before it issues a preliminary 
8integrated resource plan and one or more such stakeholder 
9meetings after the preliminary integrated resource plan is 
10issued.
11    Notice of the meetings shall be posted to the municipal 
12power agency's or municipality's website and notice of the 
13initial meeting to customers through the normal billing 
14process not less than 30 days prior to the initial meeting, and 
15any municipality planning to adopt a municipal power agency's 
16final integrated resource plan shall post the notice to its 
17website or a link to the notice on the municipality's website 
18and provide notice of the municipal power agency's initial 
19meeting to customers through the normal billing process not 
20less than 30 days prior to the initial meeting. During the 
21first meeting the municipal power agency or municipality shall 
22describe its proposed processes for developing the integrated 
23resource plan and its core assumptions and constraints. In 
24subsequent meetings, either before or after the preliminary 
25integrated resource plan is issued, the municipal power agency 
 
 
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1or municipality shall present its proposed preferred 
2portfolio, and describe any planned retirements, capital 
3expenditures on existing generation resources likely to exceed 
4$1,000,000, and planned construction. Each meeting shall 
5provide opportunity for meaningful public engagement including 
6reasonable time to ask questions, have those questions 
7answered, and to provide public comment. Meetings shall be 
8held at times accessible for working residents and shall be 
9recorded, and the municipal power agency or municipality may 
10consider language interpretation needs for non-English 
11speaking ratepayers in areas with a significant proportion of 
12non-English speaking residents. Following the meeting, the 
13municipal power agency or municipality shall provide attendees 
14with a reasonable means of providing public comment in writing 
15and of accessing the recording.
 
16    Section 1-25. Procedures for preliminary and final 
17integrated resource plans for municipal power agencies and 
18municipalities. 
19    (a) Each municipal power agency or municipality shall 
20issue its preliminary integrated resource plan, as set forth 
21in this Act, and post it publicly to the website maintained by 
22the municipal power agency or municipality by January 1, 12 
23months following the date of the calendar year for which the 
24planning is required to begin. Any municipality planning to 
25adopt a municipal power agency's final integrated resource 
 
 
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1plan shall post the preliminary integrated resource plan 
2publicly to its website or a link to it on the municipality's 
3website. 
4    (b) The municipal power agency or municipality shall 
5facilitate public comment on the preliminary integrated 
6resource plan, as follows:
7        (1) upon issuance of the preliminary integrated 
8    resource plan, the municipal power agency or municipality 
9    and any municipality planning to adopt a municipal power 
10    agency's final integrated resource plan shall post the 
11    preliminary integrated resource plan or a link to it 
12    publicly on its website. The plan shall remain publicly 
13    accessible for at least 60 days;
14        (2) the municipal power agency or municipality shall 
15    hold one or more public meetings, in person with remote 
16    access, where it shall make a representative available to 
17    address questions about the preliminary integrated 
18    resource plan. The meetings shall be held no sooner than 
19    15 days, and no later than 45 days, after the preliminary 
20    integrated resource plan is made available to the public;
21        (3) the municipal power agency or municipality shall 
22    accept public comments on the preliminary integrated 
23    resource plan for 30 days following its public posting via 
24    website, email, or mail. The municipal power agency or 
25    municipality may extend this public comment period by an 
26    additional 30 days upon request by ratepayers of the 
 
 
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1    municipal power agency or municipality or any entity that 
2    plans to adopt the municipal power agency's or 
3    municipality's final integrated resource plan; and
4        (4) The municipal power agency or municipality shall 
5    review public comments and provide responses that 
6    reasonably address all relevant issues or questions raised 
7    by such comments. The municipal power agency or 
8    municipality may modify its preliminary integrated 
9    resource plan in response to these comments. The municipal 
10    power agency or municipality shall prepare a document with 
11    responses to public comments and submit this response 
12    document to the Agency no later than 90 days after the 
13    close of the comment period. This response document shall 
14    be posted publicly on the municipality's or municipal 
15    power agency's websites, as relevant, and on the website 
16    of the Illinois Power Agency's website along with the 
17    preliminary integrated resource plan, as submitted, and 
18    any revisions made by the municipal power agency or 
19    municipality in response to public comments.
20    (c) The Illinois Power Agency shall maintain public access 
21to all integrated resource plans submitted pursuant to this 
22Act, accessible through the Illinois Power Agency's website, 
23for no less than 10 years following each integrated resource 
24plan's initial submission.
 
25    Section 1-27. Member input and process for electric 
 
 
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1cooperatives completing an integrated resource plan. 
2    (a) Each electric cooperative completing an integrated 
3resource plan shall post its preliminary integrated resource 
4plan on its website no later than 60 days after completion of 
5the preliminary integrated resource plan. Any distribution 
6electric cooperative intending to adopt a generation and 
7transmission cooperative's integrated resource plan pursuant 
8to Section 1-15 of this Act must also post the preliminary 
9integrated resource plan or a link to the preliminary 
10integrated resource plan on its own website. The preliminary 
11integrated resource plan must remain publicly accessible for 
12at least 60 days.
13    (b) After posting the preliminary integrated resource 
14plan, but before completion of a final integrated resource 
15plan, an electric cooperative preparing such a plan shall hold 
16at least one meeting open to its members, including members of 
17any member distribution cooperative and any other electric 
18cooperative adopting the integrated resource plan. An electric 
19cooperative intending to adopt the integrated resource plan 
20pursuant to Section 1-15 of this Act may, but is not required 
21to, hold its own meeting. If all other provisions of Section 
221-15 are met, an electric cooperative may utilize its annual 
23meeting of members to comply with the meeting requirements set 
24forth in this Section.
25    (c) Notice of any meeting held pursuant to this Section 
26shall be posted on the website of any electric cooperative 
 
 
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1whose members are eligible to attend the meeting and, if 
2applicable, provided to members through the electric 
3cooperative's normal billing process or regular communication 
4channel, at least 30 days prior to the meeting. An electric 
5cooperative intending to adopt the integrated resource plan 
6pursuant to Section 1-15 of this Act shall post the meeting 
7notice on its own website and notify members using the same 
8timeline and methods.
9    (d) Each meeting shall provide an opportunity for 
10meaningful member participation, including sufficient time for 
11members to submit comments, ask questions, and receive 
12responses. Meetings shall be held at times convenient for 
13working members. The electric cooperative may consider 
14language interpretation needs for non-English speaking members 
15in areas with a significant non-English speaking population. 
16At a minimum, the electric cooperative shall present the 
17following information at the meeting:
18        (1) the purpose and process of developing an 
19    integrated resource plan;
20        (2) the electric cooperative's process for developing 
21    the integrated resource plan;
22        (3) the assumptions and scenarios considered by the 
23    electric cooperative;
24        (4) an overview of supply and demand size resources 
25    used to meet energy and capacity needs; and
26        (5) historical energy and capacity data, along with 
 
 
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1    assumptions regarding future load changes. 
2    (e) Following the meeting, the electric cooperative shall 
3provide a reasonable opportunity for members to submit written 
4comments for at least 30 days. The electric cooperative shall 
5review written comments and prepare a response document that 
6summarizes and addresses relevant member comments. The 
7electric cooperative shall post the response document on its 
8website within 90 days after the close of the comment period. 
9The electric cooperative may modify its preliminary integrated 
10resource plan in response to comments. If the electric 
11cooperative revises its preliminary integrated resource plan 
12in response to comments, it shall post the modified 
13preliminary integrated resource plan on its website.
14    (f) The Illinois Power Agency shall maintain a copy or a 
15link to an electric cooperative's integrated resource plan 
16completed pursuant to this Act on the Agency's website, for at 
17least 10 years from the date of each plan's initial 
18submission.
19    (g) An electric cooperative completing an integrated 
20resource plan may select their own consulting firm, complete 
21internally, or select a prequalified consulting firm from the 
22list maintained by the Agency.
 
23    Section 1-30. IRP prequalified consulting firm list. 
24    (a) The Illinois Power Agency shall maintain a list of 
25qualified consulting firms for the purpose of developing 
 
 
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1integrated resource plans on behalf of the utility. In order 
2to prequalify a consulting firm must have:
3        (1) direct previous experience preparing integrated 
4    resource plans for utilities; assembling power supply 
5    plans or portfolios for utilities;
6        (2) one or more employees with an advanced degree in 
7    economics, mathematics, engineering, risk management, or a 
8    related area of study;
9        (3) 10 years of experience in the electricity sector;
10        (4) expertise in wholesale electricity market rules, 
11    market planning, market development, and market modeling. 
12    This includes, but is not limited to, expertise in current 
13    and ongoing FERC Order implementation into RTO markets, 
14    RTO governing documents, including, but not limited to, 
15    transmission planning processes, and resource planning; 
16        (5) expertise in wholesale electricity market rules, 
17    including those established by the federal Energy 
18    Regulatory Commission and regional transmission 
19    organizations; and
20        (6) adequate resources to perform and fulfill the 
21    required functions and responsibilities.
22    (b) No later than January 1, 2026 or the effective date of 
23this Act, whichever is later, the Illinois Power Agency shall 
24issue a Request for Information seeking responses from 
25consulting firms. Responses will be due within 45 days of that 
26issuance. The Agency will review responses and within 45 days 
 
 
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1produce a list of prequalified consulting firms that the 
2Agency determines meet all of the prequalification 
3requirements contained in subsection (a) of this Section. A 
4firm determined not to meet the requirements may request to 
5submit additional information to the Agency for 
6reconsideration. If the Agency subsequently determines a firm 
7meets the requirements, the Agency shall add the firm to the 
8list.
9    The list will be updated as additional consulting firms 
10request to be added to the list and the Agency determines they 
11meet the requirements contained in subsection (a) of this 
12Section 1-30. The Agency shall not arbitrarily or capriciously 
13deny inclusion to any qualified vendor that satisfies the 
14minimum qualifications set forth in this Section 1-30.
15    (c) The Illinois Power Agency shall publish the list of 
16prequalified consulting firms on its website. Upon request, 
17the Agency shall also provide each prequalified consulting 
18firm's response to the Request for Information to the affected 
19utility.
20    (d) A utility required to submit an integrated resource 
21plan may select a consulting firm on the Agency's list of 
22prequalified consulting firms to develop the integrated 
23resource plan and support stakeholder processes.
24    (e) The utility may apply for funding to offset its costs 
25for its integrated resource plan through the Small Utility 
26Clean Energy Planning Grant Program offered through the 
 
 
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1Illinois Finance Authority in its role as Climate Bank for the 
2State of Illinois, subject to funding availability or subject 
3to appropriation, and in accordance with program requirements 
4and limitations.
 
5    Section 1-32. Planning purposes of an integrated resource 
6plan. 
7    (a) Nothing in this Act shall be construed to alter any 
8regulatory authority or jurisdiction of any State agency with 
9respect to any municipal power agency, municipality, or 
10cooperative.
11    (b) The submission, posting, or publication of an 
12integrated resource plan pursuant to this Act shall not create 
13any binding obligation, commitment, or duty upon the municipal 
14power agency, municipality, or electric cooperative regarding 
15the construction, retirement, or operation of any facility, or 
16the procurement of any resource.
17    (c) Nothing in this Act shall be construed to create a 
18private right of action to enforce its provisions. 
 
19    Section 1-90. The Open Meetings Act is amended by changing 
20Section 2 as follows:
 
21    (5 ILCS 120/2)  (from Ch. 102, par. 42)
22    Sec. 2. Open meetings. 
23    (a) Openness required. All meetings of public bodies shall 
 
 
10400SB0025ham003- 23 -LRB104 07069 AAS 29208 a

1be open to the public unless excepted in subsection (c) and 
2closed in accordance with Section 2a.
3    (b) Construction of exceptions. The exceptions contained 
4in subsection (c) are in derogation of the requirement that 
5public bodies meet in the open, and therefore, the exceptions 
6are to be strictly construed, extending only to subjects 
7clearly within their scope. The exceptions authorize but do 
8not require the holding of a closed meeting to discuss a 
9subject included within an enumerated exception.
10    (c) Exceptions. A public body may hold closed meetings to 
11consider the following subjects:
12        (1) The appointment, employment, compensation, 
13    discipline, performance, or dismissal of specific 
14    employees, specific individuals who serve as independent 
15    contractors in a park, recreational, or educational 
16    setting, or specific volunteers of the public body or 
17    legal counsel for the public body, including hearing 
18    testimony on a complaint lodged against an employee, a 
19    specific individual who serves as an independent 
20    contractor in a park, recreational, or educational 
21    setting, or a volunteer of the public body or against 
22    legal counsel for the public body to determine its 
23    validity. However, a meeting to consider an increase in 
24    compensation to a specific employee of a public body that 
25    is subject to the Local Government Wage Increase 
26    Transparency Act may not be closed and shall be open to the 
 
 
10400SB0025ham003- 24 -LRB104 07069 AAS 29208 a

1    public and posted and held in accordance with this Act.
2        (2) Collective negotiating matters between the public 
3    body and its employees or their representatives, or 
4    deliberations concerning salary schedules for one or more 
5    classes of employees.
6        (3) The selection of a person to fill a public office, 
7    as defined in this Act, including a vacancy in a public 
8    office, when the public body is given power to appoint 
9    under law or ordinance, or the discipline, performance or 
10    removal of the occupant of a public office, when the 
11    public body is given power to remove the occupant under 
12    law or ordinance. 
13        (4) Evidence or testimony presented in open hearing, 
14    or in closed hearing where specifically authorized by law, 
15    to a quasi-adjudicative body, as defined in this Act, 
16    provided that the body prepares and makes available for 
17    public inspection a written decision setting forth its 
18    determinative reasoning.
19        (4.5) Evidence or testimony presented to a school 
20    board regarding denial of admission to school events or 
21    property pursuant to Section 24-24 of the School Code, 
22    provided that the school board prepares and makes 
23    available for public inspection a written decision setting 
24    forth its determinative reasoning. 
25        (5) The purchase or lease of real property for the use 
26    of the public body, including meetings held for the 
 
 
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1    purpose of discussing whether a particular parcel should 
2    be acquired.
3        (6) The setting of a price for sale or lease of 
4    property owned by the public body.
5        (7) The sale or purchase of securities, investments, 
6    or investment contracts. This exception shall not apply to 
7    the investment of assets or income of funds deposited into 
8    the Illinois Prepaid Tuition Trust Fund. 
9        (8) Security procedures, school building safety and 
10    security, and the use of personnel and equipment to 
11    respond to an actual, a threatened, or a reasonably 
12    potential danger to the safety of employees, students, 
13    staff, the public, or public property.
14        (9) Student disciplinary cases.
15        (10) The placement of individual students in special 
16    education programs and other matters relating to 
17    individual students.
18        (11) Litigation, when an action against, affecting or 
19    on behalf of the particular public body has been filed and 
20    is pending before a court or administrative tribunal, or 
21    when the public body finds that an action is probable or 
22    imminent, in which case the basis for the finding shall be 
23    recorded and entered into the minutes of the closed 
24    meeting.
25        (12) The establishment of reserves or settlement of 
26    claims as provided in the Local Governmental and 
 
 
10400SB0025ham003- 26 -LRB104 07069 AAS 29208 a

1    Governmental Employees Tort Immunity Act, if otherwise the 
2    disposition of a claim or potential claim might be 
3    prejudiced, or the review or discussion of claims, loss or 
4    risk management information, records, data, advice or 
5    communications from or with respect to any insurer of the 
6    public body or any intergovernmental risk management 
7    association or self insurance pool of which the public 
8    body is a member.
9        (13) Conciliation of complaints of discrimination in 
10    the sale or rental of housing, when closed meetings are 
11    authorized by the law or ordinance prescribing fair 
12    housing practices and creating a commission or 
13    administrative agency for their enforcement.
14        (14) Informant sources, the hiring or assignment of 
15    undercover personnel or equipment, or ongoing, prior or 
16    future criminal investigations, when discussed by a public 
17    body with criminal investigatory responsibilities.
18        (15) Professional ethics or performance when 
19    considered by an advisory body appointed to advise a 
20    licensing or regulatory agency on matters germane to the 
21    advisory body's field of competence.
22        (16) Self evaluation, practices and procedures or 
23    professional ethics, when meeting with a representative of 
24    a statewide association of which the public body is a 
25    member.
26        (17) The recruitment, credentialing, discipline or 
 
 
10400SB0025ham003- 27 -LRB104 07069 AAS 29208 a

1    formal peer review of physicians or other health care 
2    professionals, or for the discussion of matters protected 
3    under the federal Patient Safety and Quality Improvement 
4    Act of 2005, and the regulations promulgated thereunder, 
5    including 42 C.F.R. Part 3 (73 FR 70732), or the federal 
6    Health Insurance Portability and Accountability Act of 
7    1996, and the regulations promulgated thereunder, 
8    including 45 C.F.R. Parts 160, 162, and 164, by a 
9    hospital, or other institution providing medical care, 
10    that is operated by the public body.
11        (18) Deliberations for decisions of the Prisoner 
12    Review Board.
13        (19) Review or discussion of applications received 
14    under the Experimental Organ Transplantation Procedures 
15    Act.
16        (20) The classification and discussion of matters 
17    classified as confidential or continued confidential by 
18    the State Government Suggestion Award Board.
19        (21) Discussion of minutes of meetings lawfully closed 
20    under this Act, whether for purposes of approval by the 
21    body of the minutes or semi-annual review of the minutes 
22    as mandated by Section 2.06.
23        (22) Deliberations for decisions of the State 
24    Emergency Medical Services Disciplinary Review Board.
25        (23) The operation by a municipality of a municipal 
26    utility or the operation of a municipal power agency or 
 
 
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1    municipal natural gas agency when the discussion involves: 
2    (i) trade secrets or commercial or financial information 
3    obtained from a person or business where the trade secrets 
4    or commercial or financial information are furnished under 
5    a claim that they are proprietary, privileged, or 
6    confidential, and that disclosure of the trade secrets or 
7    commercial or financial information would cause 
8    competitive harm to the person or business; or 
9    commercially sensitive information contained in offers to 
10    buy or sell made in the competitive markets of a regional 
11    transmission organization; and only insofar as the 
12    discussion relates directly to such trade secrets or 
13    information; (ii) physical or cybersecurity of facilities 
14    or materials designated as Critical Energy/Electric 
15    Infrastructure Information under federal law or 
16    regulation; or (iii) ongoing contract negotiations or 
17    results of a request for proposals relating to the 
18    purchase, sale, or delivery of electricity or natural gas 
19    from nonaffiliate entities; provided however, the 
20    municipality, municipal power agency, or municipal natural 
21    gas agency shall hold at least one public meeting as to any 
22    contract discussed in whole or in part in closed session 
23    prior to final action on the contract. (i) contracts 
24    relating to the purchase, sale, or delivery of electricity 
25    or natural gas or (ii) the results or conclusions of load 
26    forecast studies.
 
 
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1        (24) Meetings of a residential health care facility 
2    resident sexual assault and death review team or the 
3    Executive Council under the Abuse Prevention Review Team 
4    Act.
5        (25) Meetings of an independent team of experts under 
6    Brian's Law. 
7        (26) Meetings of a mortality review team appointed 
8    under the Department of Juvenile Justice Mortality Review 
9    Team Act. 
10        (27) (Blank). 
11        (28) Correspondence and records (i) that may not be 
12    disclosed under Section 11-9 of the Illinois Public Aid 
13    Code or (ii) that pertain to appeals under Section 11-8 of 
14    the Illinois Public Aid Code. 
15        (29) Meetings between internal or external auditors 
16    and governmental audit committees, finance committees, and 
17    their equivalents, when the discussion involves internal 
18    control weaknesses, identification of potential fraud risk 
19    areas, known or suspected frauds, and fraud interviews 
20    conducted in accordance with generally accepted auditing 
21    standards of the United States of America.
22        (30) (Blank). 
23        (31) Meetings and deliberations for decisions of the 
24    Concealed Carry Licensing Review Board under the Firearm 
25    Concealed Carry Act. 
26        (32) Meetings between the Regional Transportation 
 
 
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1    Authority Board and its Service Boards when the discussion 
2    involves review by the Regional Transportation Authority 
3    Board of employment contracts under Section 28d of the 
4    Metropolitan Transit Authority Act and Sections 3A.18 and 
5    3B.26 of the Regional Transportation Authority Act.
6        (33) Those meetings or portions of meetings of the 
7    advisory committee and peer review subcommittee created 
8    under Section 320 of the Illinois Controlled Substances 
9    Act during which specific controlled substance prescriber, 
10    dispenser, or patient information is discussed.
11        (34) Meetings of the Tax Increment Financing Reform 
12    Task Force under Section 2505-800 of the Department of 
13    Revenue Law of the Civil Administrative Code of Illinois. 
14        (35) Meetings of the group established to discuss 
15    Medicaid capitation rates under Section 5-30.8 of the 
16    Illinois Public Aid Code. 
17        (36) Those deliberations or portions of deliberations 
18    for decisions of the Illinois Gaming Board in which there 
19    is discussed any of the following: (i) personal, 
20    commercial, financial, or other information obtained from 
21    any source that is privileged, proprietary, confidential, 
22    or a trade secret; or (ii) information specifically 
23    exempted from the disclosure by federal or State law.
24        (37) Deliberations for decisions of the Illinois Law 
25    Enforcement Training Standards Board, the Certification 
26    Review Panel, and the Illinois State Police Merit Board 
 
 
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1    regarding certification and decertification. 
2        (38) Meetings of the Ad Hoc Statewide Domestic 
3    Violence Fatality Review Committee of the Illinois 
4    Criminal Justice Information Authority Board that occur in 
5    closed executive session under subsection (d) of Section 
6    35 of the Domestic Violence Fatality Review Act. 
7        (39) Meetings of the regional review teams under 
8    subsection (a) of Section 75 of the Domestic Violence 
9    Fatality Review Act. 
10        (40) Meetings of the Firearm Owner's Identification 
11    Card Review Board under Section 10 of the Firearm Owners 
12    Identification Card Act. 
13    (d) Definitions. For purposes of this Section:
14    "Employee" means a person employed by a public body whose 
15relationship with the public body constitutes an 
16employer-employee relationship under the usual common law 
17rules, and who is not an independent contractor.
18    "Public office" means a position created by or under the 
19Constitution or laws of this State, the occupant of which is 
20charged with the exercise of some portion of the sovereign 
21power of this State. The term "public office" shall include 
22members of the public body, but it shall not include 
23organizational positions filled by members thereof, whether 
24established by law or by a public body itself, that exist to 
25assist the body in the conduct of its business.
26    "Quasi-adjudicative body" means an administrative body 
 
 
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1charged by law or ordinance with the responsibility to conduct 
2hearings, receive evidence or testimony and make 
3determinations based thereon, but does not include local 
4electoral boards when such bodies are considering petition 
5challenges.
6    (e) Final action. No final action may be taken at a closed 
7meeting. Final action shall be preceded by a public recital of 
8the nature of the matter being considered and other 
9information that will inform the public of the business being 
10conducted. 
11(Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21; 
12102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff. 
137-28-23; 103-626, eff. 1-1-25.)
 
14    Section 1-95. The Public Utilities Act is amended by 
15changing Section 8-406 as follows:
 
16    (220 ILCS 5/8-406)  (from Ch. 111 2/3, par. 8-406)
17    Sec. 8-406. Certificate of public convenience and 
18necessity. 
19    (a) No public utility not owning any city or village 
20franchise nor engaged in performing any public service or in 
21furnishing any product or commodity within this State as of 
22July 1, 1921 and not possessing a certificate of public 
23convenience and necessity from the Illinois Commerce 
24Commission, the State Public Utilities Commission, or the 
 
 
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1Public Utilities Commission, at the time Public Act 84-617 
2goes into effect (January 1, 1986), shall transact any 
3business in this State until it shall have obtained a 
4certificate from the Commission that public convenience and 
5necessity require the transaction of such business. A 
6certificate of public convenience and necessity requiring the 
7transaction of public utility business in any area of this 
8State shall include authorization to the public utility 
9receiving the certificate of public convenience and necessity 
10to construct such plant, equipment, property, or facility as 
11is provided for under the terms and conditions of its tariff 
12and as is necessary to provide utility service and carry out 
13the transaction of public utility business by the public 
14utility in the designated area.
15    (b) No public utility shall begin the construction of any 
16new plant, equipment, property, or facility which is not in 
17substitution of any existing plant, equipment, property, or 
18facility, or any extension or alteration thereof or in 
19addition thereto, unless and until it shall have obtained from 
20the Commission a certificate that public convenience and 
21necessity require such construction. Whenever after a hearing 
22the Commission determines that any new construction or the 
23transaction of any business by a public utility will promote 
24the public convenience and is necessary thereto, it shall have 
25the power to issue certificates of public convenience and 
26necessity. The Commission shall determine that proposed 
 
 
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1construction will promote the public convenience and necessity 
2only if the utility demonstrates: (1) that the proposed 
3construction is necessary to provide adequate, reliable, and 
4efficient service to its customers and is the least-cost means 
5of satisfying the service needs of its customers or that the 
6proposed construction will promote the development of an 
7effectively competitive electricity market that operates 
8efficiently, is equitable to all customers, and is the least 
9cost means of satisfying those objectives; (2) that the 
10utility is capable of efficiently managing and supervising the 
11construction process and has taken sufficient action to ensure 
12adequate and efficient construction and supervision thereof; 
13and (3) that the utility is capable of financing the proposed 
14construction without significant adverse financial 
15consequences for the utility or its customers.
16    (b-5) As used in this subsection (b-5):
17    "Qualifying direct current applicant" means an entity that 
18seeks to provide direct current bulk transmission service for 
19the purpose of transporting electric energy in interstate 
20commerce.
21    "Qualifying direct current project" means a high voltage 
22direct current electric service line that crosses at least one 
23Illinois border, the Illinois portion of which is physically 
24located within the region of the Midcontinent Independent 
25System Operator, Inc., or its successor organization, and runs 
26through the counties of Pike, Scott, Greene, Macoupin, 
 
 
10400SB0025ham003- 35 -LRB104 07069 AAS 29208 a

1Montgomery, Christian, Shelby, Cumberland, and Clark, is 
2capable of transmitting electricity at voltages of 345 
3kilovolts or above, and may also include associated 
4interconnected alternating current interconnection facilities 
5in this State that are part of the proposed project and 
6reasonably necessary to connect the project with other 
7portions of the grid.
8    Notwithstanding any other provision of this Act, a 
9qualifying direct current applicant that does not own, 
10control, operate, or manage, within this State, any plant, 
11equipment, or property used or to be used for the transmission 
12of electricity at the time of its application or of the 
13Commission's order may file an application on or before 
14December 31, 2023 with the Commission pursuant to this Section 
15or Section 8-406.1 for, and the Commission may grant, a 
16certificate of public convenience and necessity to construct, 
17operate, and maintain a qualifying direct current project. The 
18qualifying direct current applicant may also include in the 
19application requests for authority under Section 8-503. The 
20Commission shall grant the application for a certificate of 
21public convenience and necessity and requests for authority 
22under Section 8-503 if it finds that the qualifying direct 
23current applicant and the proposed qualifying direct current 
24project satisfy the requirements of this subsection and 
25otherwise satisfy the criteria of this Section or Section 
268-406.1 and the criteria of Section 8-503, as applicable to 
 
 
10400SB0025ham003- 36 -LRB104 07069 AAS 29208 a

1the application and to the extent such criteria are not 
2superseded by the provisions of this subsection. The 
3Commission's order on the application for the certificate of 
4public convenience and necessity shall also include the 
5Commission's findings and determinations on the request or 
6requests for authority pursuant to Section 8-503. Prior to 
7filing its application under either this Section or Section 
88-406.1, the qualifying direct current applicant shall conduct 
93 public meetings in accordance with subsection (h) of this 
10Section. If the qualifying direct current applicant 
11demonstrates in its application that the proposed qualifying 
12direct current project is designed to deliver electricity to a 
13point or points on the electric transmission grid in either or 
14both the PJM Interconnection, LLC or the Midcontinent 
15Independent System Operator, Inc., or their respective 
16successor organizations, the proposed qualifying direct 
17current project shall be deemed to be, and the Commission 
18shall find it to be, for public use. If the qualifying direct 
19current applicant further demonstrates in its application that 
20the proposed transmission project has a capacity of 1,000 
21megawatts or larger and a voltage level of 345 kilovolts or 
22greater, the proposed transmission project shall be deemed to 
23satisfy, and the Commission shall find that it satisfies, the 
24criteria stated in item (1) of subsection (b) of this Section 
25or in paragraph (1) of subsection (f) of Section 8-406.1, as 
26applicable to the application, without the taking of 
 
 
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1additional evidence on these criteria. Prior to the transfer 
2of functional control of any transmission assets to a regional 
3transmission organization, a qualifying direct current 
4applicant shall request Commission approval to join a regional 
5transmission organization in an application filed pursuant to 
6this subsection (b-5) or separately pursuant to Section 7-102 
7of this Act. The Commission may grant permission to a 
8qualifying direct current applicant to join a regional 
9transmission organization if it finds that the membership, and 
10associated transfer of functional control of transmission 
11assets, benefits Illinois customers in light of the attendant 
12costs and is otherwise in the public interest. Nothing in this 
13subsection (b-5) requires a qualifying direct current 
14applicant to join a regional transmission organization. 
15Nothing in this subsection (b-5) requires the owner or 
16operator of a high voltage direct current transmission line 
17that is not a qualifying direct current project to obtain a 
18certificate of public convenience and necessity to the extent 
19it is not otherwise required by this Section 8-406 or any other 
20provision of this Act. 
21    (c) As used in this subsection (c):
22    "Decommissioning" has the meaning given to that term in 
23subsection (a) of Section 8-508.1.
24    "Nuclear power reactor" has the meaning given to that term 
25in Section 8 of the Nuclear Safety Law of 2004. 
26    After the effective date of this amendatory Act of the 
 
 
10400SB0025ham003- 38 -LRB104 07069 AAS 29208 a

1103rd General Assembly, no construction shall commence on any 
2new nuclear power reactor with a nameplate capacity of more 
3than 300 megawatts of electricity to be located within this 
4State, and no certificate of public convenience and necessity 
5or other authorization shall be issued therefor by the 
6Commission, until the Illinois Emergency Management Agency and 
7Office of Homeland Security, in consultation with the Illinois 
8Environmental Protection Agency and the Illinois Department of 
9Natural Resources, finds that the United States Government, 
10through its authorized agency, has identified and approved a 
11demonstrable technology or means for the disposal of high 
12level nuclear waste, or until such construction has been 
13specifically approved by a statute enacted by the General 
14Assembly. Beginning January 1, 2026, construction may commence 
15on a new nuclear power reactor with a nameplate capacity of 300 
16megawatts of electricity or less within this State if the 
17entity constructing the new nuclear power reactor has obtained 
18all permits, licenses, permissions, or approvals governing the 
19construction, operation, and funding of decommissioning of 
20such nuclear power reactors required by: (1) this Act; (2) any 
21rules adopted by the Illinois Emergency Management Agency and 
22Office of Homeland Security under the authority of this Act; 
23(3) any applicable federal statutes, including, but not 
24limited to, the Atomic Energy Act of 1954, the Energy 
25Reorganization Act of 1974, the Low-Level Radioactive Waste 
26Policy Amendments Act of 1985, and the Energy Policy Act of 
 
 
10400SB0025ham003- 39 -LRB104 07069 AAS 29208 a

11992; (4) any regulations promulgated or enforced by the U.S. 
2Nuclear Regulatory Commission, including, but not limited to, 
3those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of 
4the Code of Federal Regulations, as from time to time amended; 
5and (5) any other federal or State statute, rule, or 
6regulation governing the permitting, licensing, operation, or 
7decommissioning of such nuclear power reactors. None of the 
8rules developed by the Illinois Emergency Management Agency 
9and Office of Homeland Security or any other State agency, 
10board, or commission pursuant to this Act shall be construed 
11to supersede the authority of the U.S. Nuclear Regulatory 
12Commission. The changes made by this amendatory Act of the 
13103rd General Assembly shall not apply to the uprate, renewal, 
14or subsequent renewal of any license for an existing nuclear 
15power reactor that began operation prior to the effective date 
16of this amendatory Act of the 103rd General Assembly. 
17    None of the changes made in this amendatory Act of the 
18103rd General Assembly are intended to authorize the 
19construction of nuclear power plants powered by nuclear power 
20reactors that are not either: (1) small modular nuclear 
21reactors; or (2) nuclear power reactors licensed by the U.S. 
22Nuclear Regulatory Commission to operate in this State prior 
23to the effective date of this amendatory Act of the 103rd 
24General Assembly. 
25    (d) In making its determination under subsection (b) of 
26this Section, the Commission shall attach primary weight to 
 
 
10400SB0025ham003- 40 -LRB104 07069 AAS 29208 a

1the cost or cost savings to the customers of the utility. The 
2Commission may consider any or all factors which will or may 
3affect such cost or cost savings, including the public 
4utility's engineering judgment regarding the materials used 
5for construction.
6    (e) The Commission may issue a temporary certificate which 
7shall remain in force not to exceed one year in cases of 
8emergency, to assure maintenance of adequate service or to 
9serve particular customers, without notice or hearing, pending 
10the determination of an application for a certificate, and may 
11by regulation exempt from the requirements of this Section 
12temporary acts or operations for which the issuance of a 
13certificate will not be required in the public interest.
14    A public utility shall not be required to obtain but may 
15apply for and obtain a certificate of public convenience and 
16necessity pursuant to this Section with respect to any matter 
17as to which it has received the authorization or order of the 
18Commission under the Electric Supplier Act, and any such 
19authorization or order granted a public utility by the 
20Commission under that Act shall as between public utilities be 
21deemed to be, and shall have except as provided in that Act the 
22same force and effect as, a certificate of public convenience 
23and necessity issued pursuant to this Section.
24    No electric cooperative shall be made or shall become a 
25party to or shall be entitled to be heard or to otherwise 
26appear or participate in any proceeding initiated under this 
 
 
10400SB0025ham003- 41 -LRB104 07069 AAS 29208 a

1Section for authorization of power plant construction and as 
2to matters as to which a remedy is available under the Electric 
3Supplier Act.
4    (f) Such certificates may be altered or modified by the 
5Commission, upon its own motion or upon application by the 
6person or corporation affected. Unless exercised within a 
7period of 2 years from the grant thereof, authority conferred 
8by a certificate of convenience and necessity issued by the 
9Commission shall be null and void.
10    No certificate of public convenience and necessity shall 
11be construed as granting a monopoly or an exclusive privilege, 
12immunity or franchise.
13    (g) A public utility that undertakes any of the actions 
14described in items (1) through (3) of this subsection (g) or 
15that has obtained approval pursuant to Section 8-406.1 of this 
16Act shall not be required to comply with the requirements of 
17this Section to the extent such requirements otherwise would 
18apply. For purposes of this Section and Section 8-406.1 of 
19this Act, "high voltage electric service line" means an 
20electric line having a design voltage of 69,000 100,000 or 
21more. For purposes of this subsection (g), a public utility 
22may do any of the following:
23        (1) replace or upgrade any existing high voltage 
24    electric service line and related facilities, 
25    notwithstanding its length or, subject to applicable 
26    Article VII requirements, ownership;
 
 
10400SB0025ham003- 42 -LRB104 07069 AAS 29208 a

1        (2) relocate any existing high voltage electric 
2    service line and related facilities, notwithstanding its 
3    length, to accommodate construction or expansion of a 
4    roadway or other transportation infrastructure; or
5        (3) construct a high voltage electric service line and 
6    related facilities that is constructed solely to serve a 
7    single customer's premises or to provide a generator 
8    interconnection to the public utility's transmission 
9    system and that will (i) pass under or over the premises 
10    owned by the customer or generator to be served; (ii) pass    
11    or under or over premises for which the customer or 
12    generator has secured the necessary right of way    
13    right-of-way; or (iii) be multi-circuited with the 
14    facilities of the public utility. 
15    (h) A public utility seeking to construct a high-voltage 
16electric service line and related facilities (Project) must 
17show that the utility has held a minimum of 2 pre-filing public 
18meetings to receive public comment concerning the Project in 
19each county where the Project is to be located, no earlier than 
206 months prior to filing an application for a certificate of 
21public convenience and necessity from the Commission. Notice 
22of the public meeting shall be published in a newspaper of 
23general circulation within the affected county once a week for 
243 consecutive weeks, beginning no earlier than one month prior 
25to the first public meeting. If the Project traverses 2 
26contiguous counties and where in one county the transmission 
 
 
10400SB0025ham003- 43 -LRB104 07069 AAS 29208 a

1line mileage and number of landowners over whose property the 
2proposed route traverses is one-fifth or less of the 
3transmission line mileage and number of such landowners of the 
4other county, then the utility may combine the 2 pre-filing 
5meetings in the county with the greater transmission line 
6mileage and affected landowners. All other requirements 
7regarding pre-filing meetings shall apply in both counties. 
8Notice of the public meeting, including a description of the 
9Project, must be provided in writing to the clerk of each 
10county where the Project is to be located. A representative of 
11the Commission shall be invited to each pre-filing public 
12meeting.
13    (h-5) A public utility seeking to construct a high-voltage 
14electric service line and related facilities must also show 
15that the Project has complied with training and competence 
16requirements under subsection (b) of Section 15 of the 
17Electric Transmission Systems Construction Standards Act. 
18    (i) For applications filed after August 18, 2015 (the 
19effective date of Public Act 99-399), the Commission shall, by 
20certified mail, notify each owner of record of land, as 
21identified in the records of the relevant county tax assessor, 
22included in the right-of-way over which the utility seeks in 
23its application to construct a high-voltage electric line of 
24the time and place scheduled for the initial hearing on the 
25public utility's application. The utility shall reimburse the 
26Commission for the cost of the postage and supplies incurred 
 
 
10400SB0025ham003- 44 -LRB104 07069 AAS 29208 a

1for mailing the notice.
2    (j) In determining whether to issue a certificate of 
3public convenience for a new electric generation facility to a 
4municipal power agency that is required to obtain such a 
5certificate to exercise its power of eminent domain pursuant 
6to Section 11-119.1-10 of the Illinois Municipal Code, the 
7Commission shall give due consideration to whether a 
8generation unit of similar size and type is part of the 
9municipal power agency's preferred portfolio or least-cost 
10plan for achieving renewable energy goals in its most recent 
11integrated resource plan, as described in subsection (d) of 
12Section 1-15 of the Municipal and Cooperative Electric Utility 
13Transparent Planning Act.    
14(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21; 
15102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff. 
166-1-24; 103-1066, eff. 2-20-25.)
 
17    Section 1-100. The General Not For Profit Corporation Act 
18of 1986 is amended by adding Section 108.22 as follows:
 
19    (805 ILCS 105/108.22 new)
20    Sec. 108.22. Distribution electric cooperatives.
21    (a) A distribution electric cooperative, as that term is 
22used in the Electric Supplier Act, shall maintain a publicly 
23accessible website and shall post the following documents and 
24information on its website:
 
 
10400SB0025ham003- 45 -LRB104 07069 AAS 29208 a

1        (1) The current bylaws.
2        (2) A schedule of all regular meetings, posted 
3    annually and updated as necessary.
4        (3) Planned agendas for all regular and special board 
5    meetings.
6        (4) Minutes of the regular session of each board 
7    meeting, posted within 30 days of their approval.
8        (5) A description of the director election process, 
9    including:
10            (A) eligibility requirements for director 
11        candidates;
12            (B) nomination procedures;
13            (C) voting methods and member instructions; and
14            (D) election timelines and deadlines.
15    (b) A distribution electric cooperative may include in its 
16bylaws procedures for accepting votes cast by mail or through 
17secure online voting platforms.
18    (c) Each distribution electric cooperative shall adopt 
19bylaws or written policies establishing a process that allows 
20members to address the board of directors on matters relevant 
21to the governance and operation of the cooperative.
 
22
ARTICLE 5.

 
23    Section 5-1. Short title. This Article may be cited as the 
24Utility Data Access Act. References in this Article to "this 
 
 
10400SB0025ham003- 46 -LRB104 07069 AAS 29208 a

1Act" mean this Article.
 
2    Section 5-5. Findings. 
3    (a) The General Assembly finds and declares that 
4optimizing energy use through whole-building utility data 
5access is in the public interest because it provides 
6consumers, building owners, utilities, and states with 
7significant economic benefits. 
8    (b) The General Assembly further finds the following:
9        (1) implementing building energy use data access 
10    legislation catalyzes the development of a strong market 
11    for building energy services which will positively impact 
12    the State's economy through significant job growth;
13        (2) improving the energy use efficiency of the 
14    existing building stock is a key strategy to help preserve 
15    the affordability of rental housing;
16        (3) energy use reductions stemming from data access 
17    can result in direct cost savings to customers and in peak 
18    load reductions that benefit all ratepayers;
19        (4) data access programs allow utilities to maximize 
20    the value of their energy use efficiency portfolio by 
21    engaging customers and directing them to energy efficiency 
22    programs and by enabling utilities to target 
23    low-performing buildings; 
24        (5) implementing building data access enables building 
25    owners in the State to qualify for certain federal and 
 
 
10400SB0025ham003- 47 -LRB104 07069 AAS 29208 a

1    other incentives to help them improve their assets;
2        (6) energy use data access is the foundation of a 
3    successful efficiency strategy and enables building owners 
4    to track energy use performance over time, set performance 
5    goals, and justify cost-effective energy use upgrades; and
6        (7) absent whole-building energy use data access 
7    legislation, building owners lack an efficient, defined 
8    process to obtain energy performance of their buildings in 
9    a manner that protects consumer confidentiality.
 
10    Section 5-10. Definitions. As used in this Act:
11    "Account holder" or "customer" means the person or entity 
12authorized to access or modify utility account details. 
13    "Aggregated usage data" means an aggregation of covered 
14usage data, where all data associated with a qualified 
15building or qualified property, including, but not limited to, 
16data from tenant meters and from owner meters, are combined 
17into one collective data point per utility data type, per time 
18period, and where any unique identifiers or other personal 
19information are removed or dissociated from individual meter 
20data.
21    "Aggregation threshold" means 3 or more unique 
22nonresidential qualified accounts or any combination of 5 or 
23more residential and nonresidential unique qualified accounts 
24of a property or building during the period for which data is 
25requested.
 
 
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1    "Benchmarking tool" means the ENERGY STAR Portfolio 
2Manager web-based tool or any prudent and cost-effective 
3alternative system or tool approved by the Commission should 
4ENERGY STAR Portfolio Manager become inoperative or no longer 
5useful to achieving the policy goals of the State of Illinois 
6that (i) enables the periodic entry of a building's energy use 
7data and other descriptive information about a building and 
8(ii) rates a building's energy efficiency against that of 
9comparable buildings nationwide.
10    "Commission" means the Illinois Commerce Commission.
11    "Covered usage data" means electric data collected from 
12one or more utility meters that reflects the quantity and 
13period of utility usage in the building, property, or portion 
14thereof.
15    "Data recipient" means:
16        (1) an owner of the property or building;
17        (2) an owner of a portion of a property with regard to 
18    covered usage data only for the utility consumption the 
19    owner or the owner's tenants, if any, pay for and consume 
20    in the owned portion;
21        (3) a tenant with regard to covered usage data only 
22    for the utility consumption the tenant or the tenant's 
23    subtenants, if any, pay for and consume in the space 
24    leased by the tenant;
25        (4) the board, in the case of a condominium or 
26    cooperative ownership of the property or building; or
 
 
10400SB0025ham003- 49 -LRB104 07069 AAS 29208 a

1        (5) an agent authorized to receive the covered usage 
2    data by anyone in paragraphs (1) through (4).
3    "Property" means:
4        (1) a single tax parcel;
5        (2) 2 or more tax parcels held in the cooperative or 
6    condominium form of ownership and governed by a single 
7    board of managers; or
8        (3) 2 or more colocated tax parcels owned or 
9    controlled by the same entity.
10    "Qualified account" means a utility account that serves 
11some or all of a building or property for which covered usage 
12data is requested and that, as affirmed by the data recipient, 
13was not controlled by the data recipient or its subsidiary 
14during the time period for which covered usage data is 
15requested.
16    "Qualified building" means a building that meets the 
17aggregation threshold.
18    "Qualified data recipient" means a data recipient with 
19respect to a qualified property or qualified building.
20    "Qualified property" means a property that meets the 
21aggregation threshold.
22    "Qualified utility" means an electric utility that serves 
23at least 500,000 customers in the State.
24    "Utility" means an entity that is an electric utility with 
25over 500,000 customers in this State and that is a public 
26utility, as defined in Section 3-105 of the Public Utilities 
 
 
10400SB0025ham003- 50 -LRB104 07069 AAS 29208 a

1Act.
2    "Utility data type" means electric.
 
3    Section 5-15. Utility data access. 
4    (a) Within 90 days after the effective date of this Act, 
5the Commission shall open a proceeding to establish by rule, 
6consistent with the Illinois Administrative Procedure Act and 
7the requirements of subsection (c), procedures to implement 
8the requirements of this Section. The Commission shall 
9consider industry best practices along with Illinois law, 
10rules, and Commission orders in developing the implementing 
11rules. The governing authority of a public utility district, 
12municipally owned utility, or cooperative utility may adopt a 
13rule adopted by the Commission.
14    (b) No later than 2 years after the effective date of this 
15Act, the Commission shall adopt procedures through the 
16rulemaking proceeding identified in subsection (a) whereby:
17        (1) a utility shall retain all consumption data for a 
18    period of not less than 2 years;
19        (2) a qualified utility shall retain usage data in the 
20    possession of the utility on the effective date of this 
21    Act or that is subsequently generated by the utility, for 
22    a period 5 years or however long the utility retains usage 
23    data in its active billing system, whichever is longer;
24        (3) a utility shall honor an account holder's 
25    authorized request to transmit the account holder's 
 
 
10400SB0025ham003- 51 -LRB104 07069 AAS 29208 a

1    covered usage data held by the utility to any entity 
2    designated by the account holder;
3        (4) a qualified data recipient with respect to a 
4    qualified building or qualified property may request that 
5    a qualified utility provide aggregated usage data for the 
6    qualified building or qualified property. Aggregated usage 
7    data shall include identifiers of all meters associated 
8    with the aggregate data and any other information needed 
9    for data quality assurance;
10        (5) a utility shall establish a tool or process to 
11    enable qualified data recipients to request data under 
12    this subsection. The tool or process shall meet 
13    specifications established by the Commission;
14        (6) the account holder request process and utility 
15    delivery of requested data shall be convenient, secure, 
16    and at the Commission's direction requests to the utility 
17    may be submitted exclusively through an online portal; and
18        (7) a utility shall provide updates or corrections to 
19    any previously provided usage information on the schedule 
20    established in paragraph (5) of subsection (d). Data 
21    recipients may request and receive timely revisions 
22    correcting any previously provided usage information. A 
23    utility shall also provide usage information on the 
24    schedule established in paragraph (5) of subsection (d).
25    (c) Any covered usage data that a utility provides to a 
26data recipient under this Section must meet the following 
 
 
10400SB0025ham003- 52 -LRB104 07069 AAS 29208 a

1requirements:
2        (1) The covered usage data must be available to be 
3    requested online except that a nonqualified utility may 
4    provide only paper request forms upon showing of good 
5    cause. A utility's validation of the requester's identity 
6    shall be consistent with, and no more onerous than, the 
7    utility's then-current practices.
8        (2) The covered usage data must be provided to the 
9    data recipient in a timeframe, frequency, and format and 
10    be delivered by a method as may be determined by the 
11    Commission.
12    (d) Any covered usage data that a qualified utility 
13provides to a data recipient under this Section must:
14        (1) be provided to the data recipient within 30 days 
15    after receiving the data recipient's valid request if the 
16    request is received after the effective date of the 
17    rulemaking identified in subsection (a) of this Section;
18        (2) for any initial upload of data to a data recipient 
19    and subject to subsection (j) of this Section, a data 
20    recipient must include all the data for the time period 
21    required in paragraph (2) of subsection (b), regardless of 
22    whether the data recipient had a business relationship 
23    with the building or property during that period;
24        (3) include all necessary data and available usage 
25    data points for data recipients to comply with reporting 
26    requirements to which they are subject, including any such 
 
 
10400SB0025ham003- 53 -LRB104 07069 AAS 29208 a

1    usage data that the utility possesses;
2        (4) be directly uploaded to the benchmarking tool 
3    account, or delivered in another format approved by the 
4    Commission, depending on utility size under subsection 
5    (e);
6        (5) be provided to the data recipient according to a 
7    schedule set by the Commission, but no less than monthly;
8        (6) be provided until the data recipient revokes the 
9    request for usage data or is no longer a data recipient or 
10    is no longer a qualified data recipient with respect to 
11    aggregated usage data;
12        (7) be accompanied by a list of all meters associated 
13    with the covered usage data, including, but not limited 
14    to, aggregated usage data, and shall be accompanied by any 
15    other information the Commission deems necessary including 
16    for data quality assurance; and
17        (8) be provided at no cost to the data recipient. 
18    (e) The Commission shall direct that covered usage data 
19shall be delivered to the data recipient in a standard format 
20consistent with the benchmarking tool at the data recipient's 
21request. The Commission shall direct electric utilities that 
22serve at least 500,000 customers in the State to provide 
23requested data by direct upload to the benchmarking tool and 
24associate the data with the data recipient's benchmarking tool 
25account.
26    (f) To ensure the validity and usefulness of covered usage 
 
 
10400SB0025ham003- 54 -LRB104 07069 AAS 29208 a

1data, the utility shall provide the best available consumption 
2and other information, consistent with the utility's records 
3as presented to account holders on the utility's customer 
4portal and captured at the meter level.
5    (g) Once covered usage data has been made available to a 
6duly authorized data recipient, such data may not be deleted 
7or altered by a utility system, except as is necessary to 
8correct errors or reflect rebills or is affected as part of the 
9utility's billing data retention policy. If previously 
10provided covered usage data is changed to correct errors, 
11notification must be provided to the data recipient.
12    (h) Within 180 days after the effective date of this Act, 
13the Commission shall adopt a standard form for a utility 
14account holder to authorize the sharing of the utility account 
15holder's covered usage data.
16    (i) For properties that do not meet the aggregation 
17threshold and therefore require account holder authorization, 
18the utility shall provide covered usage data to data 
19recipients upon account holder authorization, which:
20        (1) may be provided in Commission-approved form;
21        (2) may be provided in a lease agreement provision; 
22    and
23        (3) remains valid until the account holder revokes it, 
24    regardless of how the authorization is provided. 
25    (j) Access to covered usage data under this Section shall 
26be subject to any rules the Commission has adopted or may 
 
 
10400SB0025ham003- 55 -LRB104 07069 AAS 29208 a

1choose to adopt, if the rules do not conflict with this 
2Section. 
3    (k) Except in cases where the utility has not followed 
4processes established by this Act or the utility is grossly 
5negligent, the utility shall be held harmless for third-party 
6misuse of data shared under this Act and no cause of action may 
7be initiated against the utility for such subsequent misuse.
8    (l) A qualified utility may file for cost recovery of the 
9reasonable and prudently incurred costs of providing covered 
10usage data, including establishing, operating, and maintaining 
11data aggregation and data access services, for the Commission 
12to evaluate. A qualified utility shall make good faith efforts 
13to secure federal, State, or other relevant funding for such 
14investments in the future. Any such funding the qualified 
15utility receives shall be deducted from future revenue 
16requirements.
17    (m) The Commission may hire consultants and experts to 
18execute their responsibilities under this Act, with the 
19retention of those consultants and experts exempt from the 
20requirements of Section 20-10 of the Illinois Procurement 
21Code.
 
22
ARTICLE 90.

 
23    Section 90-5. The Department of Commerce and Economic 
24Opportunity Law of the Civil Administrative Code of Illinois 
 
 
10400SB0025ham003- 56 -LRB104 07069 AAS 29208 a

1is amended by changing Section 605-1075 as follows:
 
2    (20 ILCS 605/605-1075)
3    Sec. 605-1075. Energy Transition Assistance Fund.
4    (a) The General Assembly hereby declares that management 
5of several economic development programs requires a 
6consolidated funding source to improve resource efficiency. 
7The General Assembly specifically recognizes that properly 
8serving communities and workers impacted by the energy 
9transition requires that the Department of Commerce and 
10Economic Opportunity have access to the resources required for 
11the execution of the programs for workforce and contractor 
12development, just transition investments and community 
13support, and the implementation and administration of energy 
14and justice efforts by the State.
15    (b) The Department shall be responsible for the 
16administration of the Energy Transition Assistance Fund and 
17shall allocate funding on the basis of priorities established 
18in this Section. Each year, the Department shall determine the 
19available amount of resources in the Fund that can be 
20allocated to the programs identified in this Section, and 
21allocate the funding accordingly. The Department shall, to the 
22extent practical, consider both the short-term and long-term 
23costs of the programs and allocate funding so that the 
24Department is able to cover both the short-term and long-term 
25costs of these programs using projected revenue.
 
 
10400SB0025ham003- 57 -LRB104 07069 AAS 29208 a

1    The available funding for each year shall be allocated 
2from the Fund in the following order of priority:
3        (1) for costs related to the Clean Jobs Workforce 
4    Network Program, up to $21,000,000 annually prior to June 
5    1, 2023; and $24,333,333 annually from June 1, 2023 to May 
6    30, 2026; and $26,500,000 annually thereafter;
7        (2) for costs related to the Clean Energy Contractor 
8    Incubator Program, up to $21,000,000 annually prior to 
9    June 1, 2026 and up to $22,687,403 thereafter;
10        (3) for costs related to the Clean Energy Primes 
11    Contractor Accelerator Program, up to $9,000,000 annually;
12        (4) for costs related to the Barrier Reduction 
13    Program, up to $21,000,000 annually prior to June 1, 2026 
14    and up to $22,143,079 annually thereafter;
15        (5) for costs related to the Jobs and Environmental 
16    Justice Grant Program, up to $34,000,000 annually prior to 
17    June 1, 2026 and up to $41,000,000 annually thereafter;
18        (6) for costs related to the Returning Residents Clean 
19    Jobs Training Program, up to $6,000,000 annually;
20        (7) for costs related to Energy Transition Navigators, 
21    up to $6,000,000 annually prior to June 1, 2026 and up to 
22    $6,500,000 annually thereafter;
23        (8) for costs related to the Illinois Climate Works 
24    Preapprenticeship Program, up to $10,000,000 annually;
25        (9) for costs related to Energy Transition Community 
26    Support Grants, up to $40,000,000 annually;
 
 
10400SB0025ham003- 58 -LRB104 07069 AAS 29208 a

1        (10) for costs related to the Displaced Energy Worker 
2    Dependent Scholarship, upon request by the Illinois 
3    Student Assistance Commission, up to $1,100,000 annually;
4        (11) up to $10,000,000 annually shall be transferred 
5    to the Public Utilities Fund for use by the Illinois 
6    Commerce Commission for costs of administering the changes 
7    made to the Public Utilities Act by this amendatory Act of 
8    the 102nd General Assembly;
9        (12) up to $4,000,000 annually shall be transferred to 
10    the Illinois Power Agency Operations Fund for use by the 
11    Illinois Power Agency; and
12        (13) for costs related to the Clean Energy Jobs and 
13    Justice Fund, up to $1,000,000 annually.
14    The Department is authorized to utilize up to 10% of the 
15Energy Transition Assistance Fund for administrative and 
16operational expenses to implement the requirements of this 
17Act.
18    (b-5) Beginning January 1, 2028, at the direction of the 
19Department, the State Comptroller shall direct and the State 
20Treasurer shall transfer up to $84,800,000 annually into the 
21Electric Vehicle and Charging Fund from the Energy Transition 
22Assistance Fund for costs related to transportation 
23electrification programs, as described in Section 36 of the 
24Electric Vehicle Rebate Act. The Environmental Protection 
25Agency may use up to 3% of the annual allocation under this 
26subsection (b-5) for administrative and operational expenses.    
 
 
10400SB0025ham003- 59 -LRB104 07069 AAS 29208 a

1    (c) Within 30 days after the effective date of this 
2amendatory Act of the 102nd General Assembly, each electric 
3utility serving more than 500,000 customers in the State shall 
4report to the Department its total kilowatt-hours of energy 
5delivered during the 12 months ending on the immediately 
6preceding May 31. By October 31, 2021 and each October 31 
7thereafter, each electric utility serving more than 500,000 
8customers in the State shall report to the Department its 
9total kilowatt-hours of energy delivered during the 12 months 
10ending on the immediately preceding May 31.
11    (d) The Department shall, within 60 days after the 
12effective date of this amendatory Act of the 102nd General 
13Assembly:
14        (1) determine the amount necessary, but not more than 
15    $180,000,000, to meet the funding needs of the programs 
16    reliant upon the Energy Transition Assistance Fund as a 
17    revenue source for the period between the effective date 
18    of this amendatory Act of the 102nd General Assembly and 
19    December 31, 2021;
20        (2) determine, based on the kilowatt-hour deliveries 
21    for the 12 months ending May 31, 2021 reported by the 
22    electric utilities under subsection (c), the total energy 
23    transition assistance charge to be allocated to each 
24    electric utility for the period between the effective date 
25    of this amendatory Act of the 102nd General Assembly and 
26    December 31, 2021; and
 
 
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1        (3) report the total energy transition assistance 
2    charge applicable until December 31, 2021 to each electric 
3    utility serving more than 500,000 customers in the State 
4    and the Illinois Commerce Commission for purposes of 
5    filing the tariff pursuant to Section 16-108.30 of the 
6    Public Utilities Act.
7    (d-5) Notwithstanding subsection (d), the Department 
8shall, within 60 days after the effective date of this 
9amendatory Act of the 104th General Assembly, determine the 
10amount necessary, but not more than $192,000,000, to meet the 
11funding needs of the programs reliant upon the Energy 
12Transition Assistance Fund as a revenue source.
13    (e) The Department shall by November 30, 2021, and each 
14November 30 thereafter:
15        (1) determine the amount necessary, but not more than 
16    $180,000,000 before the effective date of this amendatory 
17    Act of the 104th General Assembly and not more than 
18    $192,000,000 after the effective date of this amendatory 
19    Act of the 104th General Assembly,, to meet the funding 
20    needs of the programs reliant upon the Energy Transition 
21    Assistance Fund as a revenue source for the immediately 
22    following calendar year;
23        (2) determine, based on the kilowatt-hour deliveries 
24    for the 12 months ending on the immediately preceding May 
25    31 reported to it by the electric utilities under 
26    subsection (c), the total energy transition assistance 
 
 
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1    charge to be allocated to each electric utility for the 
2    immediately following calendar year; and
3        (3) report the energy transition assistance charge 
4    applicable for the immediately following calendar year to 
5    each electric utility serving more than 500,000 customers 
6    in the State and the Illinois Commerce Commission for 
7    purposes of filing the tariff pursuant to Section 
8    16-108.30 of the Public Utilities Act.
9    (f) The energy transition assistance charge may not exceed 
10$192,000,000 plus the amount needed to fund the programs 
11described in subsection (b-5) $180,000,000 annually. If, at 
12the end of the calendar year, any surplus remains in the Energy 
13Transition Assistance Fund, the Department may allocate the 
14surplus from the fund in the following order of priority:
15        (1) for costs related to the development of the 
16    Stretch Energy Codes and other standards at the Capital 
17    Development Board, up to $500,000 annually, at the request 
18    of the Board;
19        (2) up to $7,000,000 annually shall be transferred to 
20    the Energy Efficiency Trust Fund and Clean Air Act Permit 
21    Fund for use by the Environmental Protection Agency for 
22    costs related to energy efficiency and weatherization, and 
23    costs of implementation, administration, and enforcement 
24    of the Clean Air Act; and
25        (3) for costs related to State fleet electrification 
26    at the Department of Central Management Services, up to 
 
 
10400SB0025ham003- 62 -LRB104 07069 AAS 29208 a

1    $10,000,000 annually, at the request of the Department.
2(Source: P.A. 102-662, eff. 9-15-21.)
 
3    Section 90-6. The Electric Vehicle Act is amended by 
4changing Sections 45 and 55 as follows:
 
5    (20 ILCS 627/45)
6    Sec. 45. Beneficial electrification.
7    (a) It is the intent of the General Assembly to decrease 
8reliance on fossil fuels, reduce pollution from the 
9transportation sector, increase access to electrification for 
10all consumers, and ensure that electric vehicle adoption and 
11increased electricity usage and demand do not place 
12significant additional burdens on the electric system and 
13create benefits for Illinois residents.
14        (1) Illinois should increase the adoption of electric 
15    vehicles in the State to 1,000,000 by 2030.
16        (2) Illinois should strive to be the best state in the 
17    nation in which to drive and manufacture electric 
18    vehicles.
19        (3) Widespread adoption of electric vehicles is 
20    necessary to electrify the transportation sector, 
21    diversify the transportation fuel mix, drive economic 
22    development, and protect air quality.
23        (4) Accelerating the adoption of electric vehicles 
24    will drive the decarbonization of Illinois' transportation 
 
 
10400SB0025ham003- 63 -LRB104 07069 AAS 29208 a

1    sector.
2        (5) Expanded infrastructure investment will help 
3    Illinois more rapidly decarbonize the transportation 
4    sector.
5        (6) Statewide adoption of electric vehicles requires 
6    increasing access to electrification for all consumers.
7        (7) Widespread adoption of electric vehicles requires 
8    increasing public access to charging equipment throughout 
9    Illinois, especially in low-income and environmental 
10    justice communities, where levels of air pollution burden 
11    tend to be higher.
12        (8) Widespread adoption of electric vehicles and 
13    charging equipment has the potential to provide customers 
14    with fuel cost savings and electric utility customers with 
15    cost-saving benefits.
16        (9) Widespread adoption of electric vehicles can 
17    improve an electric utility's electric system efficiency 
18    and operational flexibility, including the ability of the 
19    electric utility to integrate renewable energy resources 
20    and make use of off-peak generation resources that support 
21    the operation of charging equipment.
22        (10) Widespread adoption of electric vehicles should 
23    stimulate innovation, competition, and increased choices 
24    in charging equipment and networks and should also attract 
25    private capital investments and create high-quality jobs 
26    in Illinois.
 
 
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1    (b) As used in this Section:
2    "Agency" means the Environmental Protection Agency.
3    "Beneficial electrification programs" means programs that 
4lower carbon dioxide emissions, replace fossil fuel use, 
5create cost savings, improve electric grid operations, reduce 
6increases to peak demand, improve electric usage load shape, 
7and align electric usage with times of renewable generation. 
8All beneficial electrification programs shall provide for 
9incentives such that customers are induced to use electricity 
10at times of low overall system usage or at times when 
11generation from renewable energy sources is high. "Beneficial 
12electrification programs" include a portfolio of the 
13following:
14        (1) time-of-use electric rates;
15        (2) hourly pricing electric rates;
16        (3) optimized charging programs or programs that 
17    encourage charging at times beneficial to the electric 
18    grid;
19        (4) optional demand-response programs specifically 
20    related to electrification efforts;
21        (5) incentives for electrification and associated 
22    infrastructure tied to using electricity at off-peak 
23    times;
24        (6) incentives for electrification and associated 
25    infrastructure targeted to medium-duty and heavy-duty 
26    vehicles used by transit agencies;
 
 
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1        (7) incentives for electrification and associated 
2    infrastructure targeted to school buses;
3        (8) incentives for electrification and associated 
4    infrastructure for medium-duty and heavy-duty government 
5    and private fleet vehicles;
6        (9) low-income programs that provide access to 
7    electric vehicles for communities where car ownership or 
8    new car ownership is not common;
9        (10) incentives for electrification in eligible 
10    communities;
11        (11) incentives or programs to enable quicker adoption 
12    of electric vehicles by developing public charging 
13    stations in dense areas, workplaces, and low-income 
14    communities;
15        (12) incentives or programs to develop electric 
16    vehicle infrastructure that minimizes range anxiety, 
17    filling the gaps in deployment, particularly in rural 
18    areas and along highway corridors;
19        (13) incentives to encourage the development of 
20    electrification and renewable energy generation in close 
21    proximity in order to reduce grid congestion;
22        (14) offer support to low-income communities who are 
23    experiencing financial and accessibility barriers such 
24    that electric vehicle ownership is not an option; and
25        (15) other such programs as defined by the Commission.
26    "Black, indigenous, and people of color" or "BIPOC" means 
 
 
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1people who are members of the groups described in 
2subparagraphs (a) through (e) of paragraph (A) of subsection 
3(1) of Section 2 of the Business Enterprise for Minorities, 
4Women, and Persons with Disabilities Act.
5    "Commission" means the Illinois Commerce Commission.
6    "Coordinator" means the Electric Vehicle Coordinator.
7    "Electric vehicle" means a vehicle that is exclusively 
8powered by and refueled by electricity, must be plugged in to 
9charge, and is licensed to drive on public roadways. "Electric 
10vehicle" does not include electric mopeds, electric 
11off-highway vehicles, or hybrid electric vehicles and 
12extended-range electric vehicles that are also equipped with 
13conventional fueled propulsion or auxiliary engines.
14    "Electric vehicle charging station" means a station that 
15delivers electricity from a source outside an electric vehicle 
16into one or more electric vehicles.
17    "Environmental justice communities" means the definition 
18of that term based on existing methodologies and findings, 
19used and as may be updated by the Illinois Power Agency and its 
20program administrator in the Illinois Solar for All Program.
21    "Equity investment eligible community" or "eligible 
22community" means the geographic areas throughout Illinois 
23which would most benefit from equitable investments by the 
24State designed to combat discrimination and foster sustainable 
25economic growth. Specifically, "eligible community" means the 
26following areas:
 
 
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1        (1) areas where residents have been historically 
2    excluded from economic opportunities, including 
3    opportunities in the energy sector, as defined pursuant to 
4    Section 10-40 of the Cannabis Regulation and Tax Act; and
5        (2) areas where residents have been historically 
6    subject to disproportionate burdens of pollution, 
7    including pollution from the energy sector, as established 
8    by environmental justice communities as defined by the 
9    Illinois Power Agency pursuant to Illinois Power Agency 
10    Act, excluding any racial or ethnic indicators.
11    "Equity investment eligible person" or "eligible person" 
12means the persons who would most benefit from equitable 
13investments by the State designed to combat discrimination and 
14foster sustainable economic growth. Specifically, "eligible 
15person" means the following people:
16        (1) persons whose primary residence is in an equity 
17    investment eligible community;
18        (2) persons who are graduates of or currently enrolled 
19    in the foster care system; or
20        (3) persons who were formerly incarcerated.
21    "Low-income" means persons and families whose income does 
22not exceed 80% of the state median income for the current State 
23fiscal year as established by the U.S. Department of Health 
24and Human Services.
25    "Make-ready infrastructure" means the electrical and 
26construction work necessary between the distribution circuit 
 
 
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1to the connection point of charging equipment.
2    "Optimized charging programs" mean programs whereby owners 
3of electric vehicles can set their vehicles to be charged 
4based on the electric system's current demand, retail or 
5wholesale market rates, incentives, the carbon or other 
6pollution intensity of the electric generation mix, the 
7provision of grid services, efficient use of the electric 
8grid, or the availability of clean energy generation. 
9Optimized charging programs may be operated by utilities as 
10well as third parties.
11    (c) The Commission shall initiate a workshop process no 
12later than November 30, 2021 for the purpose of soliciting 
13input on the design of beneficial electrification programs 
14that the utility shall offer. The workshop shall be 
15coordinated by the Staff of the Commission, or a facilitator 
16retained by Staff, and shall be organized and facilitated in a 
17manner that encourages representation from diverse 
18stakeholders, including stakeholders representing 
19environmental justice and low-income communities, and ensures 
20equitable opportunities for participation, without requiring 
21formal intervention or representation by an attorney.
22    The stakeholder workshop process shall take into 
23consideration the benefits of electric vehicle adoption and 
24barriers to adoption, including:
25        (1) the benefit of lower bills for customers who do 
26    not charge electric vehicles;
 
 
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1        (2) benefits to the distribution system from electric 
2    vehicle usage;
3        (3) the avoidance and reduction in capacity costs from 
4    optimized charging and off-peak charging;
5        (4) energy price and cost reductions;
6        (5) environmental benefits, including greenhouse gas 
7    emission and other pollution reductions;
8        (6) current barriers to mass-market adoption, 
9    including cost of ownership and availability of charging 
10    stations;
11        (7) current barriers to increasing access among 
12    populations that have limited access to electric vehicle 
13    ownership, communities significantly impacted by 
14    transportation-related pollution, and market segments that 
15    create disproportionate pollution impacts;
16        (8) benefits of and incentives for medium-duty and 
17    heavy-duty fleet vehicle electrification;
18        (9) opportunities for eligible communities to benefit 
19    from electrification;
20        (10) geographic areas and market segments that should 
21    be prioritized for electrification infrastructure 
22    investment.
23    The workshops shall consider barriers, incentives, 
24enabling rate structures, and other opportunities for the bill 
25reduction and environmental benefits described in this 
26subsection.
 
 
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1    The workshop process shall conclude no later than February 
228, 2022. Following the workshop, the Staff of the Commission, 
3or the facilitator retained by the Staff, shall prepare and 
4submit a report, no later than March 31, 2022, to the 
5Commission that includes, but is not limited to, 
6recommendations for transportation electrification investment 
7or incentives in the following areas:
8        (i) publicly accessible Level 2 and fast-charging 
9    stations, with a focus on bringing access to 
10    transportation electrification in densely populated areas 
11    and workplaces within eligible communities;
12        (ii) medium-duty and heavy-duty charging 
13    infrastructure used by government and private fleet 
14    vehicles that serve or travel through environmental 
15    justice or eligible communities;
16        (iii) medium-duty and heavy-duty charging 
17    infrastructure used in school bus operations, whether 
18    private or public, that primarily serve governmental or 
19    educational institutions, and also serve or travel through 
20    environmental justice or eligible communities;
21        (iv) public transit medium-duty and heavy-duty 
22    charging infrastructure, developed in consultation with 
23    public transportation agencies; and
24        (v) publicly accessible Level 2 and fast-charging 
25    stations targeted to fill gaps in deployment, particularly 
26    in rural areas and along State highway corridors.
 
 
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1    The report must also identify the participants in the 
2process, program designs proposed during the process, 
3estimates of the costs and benefits of proposed programs, any 
4material issues that remained unresolved at the conclusions of 
5such process, and any recommendations for workshop process 
6improvements. The report shall be used by the Commission to 
7inform and evaluate the cost-effectiveness cost effectiveness    
8and achievement of goals within the submitted Beneficial 
9Electrification Plans.
10    (d) No later than July 1, 2022, electric utilities serving 
11greater than 500,000 customers in the State shall file a 
12Beneficial Electrification Plan with the Illinois Commerce 
13Commission for programs that start no later than January 1, 
142023. The plan shall take into consideration recommendations 
15from the workshop report described in this Section. Within 45 
16days after the filing of the Beneficial Electrification Plan, 
17the Commission shall, with reasonable notice, open an 
18investigation to consider whether the plan meets the 
19objectives and contains the information required by this 
20Section. The Commission shall determine if the proposed plan 
21is cost-beneficial and in the public interest. When 
22considering if the plan is in the public interest and 
23determining appropriate levels of cost recovery for 
24investments and expenditures related to programs proposed by 
25an electric utility, the Commission shall consider whether the 
26investments and other expenditures are designed and reasonably 
 
 
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1expected to:
2        (1) maximize total energy cost savings and rate 
3    reductions so that nonparticipants can benefit;
4        (2) address environmental justice interests by 
5    ensuring there are significant opportunities for residents 
6    and businesses in eligible communities to directly 
7    participate in and benefit from beneficial electrification 
8    programs;
9        (3) support at least a 40% investment of make-ready 
10    infrastructure incentives to facilitate the rapid 
11    deployment of charging equipment in or serving 
12    environmental justice, low-income, and eligible 
13    communities; however, nothing in this subsection is 
14    intended to require a specific amount of spending in a 
15    particular geographic area;
16        (4) support at least a 5% investment target in 
17    electrifying medium-duty and heavy-duty school bus and 
18    diesel public transportation vehicles located in or 
19    serving environmental justice, low-income, and eligible 
20    communities in order to provide those communities and 
21    businesses with greater economic investment, 
22    transportation opportunities, and a cleaner environment so 
23    they can directly benefit from transportation 
24    electrification efforts; however, nothing in this 
25    subsection is intended to require a specific amount of 
26    spending in a particular geographic area;
 
 
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1        (5) stimulate innovation, competition, private 
2    investment, and increased consumer choices in electric 
3    vehicle charging equipment and networks;
4        (6) contribute to the reduction of carbon emissions 
5    and meeting air quality standards, including improving air 
6    quality in eligible communities who disproportionately 
7    suffer from emissions from the medium-duty and heavy-duty 
8    transportation sector;
9        (7) support the efficient and cost-effective use of 
10    the electric grid in a manner that supports electric 
11    vehicle charging operations; and
12        (8) provide resources to support private investment in 
13    charging equipment for uses in public and private charging 
14    applications, including residential, multi-family, fleet, 
15    transit, community, and corridor applications.
16    The plan shall be determined to be cost-beneficial if the 
17total cost of beneficial electrification expenditures is less 
18than the net present value of increased electricity costs 
19(defined as marginal avoided energy, avoided capacity, and 
20avoided transmission and distribution system costs) avoided by 
21programs under the plan, the net present value of reductions 
22in other customer energy costs, net revenue from all electric 
23charging in the service territory, and the societal value of 
24reduced carbon emissions and surface-level pollutants, 
25particularly in environmental justice communities. The 
26calculation of costs and benefits should be based on net 
 
 
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1impacts, including the impact on customer rates.
2    The Commission shall approve, approve with modifications, 
3or reject the plan within 270 days from the date of filing. The 
4Commission may approve the plan if it finds that the plan will 
5achieve the goals described in this Section and contains the 
6information described in this Section. Proceedings under this 
7Section shall proceed according to the rules provided by 
8Article IX of the Public Utilities Act. Information contained 
9in the approved plan shall be considered part of the record in 
10any Commission proceeding under Section 16-107.6 of the Public 
11Utilities Act, provided that a final order has not been 
12entered prior to the initial filing date. The Beneficial 
13Electrification Plan shall specifically address, at a minimum, 
14the following:
15        (i) make-ready investments to facilitate the rapid 
16    deployment of charging equipment throughout the State, 
17    facilitate the electrification of public transit and other 
18    vehicle fleets in the light-duty, medium-duty, and 
19    heavy-duty sectors, and align with Agency-issued rebates 
20    for charging equipment;
21        (ii) the development and implementation of beneficial 
22    electrification programs, including time-of-use rates and 
23    their benefit for electric vehicle users and for all 
24    customers, optimized charging programs to achieve savings 
25    identified, and new contracts and compensation for 
26    services in those programs, through signals that allow 
 
 
10400SB0025ham003- 75 -LRB104 07069 AAS 29208 a

1    electric vehicle charging to respond to local system 
2    conditions, manage critical peak periods, serve as a 
3    demand response or peak resource, and maximize renewable 
4    energy use and integration into the grid;
5        (iii) optional commercial tariffs utilizing 
6    alternatives to traditional demand-based rate structures 
7    to facilitate charging for light-duty, heavy-duty, and 
8    fleet electric vehicles;
9        (iv) financial and other challenges to electric 
10    vehicle usage in low-income communities, and strategies 
11    for overcoming those challenges, particularly in 
12    communities where and for people for whom car ownership is 
13    not an option;
14        (v) methods of minimizing ratepayer impacts and 
15    exempting or minimizing, to the extent possible, 
16    low-income ratepayers from the costs associated with 
17    facilitating the expansion of electric vehicle charging;
18        (vi) plans to increase access to Level 3 Public 
19    Electric Vehicle Charging Infrastructure to serve vehicles 
20    that need quicker charging times and vehicles of persons 
21    who have no other access to charging infrastructure, 
22    regardless of whether those projects participate in 
23    optimized charging programs;
24        (vii) whether to establish charging standards for type 
25    of plugs eligible for investment or incentive programs, 
26    and if so, what standards;
 
 
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1        (viii) opportunities for coordination and cohesion 
2    with electric vehicle and electric vehicle charging 
3    equipment incentives established by any agency, 
4    department, board, or commission of the State, any other 
5    unit of government in the State, any national programs, or 
6    any unit of the federal government;
7        (ix) ideas for the development of online tools, 
8    applications, and data sharing that provide essential 
9    information to those charging electric vehicles, and 
10    enable an automated charging response to price signals, 
11    emission signals, real-time renewable generation 
12    production, and other Commission-approved or 
13    customer-desired indicators of beneficial charging times; 
14    and
15        (x) customer education, outreach, and incentive 
16    programs that increase awareness of the programs and the 
17    benefits of transportation electrification, including 
18    direct outreach to eligible communities.
19    (e) Proceedings under this Section shall proceed according 
20to the rules provided by Article IX of the Public Utilities 
21Act. Information contained in the approved plan shall be 
22considered part of the record in any Commission proceeding 
23under Section 16-107.6 of the Public Utilities Act, provided 
24that a final order has not been entered prior to the initial 
25filing date.
26    (f) The utility shall file an update to the plan on July 1, 
 
 
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12024 and every 3 years thereafter. This update shall describe 
2transportation investments made during the prior plan period, 
3investments planned for the following 24 months, and updates 
4to the information required by this Section. Beginning with 
5the first update, the    The utility shall develop the plan in 
6conjunction with the distribution system planning process 
7described in Section 16-105.17, including incorporation of 
8stakeholder feedback from that process.
9    (g) Within 35 days after the utility files its report, the 
10Commission shall, upon its own initiative, open an 
11investigation regarding the utility's plan update to 
12investigate whether the objectives described in this Section 
13are being achieved. The Commission shall determine whether 
14investment targets should be increased based on achievement of 
15spending goals outlined in the Beneficial Electrification Plan 
16and consistency with outcomes directed in the plan stakeholder 
17workshop report. If the Commission finds, after notice and 
18hearing, that the utility's plan is materially deficient, the 
19Commission shall issue an order requiring the utility to 
20devise a corrective action plan, subject to Commission 
21approval, to bring the plan into compliance with the goals of 
22this Section. The Commission's order shall be entered within 
23270 days after the utility files its annual report. The 
24contents of a plan filed under this Section shall be available 
25for evidence in Commission proceedings. However, omission from 
26an approved plan shall not render any future utility 
 
 
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1expenditure to be considered unreasonable or imprudent. The 
2Commission may, upon sufficient evidence, allow expenditures 
3that were not part of any particular distribution plan. The 
4Commission shall consider revenues from electric vehicles in 
5the utility's service territory in evaluating the retail rate 
6impact. The retail rate impact from the development of 
7electric vehicle infrastructure shall not exceed 1% per year 
8of the total annual revenue requirements of the utility.
9    (h) In meeting the requirements of this Section, the 
10utility shall demonstrate efforts to increase the use of 
11contractors and electric vehicle charging station installers 
12that meet multiple workforce equity actions, including, but 
13not limited to:
14        (1) the business is headquartered in or the person 
15    resides in an eligible community;
16        (2) the business is majority owned by eligible person 
17    or the contractor is an eligible person;
18        (3) the business or person is certified by another 
19    municipal, State, federal, or other certification for 
20    disadvantaged businesses;
21        (4) the business or person meets the eligibility 
22    criteria for a certification program such as:
23            (A) certified under Section 2 of the Business 
24        Enterprise for Minorities, Women, and Persons with 
25        Disabilities Act;
26            (B) certified by another municipal, State, 
 
 
10400SB0025ham003- 79 -LRB104 07069 AAS 29208 a

1        federal, or other certification for disadvantaged 
2        businesses;
3            (C) submits an affidavit showing that the vendor 
4        meets the eligibility criteria for a certification 
5        program such as those in items (A) and (B);
6            (D) if the vendor is a nonprofit, meets any of the 
7        criteria in those in item (A), (B), or (C) with the 
8        exception that the nonprofit is not required to meet 
9        any criteria related to being a for-profit entity, or 
10        is controlled by a board of directors that consists of 
11        51% or greater individuals who are equity investment 
12        eligible persons; or
13            (E) ensuring that program implementation 
14        contractors and electric vehicle charging station 
15        installers pay employees working on electric vehicle 
16        charging installations at or above the prevailing wage 
17        rate as published by the Department of Labor.
18    Utilities shall establish reporting procedures for vendors 
19that ensure compliance with this subsection, but are 
20structured to avoid, wherever possible, placing an undue 
21administrative burden on vendors.
22    (i) Program data collection.
23        (1) In order to ensure that the benefits provided to 
24    Illinois residents and business by the clean energy 
25    economy are equitably distributed across the State, it is 
26    necessary to accurately measure the applicants and 
 
 
10400SB0025ham003- 80 -LRB104 07069 AAS 29208 a

1    recipients of this Program. The purpose of this paragraph 
2    is to require the implementing utilities to collect all 
3    data from Program applicants and beneficiaries to track 
4    and improve equitable distribution of benefits across 
5    Illinois communities. The further purpose is to measure 
6    any potential impact of racial discrimination on the 
7    distribution of benefits and provide the utilities the 
8    information necessary to correct any discrimination 
9    through methods consistent with State and federal law.
10        (2) The implementing utilities shall collect 
11    demographic and geographic data for each applicant and 
12    each person or business awarded benefits or contracts 
13    under this Program.
14        (3) The implementing utilities shall collect the 
15    following information from applicants and Program or 
16    procurement beneficiaries where applicable:
17            (A) demographic information, including racial or 
18        ethnic identity for real persons employed, contracted, 
19        or subcontracted through the program;
20            (B) demographic information, including racial or 
21        ethnic identity of business owners;
22            (C) geographic location of the residency of real 
23        persons or geographic location of the headquarters for 
24        businesses; and
25            (D) any other information necessary for the 
26        purpose of achieving the purpose of this paragraph.
 
 
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1        (4) The utility shall publish, at least annually, 
2    aggregated information on the demographics of program and 
3    procurement applicants and beneficiaries. The utilities 
4    shall protect personal and confidential business 
5    information as necessary.
6        (5) The utilities shall conduct a regular review 
7    process to confirm the accuracy of reported data.
8        (6) On a quarterly basis, utilities shall collect data 
9    necessary to ensure compliance with this Section and shall 
10    communicate progress toward compliance to program 
11    implementation contractors and electric vehicle charging 
12    station installation vendors.
13        (7) Utilities filing Beneficial Electrification Plans 
14    under this Section shall report annually to the Illinois 
15    Commerce Commission and the General Assembly on how 
16    hiring, contracting, job training, and other practices 
17    related to its Beneficial electrification programs enhance 
18    the diversity of vendors working on such programs. These 
19    reports must include data on vendor and employee 
20    diversity.
21    (j) The provisions of this Section are severable under 
22Section 1.31 of the Statute on Statutes. 
23    (k) Any Beneficial Electrification Plan under this Section 
24shall terminate no later than December 31, 2028. Beginning 
25January 1, 2029, utilities shall continue to support 
26transportation electrification by maintaining responsibility 
 
 
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1for the following through the Multi-Year Integrated Grid Plans 
2implemented by electric utilities pursuant to Section 
316-105.17 of the Public Utilities Act:
4        (i) make-ready investments and programs that 
5    facilitate the rapid deployment of charging equipment 
6    throughout the State, especially deployment that targets 
7    medium heavy duty electrification and multi-unit 
8    buildings;
9        (ii) the development and implementation of (1) 
10    time-of-use rates and the benefit of the rates for 
11    electric vehicle users and for all customers, (2) 
12    optimized charging programs to achieve identified savings, 
13    and (3) new contracts and compensation for services in the 
14    optimized charging programs, through signals that allow 
15    electric vehicle charging to respond to local system 
16    conditions, manage critical peak periods, serve as a 
17    demand response or peak resource, and maximize renewable 
18    energy use and integration into the grid; and
19        (iii) commercial tariffs that utilize alternatives to 
20    traditional demand-based rate structures to facilitate 
21    charging for light-duty, heavy-duty, and fleet electric 
22    vehicles.
23    Utilities shall demonstrate methods of minimizing 
24ratepayer impacts and exempting or minimizing, to the extent 
25possible, low-income ratepayers from the costs associated with 
26facilitating the expansion of electric vehicle charging.
 
 
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1(Source: P.A. 102-662, eff. 9-15-21; 102-820, eff. 5-13-22; 
2103-154, eff. 6-30-23.)
 
3    (20 ILCS 627/55)
4    Sec. 55. Charging rebate program.
5    (a) In order to substantially offset the installation 
6costs of electric vehicle charging infrastructure, beginning 
7July 1, 2022, and continuing as long as funds are available, 
8the Agency shall issue rebates, consistent with the 
9Commission-approved Beneficial Electrification Plans in 
10accordance with Section 45, to public and private 
11organizations and companies to install and maintain Level 2 or 
12Level 3 charging stations.
13    (b) The Agency shall award rebates or grants that fund up 
14to 80% of the cost of the installation of charging stations. 
15The Agency shall award additional incentives per port for 
16every charging station installed in an eligible community and 
17every charging station located to support eligible persons. In 
18order to be eligible to receive a rebate or grant, the 
19organization or company must submit an application to the 
20Agency and commit to paying the prevailing wage for the 
21installation project. The Agency shall by rule provide 
22application and other programmatic details and requirements, 
23including additional incentives for eligible communities. The 
24Agency may determine per port or project caps based on a review 
25of best practices and stakeholder engagement. The Agency shall 
 
 
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1accept applications on a rolling basis and shall award rebates 
2or grants within 60 days of each application. The Agency must 
3require that any grant or rebate applicant comply with the 
4requirements of the Prevailing Wage Act for any installation 
5of a charging station for which it seeks a rebate or grant.
6    (c) This Section is repealed on January 1, 2029.    
7(Source: P.A. 102-662, eff. 9-15-21; 102-673, eff. 11-30-21.)
 
8    Section 90-7. The Energy Transition Act is amended by 
9changing Sections 5-40 and 5-60 as follows:
 
10    (20 ILCS 730/5-40)
11    (Section scheduled to be repealed on September 15, 2045)
12    Sec. 5-40. Illinois Climate Works Preapprenticeship 
13Program. 
14    (a) Subject to appropriation, the Department shall 
15develop, and through Regional Administrators administer, the 
16Illinois Climate Works Preapprenticeship Program. The goal of 
17the Illinois Climate Works Preapprenticeship Program is to 
18create a network of hubs throughout the State that will 
19recruit, prescreen, and provide preapprenticeship skills 
20training, for which participants may attend free of charge and 
21receive a stipend, to create a qualified, diverse pipeline of 
22workers who are prepared for careers in the construction and 
23building trades and clean energy jobs opportunities therein. 
24Upon completion of the Illinois Climate Works 
 
 
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1Preapprenticeship Program, the candidates will be connected to 
2and prepared to successfully complete an apprenticeship 
3program.
4    (b) Each Climate Works Hub that receives funding from the 
5Energy Transition Assistance Fund shall provide an annual 
6report to the Illinois Works Review Panel by April 1 of each 
7calendar year. The annual report shall include the following 
8information:
9        (1) a description of the Climate Works Hub's 
10    recruitment, screening, and training efforts, including a 
11    description of training related to construction and 
12    building trades opportunities in clean energy jobs;
13        (2) the number of individuals who apply to, 
14    participate in, and complete the Climate Works Hub's 
15    program, broken down by race, gender, age, and veteran 
16    status;
17        (3) the number of the individuals referenced in 
18    paragraph (2) of this subsection who are initially 
19    accepted and placed into apprenticeship programs in the 
20    construction and building trades; and
21        (4) the number of individuals referenced in paragraph 
22    (2) of this subsection who remain in apprenticeship 
23    programs in the construction and building trades or have 
24    become journeymen one calendar year after their placement, 
25    as referenced in paragraph (3) of this subsection.
26    (c) Subject to appropriation, the Department shall provide 
 
 
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1funding to 3 Climate Works Hubs throughout the State, 
2including one to the Illinois Department of Transportation 
3Region 1, one to the Illinois Department of Transportation 
4Regions 2 and 3, and one to the Illinois Department of 
5Transportation Regions 4 and 5. An eligible organization may 
6serve as the designated Climate Works Hub for all 5 regions. 
7Climate Works Hubs shall be awarded grants in multi-year 
8increments not to exceed 36 months. Each grant shall come with 
9a one year initial term, with the Department renewing each 
10year for 2 additional years unless the grantee either declines 
11to continue or fails to meet reasonable performance measures 
12that consider apprenticeship programs timeframes. The 
13Department may take into account experience and performance as 
14a previous grantee of the Climate Works Hub as part of the 
15selection criteria for subsequent years. 
16    (d) Each Climate Works Hub that receives funding from the 
17Energy Transition Assistance Fund shall recruit, prescreen, 
18and provide preapprenticeship training to program 
19participants. Each Climate Works Hub that receives funding 
20from the Energy Transition Assistance Fund shall:
21        (1) in each Hub Site where the applicant pool allows, 
22    comply with the following:
23            (A) dedicate at least one-third of Program 
24        placements to applicants who reside in a geographic 
25        area that is impacted by economic and environmental 
26        challenges, defined as an area that is both (i) an R3 
 
 
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1        Area, as defined pursuant to Section 10-40 of the 
2        Cannabis Regulation and Tax Act, and (ii) an 
3        environmental justice community, as defined by the 
4        Illinois Power Agency under the Illinois Power Agency 
5        Act, excluding any racial or ethnic indicators used by 
6        the Agency unless and until the constitutional basis 
7        for the inclusion of the factors in determining 
8        Program admissions is established; among applicants 
9        that satisfy these criteria, preference shall be given 
10        to applicants who face barriers to employment, 
11        including low educational attainment, prior 
12        involvement with the criminal justice system, and 
13        language barriers, and applicants that are graduates 
14        of or currently enrolled in the foster care system; 
15        and
16            (B) dedicate at least two-thirds of Program 
17        placements to applicants who reside in a geographic 
18        area that is impacted by economic or environmental 
19        challenges, defined as an area that is either (i) an R3 
20        Area, as defined pursuant to Section 10-40 of the 
21        Cannabis Regulation and Tax Act, or (ii) an 
22        environmental justice community, as defined by the 
23        Illinois Power Agency in the Illinois Power Agency 
24        Act, excluding any racial or ethnic indicators used by 
25        the Agency unless and until the constitutional basis 
26        for the inclusion of the factors in determining 
 
 
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1        Program admissions is established; among applicants 
2        that satisfy these criteria, preference shall be given 
3        to applicants who face barriers to employment, 
4        including low educational attainment, prior 
5        involvement with the criminal legal system, and 
6        language barriers, and applicants that are graduates 
7        of or currently enrolled in the foster care system; 
8        and
9            (C) prioritize the remaining Program placements 
10        for the following:
11                (i) applicants who are displaced energy 
12            workers, as defined in the Energy Community 
13            Reinvestment Act;
14                (ii) persons who face barriers to employment, 
15            including low educational attainment, prior 
16            involvement with the criminal justice system, and 
17            language barriers; and
18                (iii) applicants who are graduates of or 
19            currently enrolled in the foster care system, 
20            regardless of the applicant's area of residence;    
21            Each Climate Works Hub that receives funding from 
22            the Energy Transition Assistance Fund shall:
23        (1) recruit, prescreen, and provide preapprenticeship 
24    training to equity investment eligible persons;
25        (2) provide training information related to 
26    opportunities and certifications relevant to clean energy 
 
 
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1    jobs in the construction and building trades; and
2        (3) provide preapprentices with stipends they receive 
3    that may vary depending on the occupation the individual 
4    is training for. 
5    (d-5) Priority shall be given to Climate Works Hubs that 
6have an agreement with North American Building Trades Unions 
7(NABTU) to utilize the Multi-Craft Core Curriculum or 
8successor curriculums. 
9    (e) Funding for the Program is subject to appropriation 
10from the Energy Transition Assistance Fund.
11    (f) The Department shall adopt any rules deemed necessary 
12to implement this Section.
13(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22; 
14102-1123, eff. 1-27-23.)
 
15    (20 ILCS 730/5-60)
16    (Section scheduled to be repealed on September 15, 2045)
17    Sec. 5-60. Jobs and Environmental Justice Grant Program. 
18    (a) In order to provide upfront capital to support the 
19development of projects, businesses, community organizations, 
20and jobs creating opportunity for historically disadvantaged 
21populations, and to provide seed capital to support community 
22ownership of renewable energy projects, the Department of 
23Commerce and Economic Opportunity shall create and administer 
24a Jobs and Environmental Justice Grant Program. The grant 
25program shall be designed to help remove barriers to project, 
 
 
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1community, and business development caused by a lack of 
2capital. 
3    (b) The grant program shall provide grant awards of up to 
4$1,000,000 per application to support the development of 
5renewable energy resources as defined in Section 1-10 of the 
6Illinois Power Agency Act, and energy efficiency measures as 
7defined in Section 8-103B of the Public Utilities Act. The 
8amount of a grant award shall be based on a project's size and 
9scope. Grants shall be provided upfront, in advance of other 
10incentives, to provide businesses, organizations, and 
11community groups with capital needed to plan, develop, and 
12execute a project. Grants shall be designed to coordinate with 
13and supplement existing incentive programs, such as the 
14Adjustable Block program, the Illinois Solar for All Program, 
15the community renewable generation projects, and renewable 
16energy procurements as described in the Illinois Power Agency 
17Act, as well as utility energy efficiency measures as 
18described in Section 8-103B of the Public Utilities Act. 
19    (c) The Jobs and Environmental Justice Grant Program shall 
20include 2 subprograms:
21        (1) the Equitable Energy Future Grant Program; and
22        (2) the Community Solar Energy Sovereignty Grant 
23    Program.
24    (d) The Equitable Energy Future Grant Program is designed 
25to provide seed funding and pre-development funding 
26opportunities for equity eligible contractors and support for 
 
 
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1compliance with or fulfillment of project labor agreement and 
2prevailing wage requirements in the clean energy economy. 
3        (1) The Equitable Energy Future Grant shall be awarded 
4    to businesses and nonprofit organizations for costs 
5    related to the following activities and project needs: 
6            (i) planning and project development, including 
7        costs for professional services such as architecture, 
8        design, engineering, auditing, consulting, and 
9        developer services; 
10            (ii) project application, deposit, and approval; 
11            (iii) purchasing and leasing of land; 
12            (iv) permitting and zoning; 
13            (v) interconnection application costs and fees, 
14        studies, and expenses; 
15            (vi) equipment and supplies; 
16            (vii) community outreach, marketing, and 
17        engagement; and
18            (viii) staff and operations expenses; and .
19            (ix) any support needed to comply with or fulfill 
20        prevailing wage and project labor agreement 
21        requirements in the clean energy economy.    
22        (2) Grants shall be awarded to projects that most 
23    effectively provide opportunities for equity eligible 
24    contractors and equity investment eligible communities, 
25    and should consider the following criteria: 
26            (i) projects that provide community benefits, 
 
 
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1        which are projects that have one or more of the 
2        following characteristics: (A) greater than 50% of the 
3        project's energy provided or saved benefits low-income 
4        residents, or (B) the project benefits not-for-profit 
5        organizations providing services to low-income 
6        households, affordable housing owners, or 
7        community-based limited liability companies providing 
8        services to low-income households; 
9            (ii) projects that are located in equity 
10        investment eligible communities; 
11            (iii) projects that provide on-the-job training; 
12            (iv) projects that contract with contractors who 
13        are participating or have participated in the Clean 
14        Energy Contractor Incubator Program, Clean Energy 
15        Primes Contractor Accelerator Program, or similar 
16        programs; and    
17            (v) projects employ a minimum of 51% of its 
18        workforce from participants and graduates of the Clean 
19        Jobs Workforce Network Program, Illinois Climate Works 
20        Preapprenticeship Program, and Returning Residents 
21        Clean Jobs Training Program; and .
22            (vi) equity eligible contractors and contractors 
23        participating in either the Clean Energy Primes 
24        Contractor Accelerator Program or the Clean Energy 
25        Contractor Incubator Program and that demonstrate 
26        support needed on a company or project-specific basis 
 
 
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1        to comply with prevailing wage and project labor 
2        agreement requirements in the clean energy economy.    
3        (3) Grants shall be awarded to applicants that meet 
4    the following criteria: 
5            (i) are equity eligible contractors per the equity 
6        accountability systems described in subsection (c-10) 
7        of Section 1-75 of the Illinois Power Agency Act, or 
8        meet the equity building criteria in paragraph (9.5) 
9        of subsection (g) of Section 8-103B of the Public 
10        Utilities Act; and 
11            (ii) provide demonstrable proof of a historical or 
12        future, and persisting, long-term partnership with the 
13        community in which the project will be located.
14        (4) The Department may engage contractors or provide 
15    grants to nonprofit organizations in order to provide 
16    technical assistance as part of this Program to equity 
17    eligible contractors and contractors participating in 
18    either the Clean Energy Primes Contractor Accelerator 
19    Program or Clean Energy Contractor Incubator Program that 
20    need support to comply with and fulfill prevailing wage 
21    and project labor agreement requirements in the clean 
22    energy economy.    
23    (e) The Community Solar Energy Sovereignty Grant Program 
24shall be designed to support the pre-development and 
25development of community solar projects that promote community 
26ownership and energy sovereignty. 
 
 
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1        (1) Grants shall be awarded to applicants that best 
2    demonstrate the ability and intent to create community 
3    ownership and other local community benefits, including 
4    local community wealth building via community renewable 
5    generation projects. Grants shall be prioritized to 
6    applicants for whom: 
7            (i) the proposed project is located in and 
8        supporting an equity investment eligible community or 
9        communities; and
10            (ii) the proposed project provides additional 
11        benefits for participating low-income households. 
12        (2) Grant funds shall be awarded to support project 
13    pre-development work and may also be awarded to support 
14    the development of programs and entities to assist in the 
15    long-term governance, management, and maintenance of 
16    community solar projects, such as community solar 
17    cooperatives. For example, funds may be awarded for: 
18            (i) early stage project planning; 
19            (ii) project team organization; 
20            (iii) site identification; 
21            (iv) organizing a project business model and 
22        securing financing; 
23            (v) procurement and contracting;
24            (vi) customer outreach and enrollment;
25            (vii) preliminary site assessments;
26            (viii) development of cooperative or community 
 
 
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1        ownership model; and 
2            (ix) development of project models that allocate 
3        benefits to equity investment eligible communities. 
4        (3) Grant recipients shall submit reports to the 
5    Department at the end of the grant term on the activities 
6    pursued under their grant and any lessons learned for 
7    publication on the Department's website so that other 
8    energy sovereignty projects may learn from their 
9    experience. 
10        (4) Eligible applicants shall include community-based 
11    organizations, as defined in the Illinois Power Agency's 
12    long-term renewable resources procurement plan, or 
13    technical service providers working in direct partnership 
14    with community-based organizations. 
15        (5) The amount of a grant shall be based on a projects' 
16    size and scope. Grants shall allow for a significant 
17    portion, or the entirety, of the grant value to be made 
18    upfront, in advance of other incentives, to ensure 
19    businesses and organizations have the capital needed to 
20    plan, develop, and execute a project. 
21    (f) The application process for both subprograms shall not 
22be burdensome on applicants, nor require extensive technical 
23knowledge, and shall be able to be completed on less than 4 
24standard letter-sized pages. 
25    (g) These grant subprograms may be coordinated with 
26low-interest and no-interest financing opportunities offered 
 
 
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1through the Clean Energy Jobs and Justice Fund. 
2    (h) The grant subprograms may have a budget of up to 
3$41,000,000 $34,000,000 per year. No more than $8,500,000 25%    
4of the allocated budget shall go to the Community Solar Energy 
5Sovereignty Grant Program. No more than $7,000,000 of the 
6allocated budget shall go to financial assistance or technical 
7assistance to support compliance with prevailing wage and 
8project labor agreement requirements.    
9    (i) The Department shall endeavor to make expanded 
10Equitable Energy Future Grant Program grants available in line 
11with the timing of projects being constructed that have to 
12comply with newly applicable project labor agreements 
13requirements as a result of this amendatory Act of the 104th 
14General Assembly.    
15(Source: P.A. 102-662, eff. 9-15-21.)
 
16    Section 90-11. The Illinois Finance Authority Act is 
17amended by changing Section 801-10 and by adding Section 
18850-20 as follows:
 
19    (20 ILCS 3501/801-10)
20    Sec. 801-10. Definitions. The following terms, whenever 
21used or referred to in this Act, shall have the following 
22meanings, except in such instances where the context may 
23clearly indicate otherwise:
24    (a) The term "Authority" means the Illinois Finance 
 
 
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1Authority created by this Act.
2    (b) The term "project" means an industrial project, clean 
3energy project, energy storage project, conservation project, 
4housing project, public purpose project, higher education 
5project, health facility project, cultural institution 
6project, municipal bond program project, PACE Project, 
7agricultural facility or agribusiness, and "project" may 
8include any combination of one or more of the foregoing 
9undertaken jointly by any person with one or more other 
10persons.
11    (c) The term "public purpose project" means (i) any 
12project or facility, including without limitation land, 
13buildings, structures, machinery, equipment and all other real 
14and personal property, which is authorized or required by law 
15to be acquired, constructed, improved, rehabilitated, 
16reconstructed, replaced or maintained by any unit of 
17government or any other lawful public purpose, including 
18provision of working capital, which is authorized or required 
19by law to be undertaken by any unit of government or (ii) costs 
20incurred and other expenditures, including expenditures for 
21management, investment, or working capital costs, incurred in 
22connection with the reform, consolidation, or implementation 
23of the transition process as described in Articles 22B and 22C 
24of the Illinois Pension Code. 
25    (d) The term "industrial project" means the acquisition, 
26construction, refurbishment, creation, development or 
 
 
10400SB0025ham003- 98 -LRB104 07069 AAS 29208 a

1redevelopment of any facility, equipment, machinery, real 
2property or personal property for use by any instrumentality 
3of the State or its political subdivisions, for use by any 
4person or institution, public or private, for profit or not 
5for profit, or for use in any trade or business, including, but 
6not limited to, any industrial, manufacturing, clean energy, 
7or commercial enterprise that is located within or outside the 
8State, provided that, with respect to a project involving 
9property located outside the State, the property must be 
10owned, operated, leased or managed by an entity located within 
11the State or an entity affiliated with an entity located 
12within the State, and which is (1) a capital project or clean 
13energy project, including, but not limited to: (i) land and 
14any rights therein, one or more buildings, structures or other 
15improvements, machinery and equipment, whether now existing or 
16hereafter acquired, and whether or not located on the same 
17site or sites; (ii) all appurtenances and facilities 
18incidental to the foregoing, including, but not limited to, 
19utilities, access roads, railroad sidings, track, docking and 
20similar facilities, parking facilities, dockage, wharfage, 
21railroad roadbed, track, trestle, depot, terminal, switching 
22and signaling or related equipment, site preparation and 
23landscaping; and (iii) all non-capital costs and expenses 
24relating thereto or (2) any addition to, renovation, 
25rehabilitation or improvement of a capital project or a clean 
26energy project, or (3) any activity or undertaking within or 
 
 
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1outside the State, provided that, with respect to a project 
2involving property located outside the State, the property 
3must be owned, operated, leased or managed by an entity 
4located within the State or an entity affiliated with an 
5entity located within the State, which the Authority 
6determines will aid, assist or encourage economic growth, 
7development or redevelopment within the State or any area 
8thereof, will promote the expansion, retention or 
9diversification of employment opportunities within the State 
10or any area thereof or will aid in stabilizing or developing 
11any industry or economic sector of the State economy. The term 
12"industrial project" also means the production of motion 
13pictures.
14    (e) The term "bond" or "bonds" shall include bonds, notes 
15(including bond, grant or revenue anticipation notes), 
16certificates and/or other evidences of indebtedness 
17representing an obligation to pay money, including refunding 
18bonds.
19    (f) The terms "lease agreement" and "loan agreement" shall 
20mean: (i) an agreement whereby a project acquired by the 
21Authority by purchase, gift or lease is leased to any person, 
22corporation or unit of local government which will use or 
23cause the project to be used as a project as heretofore defined 
24upon terms providing for lease rental payments at least 
25sufficient to pay when due all principal of, interest and 
26premium, if any, on any bonds of the Authority issued with 
 
 
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1respect to such project, providing for the maintenance, 
2insuring and operation of the project on terms satisfactory to 
3the Authority, providing for disposition of the project upon 
4termination of the lease term, including purchase options or 
5abandonment of the premises, and such other terms as may be 
6deemed desirable by the Authority, (ii) any agreement pursuant 
7to which the Authority agrees to loan the proceeds of its bonds 
8issued with respect to a project or other funds of the 
9Authority to any person which will use or cause the project to 
10be used as a project as heretofore defined or for any other 
11lawful purpose upon terms providing for loan repayment 
12installments at least sufficient to pay when due all principal 
13of, interest and premium, if any, on any bonds of the 
14Authority, if any, issued with respect to the project or for 
15any other lawful purpose, and providing for maintenance, 
16insurance and other matters as may be deemed desirable by the 
17Authority, or (iii) any financing or refinancing agreement 
18entered into by the Authority under subsection (aa) of Section 
19801-40.
20    (g) The term "financial aid" means the expenditure of 
21Authority funds or funds provided by the Authority through the 
22issuance of its bonds, notes or other evidences of 
23indebtedness or from other sources for the development, 
24construction, acquisition or improvement of a project.
25    (h) The term "person" means an individual, corporation, 
26unit of government, business trust, estate, trust, partnership 
 
 
10400SB0025ham003- 101 -LRB104 07069 AAS 29208 a

1or association, 2 or more persons having a joint or common 
2interest, or any other legal entity.
3    (i) The term "unit of government" means the federal 
4government, the State or unit of local government, a school 
5district, or any agency or instrumentality, office, officer, 
6department, division, bureau, commission, college or 
7university thereof.
8    (j) The term "health facility" means: (a) any public or 
9private institution, place, building, or agency required to be 
10licensed under the Hospital Licensing Act; (b) any public or 
11private institution, place, building, or agency required to be 
12licensed under the Nursing Home Care Act, the Specialized 
13Mental Health Rehabilitation Act of 2013, the ID/DD Community 
14Care Act, or the MC/DD Act; (c) any public or licensed private 
15hospital as defined in the Mental Health and Developmental 
16Disabilities Code; (d) any such facility exempted from such 
17licensure when the Director of Public Health attests that such 
18exempted facility meets the statutory definition of a facility 
19subject to licensure; (e) any other public or private health 
20service institution, place, building, or agency which the 
21Director of Public Health attests is subject to certification 
22by the Secretary, U.S. Department of Health and Human Services 
23under the Social Security Act, as now or hereafter amended, or 
24which the Director of Public Health attests is subject to 
25standard-setting by a recognized public or voluntary 
26accrediting or standard-setting agency; (f) any public or 
 
 
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1private institution, place, building or agency engaged in 
2providing one or more supporting services to a health 
3facility; (g) any public or private institution, place, 
4building or agency engaged in providing training in the 
5healing arts, including, but not limited to, schools of 
6medicine, dentistry, osteopathy, optometry, podiatry, pharmacy 
7or nursing, schools for the training of x-ray, laboratory or 
8other health care technicians and schools for the training of 
9para-professionals in the health care field; (h) any public or 
10private congregate, life or extended care or elderly housing 
11facility or any public or private home for the aged or infirm, 
12including, without limitation, any Facility as defined in the 
13Life Care Facilities Act; (i) any public or private mental, 
14emotional or physical rehabilitation facility or any public or 
15private educational, counseling, or rehabilitation facility or 
16home, for those persons with a developmental disability, those 
17who are physically ill or disabled, the emotionally disturbed, 
18those persons with a mental illness or persons with learning 
19or similar disabilities or problems; (j) any public or private 
20alcohol, drug or substance abuse diagnosis, counseling 
21treatment or rehabilitation facility, (k) any public or 
22private institution, place, building or agency licensed by the 
23Department of Children and Family Services or which is not so 
24licensed but which the Director of Children and Family 
25Services attests provides child care, child welfare or other 
26services of the type provided by facilities subject to such 
 
 
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1licensure; (l) any public or private adoption agency or 
2facility; and (m) any public or private blood bank or blood 
3center. "Health facility" also means a public or private 
4structure or structures suitable primarily for use as a 
5laboratory, laundry, nurses or interns residence or other 
6housing or hotel facility used in whole or in part for staff, 
7employees or students and their families, patients or 
8relatives of patients admitted for treatment or care in a 
9health facility, or persons conducting business with a health 
10facility, physician's facility, surgicenter, administration 
11building, research facility, maintenance, storage or utility 
12facility and all structures or facilities related to any of 
13the foregoing or required or useful for the operation of a 
14health facility, including parking or other facilities or 
15other supporting service structures required or useful for the 
16orderly conduct of such health facility. "Health facility" 
17also means, with respect to a project located outside the 
18State, any public or private institution, place, building, or 
19agency which provides services similar to those described 
20above, provided that such project is owned, operated, leased 
21or managed by a participating health institution located 
22within the State, or a participating health institution 
23affiliated with an entity located within the State.
24    (k) The term "participating health institution" means (i) 
25a private corporation or association or (ii) a public entity 
26of this State, in either case authorized by the laws of this 
 
 
10400SB0025ham003- 104 -LRB104 07069 AAS 29208 a

1State or the applicable state to provide or operate a health 
2facility as defined in this Act and which, pursuant to the 
3provisions of this Act, undertakes the financing, construction 
4or acquisition of a project or undertakes the refunding or 
5refinancing of obligations, loans, indebtedness or advances as 
6provided in this Act.
7    (l) The term "health facility project", means a specific 
8health facility work or improvement to be financed or 
9refinanced (including without limitation through reimbursement 
10of prior expenditures), acquired, constructed, enlarged, 
11remodeled, renovated, improved, furnished, or equipped, with 
12funds provided in whole or in part hereunder, any accounts 
13receivable, working capital, liability or insurance cost or 
14operating expense financing or refinancing program of a health 
15facility with or involving funds provided in whole or in part 
16hereunder, or any combination thereof.
17    (m) The term "bond resolution" means the resolution or 
18resolutions authorizing the issuance of, or providing terms 
19and conditions related to, bonds issued under this Act and 
20includes, where appropriate, any trust agreement, trust 
21indenture, indenture of mortgage or deed of trust providing 
22terms and conditions for such bonds.
23    (n) The term "property" means any real, personal or mixed 
24property, whether tangible or intangible, or any interest 
25therein, including, without limitation, any real estate, 
26leasehold interests, appurtenances, buildings, easements, 
 
 
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1equipment, furnishings, furniture, improvements, machinery, 
2rights of way, structures, accounts, contract rights or any 
3interest therein.
4    (o) The term "revenues" means, with respect to any 
5project, the rents, fees, charges, interest, principal 
6repayments, collections and other income or profit derived 
7therefrom.
8    (p) The term "higher education project" means, in the case 
9of a private institution of higher education, an educational 
10facility to be acquired, constructed, enlarged, remodeled, 
11renovated, improved, furnished, or equipped, or any 
12combination thereof.
13    (q) The term "cultural institution project" means, in the 
14case of a cultural institution, a cultural facility to be 
15acquired, constructed, enlarged, remodeled, renovated, 
16improved, furnished, or equipped, or any combination thereof.
17    (r) The term "educational facility" means any property 
18located within the State, or any property located outside the 
19State, provided that, if the property is located outside the 
20State, it must be owned, operated, leased or managed by an 
21entity located within the State or an entity affiliated with 
22an entity located within the State, in each case constructed 
23or acquired before or after the effective date of this Act, 
24which is or will be, in whole or in part, suitable for the 
25instruction, feeding, recreation or housing of students, the 
26conducting of research or other work of a private institution 
 
 
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1of higher education, the use by a private institution of 
2higher education in connection with any educational, research 
3or related or incidental activities then being or to be 
4conducted by it, or any combination of the foregoing, 
5including, without limitation, any such property suitable for 
6use as or in connection with any one or more of the following: 
7an academic facility, administrative facility, agricultural 
8facility, assembly hall, athletic facility, auditorium, 
9boating facility, campus, communication facility, computer 
10facility, continuing education facility, classroom, dining 
11hall, dormitory, exhibition hall, fire fighting facility, fire 
12prevention facility, food service and preparation facility, 
13gymnasium, greenhouse, health care facility, hospital, 
14housing, instructional facility, laboratory, library, 
15maintenance facility, medical facility, museum, offices, 
16parking area, physical education facility, recreational 
17facility, research facility, stadium, storage facility, 
18student union, study facility, theatre or utility.
19    (s) The term "cultural facility" means any property 
20located within the State, or any property located outside the 
21State, provided that, if the property is located outside the 
22State, it must be owned, operated, leased or managed by an 
23entity located within the State or an entity affiliated with 
24an entity located within the State, in each case constructed 
25or acquired before or after the effective date of this Act, 
26which is or will be, in whole or in part, suitable for the 
 
 
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1particular purposes or needs of a cultural institution, 
2including, without limitation, any such property suitable for 
3use as or in connection with any one or more of the following: 
4an administrative facility, aquarium, assembly hall, 
5auditorium, botanical garden, exhibition hall, gallery, 
6greenhouse, library, museum, scientific laboratory, theater or 
7zoological facility, and shall also include, without 
8limitation, books, works of art or music, animal, plant or 
9aquatic life or other items for display, exhibition or 
10performance. The term "cultural facility" includes buildings 
11on the National Register of Historic Places which are owned or 
12operated by nonprofit entities.
13    (t) "Private institution of higher education" means a 
14not-for-profit educational institution which is not owned by 
15the State or any political subdivision, agency, 
16instrumentality, district or municipality thereof, which is 
17authorized by law to provide a program of education beyond the 
18high school level and which:
19        (1) Admits as regular students only individuals having 
20    a certificate of graduation from a high school, or the 
21    recognized equivalent of such a certificate;
22        (2) Provides an educational program for which it 
23    awards a bachelor's degree, or provides an educational 
24    program, admission into which is conditioned upon the 
25    prior attainment of a bachelor's degree or its equivalent, 
26    for which it awards a postgraduate degree, or provides not 
 
 
10400SB0025ham003- 108 -LRB104 07069 AAS 29208 a

1    less than a 2-year program which is acceptable for full 
2    credit toward such a degree, or offers a 2-year program in 
3    engineering, mathematics, or the physical or biological 
4    sciences which is designed to prepare the student to work 
5    as a technician and at a semiprofessional level in 
6    engineering, scientific, or other technological fields 
7    which require the understanding and application of basic 
8    engineering, scientific, or mathematical principles or 
9    knowledge;
10        (3) Is accredited by a nationally recognized 
11    accrediting agency or association or, if not so 
12    accredited, is an institution whose credits are accepted, 
13    on transfer, by not less than 3 institutions which are so 
14    accredited, for credit on the same basis as if transferred 
15    from an institution so accredited, and holds an unrevoked 
16    certificate of approval under the Private College Act from 
17    the Board of Higher Education, or is qualified as a 
18    "degree granting institution" under the Academic Degree 
19    Act; and
20        (4) Does not discriminate in the admission of students 
21    on the basis of race or color. "Private institution of 
22    higher education" also includes any "academic 
23    institution".
24    (u) The term "academic institution" means any 
25not-for-profit institution which is not owned by the State or 
26any political subdivision, agency, instrumentality, district 
 
 
10400SB0025ham003- 109 -LRB104 07069 AAS 29208 a

1or municipality thereof, which institution engages in, or 
2facilitates academic, scientific, educational or professional 
3research or learning in a field or fields of study taught at a 
4private institution of higher education. Academic institutions 
5include, without limitation, libraries, archives, academic, 
6scientific, educational or professional societies, 
7institutions, associations or foundations having such 
8purposes.
9    (v) The term "cultural institution" means any 
10not-for-profit institution which is not owned by the State or 
11any political subdivision, agency, instrumentality, district 
12or municipality thereof, which institution engages in the 
13cultural, intellectual, scientific, educational or artistic 
14enrichment of the people of the State. Cultural institutions 
15include, without limitation, aquaria, botanical societies, 
16historical societies, libraries, museums, performing arts 
17associations or societies, scientific societies and zoological 
18societies. 
19    (w) The term "affiliate" means, with respect to financing 
20of an agricultural facility or an agribusiness, any lender, 
21any person, firm or corporation controlled by, or under common 
22control with, such lender, and any person, firm or corporation 
23controlling such lender.
24    (x) The term "agricultural facility" means land, any 
25building or other improvement thereon or thereto, and any 
26personal properties deemed necessary or suitable for use, 
 
 
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1whether or not now in existence, in farming, ranching, the 
2production of agricultural commodities (including, without 
3limitation, the products of aquaculture, hydroponics and 
4silviculture) or the treating, processing or storing of such 
5agricultural commodities when such activities are customarily 
6engaged in by farmers as a part of farming and which land, 
7building, improvement or personal property is located within 
8the State, or is located outside the State, provided that, if 
9such property is located outside the State, it must be owned, 
10operated, leased, or managed by an entity located within the 
11State or an entity affiliated with an entity located within 
12the State.
13    (y) The term "lender" with respect to financing of an 
14agricultural facility or an agribusiness, means any federal or 
15State chartered bank, Federal Land Bank, Production Credit 
16Association, Bank for Cooperatives, federal or State chartered 
17savings and loan association or building and loan association, 
18Small Business Investment Company or any other institution 
19qualified within this State to originate and service loans, 
20including, but without limitation to, insurance companies, 
21credit unions and mortgage loan companies. "Lender" also means 
22a wholly owned subsidiary of a manufacturer, seller or 
23distributor of goods or services that makes loans to 
24businesses or individuals, commonly known as a "captive 
25finance company".
26    (z) The term "agribusiness" means any sole proprietorship, 
 
 
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1limited partnership, co-partnership, joint venture, 
2corporation or cooperative which operates or will operate a 
3facility located within the State or outside the State, 
4provided that, if any facility is located outside the State, 
5it must be owned, operated, leased, or managed by an entity 
6located within the State or an entity affiliated with an 
7entity located within the State, that is related to the 
8processing of agricultural commodities (including, without 
9limitation, the products of aquaculture, hydroponics and 
10silviculture) or the manufacturing, production or construction 
11of agricultural buildings, structures, equipment, implements, 
12and supplies, or any other facilities or processes used in 
13agricultural production. Agribusiness includes but is not 
14limited to the following:
15        (1) grain handling and processing, including grain 
16    storage, drying, treatment, conditioning, mailing and 
17    packaging;
18        (2) seed and feed grain development and processing;
19        (3) fruit and vegetable processing, including 
20    preparation, canning and packaging;
21        (4) processing of livestock and livestock products, 
22    dairy products, poultry and poultry products, fish or 
23    apiarian products, including slaughter, shearing, 
24    collecting, preparation, canning and packaging;
25        (5) fertilizer and agricultural chemical 
26    manufacturing, processing, application and supplying;
 
 
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1        (6) farm machinery, equipment and implement 
2    manufacturing and supplying;
3        (7) manufacturing and supplying of agricultural 
4    commodity processing machinery and equipment, including 
5    machinery and equipment used in slaughter, treatment, 
6    handling, collecting, preparation, canning or packaging of 
7    agricultural commodities;
8        (8) farm building and farm structure manufacturing, 
9    construction and supplying;
10        (9) construction, manufacturing, implementation, 
11    supplying or servicing of irrigation, drainage and soil 
12    and water conservation devices or equipment;
13        (10) fuel processing and development facilities that 
14    produce fuel from agricultural commodities or byproducts;
15        (11) facilities and equipment for processing and 
16    packaging agricultural commodities specifically for 
17    export;
18        (12) facilities and equipment for forestry product 
19    processing and supplying, including sawmilling operations, 
20    wood chip operations, timber harvesting operations, and 
21    manufacturing of prefabricated buildings, paper, furniture 
22    or other goods from forestry products;
23        (13) facilities and equipment for research and 
24    development of products, processes and equipment for the 
25    production, processing, preparation or packaging of 
26    agricultural commodities and byproducts.
 
 
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1    (aa) The term "asset" with respect to financing of any 
2agricultural facility or any agribusiness, means, but is not 
3limited to the following: cash crops or feed on hand; 
4livestock held for sale; breeding stock; marketable bonds and 
5securities; securities not readily marketable; accounts 
6receivable; notes receivable; cash invested in growing crops; 
7net cash value of life insurance; machinery and equipment; 
8cars and trucks; farm and other real estate including life 
9estates and personal residence; value of beneficial interests 
10in trusts; government payments or grants; and any other 
11assets.
12    (bb) The term "liability" with respect to financing of any 
13agricultural facility or any agribusiness shall include, but 
14not be limited to the following: accounts payable; notes or 
15other indebtedness owed to any source; taxes; rent; amounts 
16owed on real estate contracts or real estate mortgages; 
17judgments; accrued interest payable; and any other liability.
18    (cc) The term "Predecessor Authorities" means those 
19authorities as described in Section 845-75.
20    (dd) The term "housing project" means a specific work or 
21improvement located within the State or outside the State and 
22undertaken to provide residential dwelling accommodations, 
23including the acquisition, construction or rehabilitation of 
24lands, buildings and community facilities and in connection 
25therewith to provide nonhousing facilities which are part of 
26the housing project, including land, buildings, improvements, 
 
 
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1equipment and all ancillary facilities for use for offices, 
2stores, retirement homes, hotels, financial institutions, 
3service, health care, education, recreation or research 
4establishments, or any other commercial purpose which are or 
5are to be related to a housing development, provided that any 
6work or improvement located outside the State is owned, 
7operated, leased or managed by an entity located within the 
8State, or any entity affiliated with an entity located within 
9the State.
10    (ee) The term "conservation project" means any project 
11including the acquisition, construction, rehabilitation, 
12maintenance, operation, or upgrade that is intended to create 
13or expand open space or to reduce energy usage through 
14efficiency measures. For the purpose of this definition, "open 
15space" has the definition set forth under Section 10 of the 
16Illinois Open Land Trust Act. 
17    (ff) The term "significant presence" means the existence 
18within the State of the national or regional headquarters of 
19an entity or group or such other facility of an entity or group 
20of entities where a significant amount of the business 
21functions are performed for such entity or group of entities. 
22    (gg) The term "municipal bond issuer" means the State or 
23any other state or commonwealth of the United States, or any 
24unit of local government, school district, agency or 
25instrumentality, office, department, division, bureau, 
26commission, college or university thereof located in the State 
 
 
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1or any other state or commonwealth of the United States.
2    (hh) The term "municipal bond program project" means a 
3program for the funding of the purchase of bonds, notes or 
4other obligations issued by or on behalf of a municipal bond 
5issuer. 
6    (ii) The term "participating lender" means any trust 
7company, bank, savings bank, credit union, merchant bank, 
8investment bank, broker, investment trust, pension fund, 
9building and loan association, savings and loan association, 
10insurance company, venture capital company, or other 
11institution approved by the Authority which provides a portion 
12of the financing for a project.
13    (jj) The term "loan participation" means any loan in which 
14the Authority co-operates with a participating lender to 
15provide all or a portion of the financing for a project.
16    (kk) The term "PACE Project" means an energy project as 
17defined in Section 5 of the Property Assessed Clean Energy 
18Act. 
19    (ll) The term "clean energy" means energy generation that 
20is substantially free (90% or more) of carbon dioxide 
21emissions by design or operations, or that otherwise 
22contributes to the reduction in emissions of environmentally 
23hazardous materials or reduces the volume of environmentally 
24dangerous materials.
25    (mm) The term "clean energy project" means the 
26acquisition, construction, refurbishment, creation, 
 
 
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1development or redevelopment of any facility, equipment, 
2machinery, real property, or personal property for use by the 
3State or any unit of local government, school district, agency 
4or instrumentality, office, department, division, bureau, 
5commission, college, or university of the State, for use by 
6any person or institution, public or private, for profit or 
7not for profit, or for use in any trade or business, which the 
8Authority determines will aid, assist, or encourage the 
9development or implementation of clean energy in the State, or 
10as otherwise contemplated by Article 850.
11    (nn) The term "Climate Bank" means the Authority in the 
12exercise of those powers conferred on it by this Act related to 
13clean energy or clean water, drinking water, or wastewater 
14treatment.
15    (oo) "Equity investment eligible community" and "eligible 
16community" mean the geographic areas throughout Illinois that 
17would most benefit from equitable investments by the State 
18designed to combat discrimination. Specifically, the eligible 
19communities shall be defined as the following areas:
20        (1) R3 Areas as established pursuant to Section 10-40 
21    of the Cannabis Regulation and Tax Act, where residents 
22    have historically been excluded from economic 
23    opportunities, including opportunities in the energy 
24    sector; and
25        (2) Environmental justice communities, as defined by 
26    the Illinois Power Agency pursuant to the Illinois Power 
 
 
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1    Agency Act, where residents have historically been subject 
2    to disproportionate burdens of pollution, including 
3    pollution from the energy sector.
4    (pp) "Equity investment eligible person" and "eligible 
5person" mean the persons who would most benefit from equitable 
6investments by the State designed to combat discrimination. 
7Specifically, eligible persons means the following people:
8        (1) persons whose primary residence is in an equity 
9    investment eligible community;
10        (2) persons who are graduates of or currently enrolled 
11    in the foster care system; or
12        (3) persons who were formerly incarcerated.
13    (qq) "Environmental justice community" means the 
14definition of that term based on existing methodologies and 
15findings used and as may be updated by the Illinois Power 
16Agency and its program administrator in the Illinois Solar for 
17All Program. 
18    (rr) "Energy storage project" means a project that uses 
19technology for the storage of energy, including, without 
20limitation, the use of battery or electrochemical storage 
21technology for mobile or stationary applications.    
22(Source: P.A. 104-6, eff. 6-16-25.)
 
23    (20 ILCS 3501/850-20 new)
24    Sec. 850-20. Thermal Energy Network Revolving Loan and 
25Financial Assistance Program.
 
 
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1    (a) As used in this Section:
2    "Program" means the Thermal Energy Network Revolving Loan 
3and Financial Assistance Program established under this 
4Section.    
5    "Thermal energy network" means all real estate, fixtures, 
6and personal property operated, owned, used, or to be used for 
7in connection with or to facilitate a community-scale 
8distribution infrastructure project that transfers heat into 
9and out of buildings using non-combusting thermal energy, 
10sourced from zero-emission technologies, including geothermal 
11energy, for the purpose of reducing emissions. "Thermal energy 
12network" includes, but is not limited to, real estate, 
13fixtures, and personal property that is operated, owned, or 
14used by multiple parties and community geothermal systems.    
15    (b) In its role as the Climate Bank for the State, the 
16Authority may, subject to available funding, establish and 
17administer a Thermal Energy Network Revolving Loan and 
18Financial Assistance Program. The Program shall provide access 
19to capital for thermal energy network projects that take into 
20consideration the risks involved in the development of shared 
21heating and cooling systems and the required coordination 
22among multiple customers, as well as the benefits of enabling 
23low-cost decarbonization of residential, commercial, and 
24industrial buildings and processes. The Program may provide 
25loans, grants, or other financial assistance for thermal 
26energy network projects.
 
 
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1    (c) The Authority may establish internal accounts 
2necessary to administer the Program, identify sources of 
3public and private funding and financial capital, and develop 
4any requirements or agreements necessary to successfully 
5execute the Program.
6    (d) The Authority shall coordinate and enter into any 
7necessary agreements with the Illinois Commerce Commission to 
8(i) develop and offer funding and financing to thermal energy 
9network pilot projects approved by the Commission under 
10subsection (a) of Section 8-513 of the Public Utilities Act, 
11(ii) receive funds as necessary and as approved by the 
12Commission under subsection (b) of Section 8-513 of the Public 
13Utilities Act, and (iii) establish any requirements necessary 
14to ensure compliance with the objectives of any federal 
15funding sources secured to support the Program.
16    (e) All repayments of loans or other financial assistance 
17made under the Program shall be used or leveraged to provide 
18additional capital to thermal energy network pilot projects 
19that support the clean energy goals of the State, in 
20coordination with any rules established by the Illinois 
21Commerce Commission.
22    (f) The Authority may adopt any resolutions, plans, or 
23rules and fix, determine, charge, or collect any fees, 
24charges, costs, and expenses necessary to administer the 
25Program under this Section.
 
 
 
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1    Section 90-12. The Illinois Power Agency Act is amended by 
2changing Sections 1-10, 1-20, 1-56, 1-75, and 1-125 as 
3follows:
 
4    (20 ILCS 3855/1-10)
5    Sec. 1-10. Definitions. 
6    "Agency" means the Illinois Power Agency.
7    "Agency loan agreement" means any agreement pursuant to 
8which the Illinois Finance Authority agrees to loan the 
9proceeds of revenue bonds issued with respect to a project to 
10the Agency upon terms providing for loan repayment 
11installments at least sufficient to pay when due all principal 
12of, interest and premium, if any, on those revenue bonds, and 
13providing for maintenance, insurance, and other matters in 
14respect of the project.
15    "Authority" means the Illinois Finance Authority.
16    "Brownfield site photovoltaic project" means photovoltaics 
17that are either:
18        (1) interconnected to an electric utility as defined 
19    in this Section, a municipal utility as defined in this 
20    Section, a public utility as defined in Section 3-105 of 
21    the Public Utilities Act, or an electric cooperative as 
22    defined in Section 3-119 of the Public Utilities Act and 
23    located at a site that is regulated by any of the following 
24    entities under the following programs:
25            (A) the United States Environmental Protection 
 
 
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1        Agency under the federal Comprehensive Environmental 
2        Response, Compensation, and Liability Act of 1980, as 
3        amended;
4            (B) the United States Environmental Protection 
5        Agency under the Corrective Action Program of the 
6        federal Resource Conservation and Recovery Act, as 
7        amended;
8            (C) the Illinois Environmental Protection Agency 
9        under the Illinois Site Remediation Program; or
10            (D) the Illinois Environmental Protection Agency 
11        under the Illinois Solid Waste Program; or 
12        (2) located at the site of a coal mine that has 
13    permanently ceased coal production, permanently halted any 
14    re-mining operations, and is no longer accepting any coal 
15    combustion residues; has both completed all clean-up and 
16    remediation obligations under the federal Surface Mining 
17    and Reclamation Act of 1977 and all applicable Illinois 
18    rules and any other clean-up, remediation, or ongoing 
19    monitoring to safeguard the health and well-being of the 
20    people of the State of Illinois, as well as demonstrated 
21    compliance with all applicable federal and State 
22    environmental rules and regulations, including, but not 
23    limited, to 35 Ill. Adm. Code Part 845 and any rules for 
24    historic fill of coal combustion residuals, including any 
25    rules finalized in Subdocket A of Illinois Pollution 
26    Control Board docket R2020-019. 
 
 
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1    "Clean coal facility" means an electric generating 
2facility that uses primarily coal as a feedstock and that 
3captures and sequesters carbon dioxide emissions at the 
4following levels: at least 50% of the total carbon dioxide 
5emissions that the facility would otherwise emit if, at the 
6time construction commences, the facility is scheduled to 
7commence operation before 2016, at least 70% of the total 
8carbon dioxide emissions that the facility would otherwise 
9emit if, at the time construction commences, the facility is 
10scheduled to commence operation during 2016 or 2017, and at 
11least 90% of the total carbon dioxide emissions that the 
12facility would otherwise emit if, at the time construction 
13commences, the facility is scheduled to commence operation 
14after 2017. The power block of the clean coal facility shall 
15not exceed allowable emission rates for sulfur dioxide, 
16nitrogen oxides, carbon monoxide, particulates and mercury for 
17a natural gas-fired combined-cycle facility the same size as 
18and in the same location as the clean coal facility at the time 
19the clean coal facility obtains an approved air permit. All 
20coal used by a clean coal facility shall have high volatile 
21bituminous rank and greater than 1.7 pounds of sulfur per 
22million Btu content, unless the clean coal facility does not 
23use gasification technology and was operating as a 
24conventional coal-fired electric generating facility on June 
251, 2009 (the effective date of Public Act 95-1027). 
26    "Clean coal SNG brownfield facility" means a facility that 
 
 
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1(1) has commenced construction by July 1, 2015 on an urban 
2brownfield site in a municipality with at least 1,000,000 
3residents; (2) uses a gasification process to produce 
4substitute natural gas; (3) uses coal as at least 50% of the 
5total feedstock over the term of any sourcing agreement with a 
6utility and the remainder of the feedstock may be either 
7petroleum coke or coal, with all such coal having a high 
8bituminous rank and greater than 1.7 pounds of sulfur per 
9million Btu content unless the facility reasonably determines 
10that it is necessary to use additional petroleum coke to 
11deliver additional consumer savings, in which case the 
12facility shall use coal for at least 35% of the total feedstock 
13over the term of any sourcing agreement; and (4) captures and 
14sequesters at least 85% of the total carbon dioxide emissions 
15that the facility would otherwise emit. 
16    "Clean coal SNG facility" means a facility that uses a 
17gasification process to produce substitute natural gas, that 
18sequesters at least 90% of the total carbon dioxide emissions 
19that the facility would otherwise emit, that uses at least 90% 
20coal as a feedstock, with all such coal having a high 
21bituminous rank and greater than 1.7 pounds of sulfur per 
22million Btu content, and that has a valid and effective permit 
23to construct emission sources and air pollution control 
24equipment and approval with respect to the federal regulations 
25for Prevention of Significant Deterioration of Air Quality 
26(PSD) for the plant pursuant to the federal Clean Air Act; 
 
 
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1provided, however, a clean coal SNG brownfield facility shall 
2not be a clean coal SNG facility. 
3    "Clean energy" means energy generation that is 90% or 
4greater free of carbon dioxide emissions. 
5    "Commission" means the Illinois Commerce Commission.
6    "Community renewable generation project" means an electric 
7generating facility that: 
8        (1) is powered by wind, solar thermal energy, 
9    photovoltaic cells or panels, biodiesel, crops and 
10    untreated and unadulterated organic waste biomass, and 
11    hydropower that does not involve new construction of dams; 
12        (2) is interconnected at the distribution system level 
13    of an electric utility as defined in this Section, a 
14    municipal utility as defined in this Section that owns or 
15    operates electric distribution facilities, a public 
16    utility as defined in Section 3-105 of the Public 
17    Utilities Act, or an electric cooperative, as defined in 
18    Section 3-119 of the Public Utilities Act;
19        (3) credits the value of electricity generated by the 
20    facility to the subscribers of the facility; and
21        (4) is limited in nameplate capacity to less than or 
22    equal to 5,000 kilowatts.
23    "Costs incurred in connection with the development and 
24construction of a facility" means:
25        (1) the cost of acquisition of all real property, 
26    fixtures, and improvements in connection therewith and 
 
 
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1    equipment, personal property, and other property, rights, 
2    and easements acquired that are deemed necessary for the 
3    operation and maintenance of the facility;
4        (2) financing costs with respect to bonds, notes, and 
5    other evidences of indebtedness of the Agency;
6        (3) all origination, commitment, utilization, 
7    facility, placement, underwriting, syndication, credit 
8    enhancement, and rating agency fees;
9        (4) engineering, design, procurement, consulting, 
10    legal, accounting, title insurance, survey, appraisal, 
11    escrow, trustee, collateral agency, interest rate hedging, 
12    interest rate swap, capitalized interest, contingency, as 
13    required by lenders, and other financing costs, and other 
14    expenses for professional services; and
15        (5) the costs of plans, specifications, site study and 
16    investigation, installation, surveys, other Agency costs 
17    and estimates of costs, and other expenses necessary or 
18    incidental to determining the feasibility of any project, 
19    together with such other expenses as may be necessary or 
20    incidental to the financing, insuring, acquisition, and 
21    construction of a specific project and starting up, 
22    commissioning, and placing that project in operation. 
23    "Delivery services" has the same definition as found in 
24Section 16-102 of the Public Utilities Act. 
25    "Delivery year" means the consecutive 12-month period 
26beginning June 1 of a given year and ending May 31 of the 
 
 
10400SB0025ham003- 126 -LRB104 07069 AAS 29208 a

1following year. 
2    "Department" means the Department of Commerce and Economic 
3Opportunity.
4    "Director" means the Director of the Illinois Power 
5Agency.
6    "Demand response Demand-response" means measures that 
7decrease peak electricity demand or shift demand from peak to 
8off-peak periods.
9    "Distributed renewable energy generation device" means a 
10device that is:
11        (1) powered by wind, solar thermal energy, 
12    photovoltaic cells or panels, biodiesel, crops and 
13    untreated and unadulterated organic waste biomass, tree 
14    waste, and hydropower that does not involve new 
15    construction of dams, waste heat to power systems, or 
16    qualified combined heat and power systems; 
17        (2) interconnected at the distribution system level of 
18    either an electric utility as defined in this Section, a 
19    municipal utility as defined in this Section that owns or 
20    operates electric distribution facilities, or a rural 
21    electric cooperative as defined in Section 3-119 of the 
22    Public Utilities Act; 
23        (3) located on the customer side of the customer's 
24    electric meter and is primarily used to offset that 
25    customer's electricity load; and
26        (4) (blank). 
 
 
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1    "Energy efficiency" means measures that reduce the amount 
2of electricity or natural gas consumed in order to achieve a 
3given end use. "Energy efficiency" includes voltage 
4optimization measures that optimize the voltage at points on 
5the electric distribution voltage system and thereby reduce 
6electricity consumption by electric customers' end use 
7devices. "Energy efficiency" also includes measures that 
8reduce the total Btus of electricity, natural gas, and other 
9fuels needed to meet the end use or uses. 
10    "Energy storage system" has the meaning given to that term 
11in Section 16-135 of the Public Utilities Act. "Energy storage 
12system" does not include technologies that require combustion.
13    "Energy storage resources" means the operational output or 
14capabilities of energy storage systems. "Energy storage 
15resources" includes, but is not limited to, energy, capacity, 
16and energy storage credits.    
17    "Electric utility" has the same definition as found in 
18Section 16-102 of the Public Utilities Act.
19    "Equity investment eligible community" or "eligible 
20community" are synonymous and mean the geographic areas 
21throughout Illinois which would most benefit from equitable 
22investments by the State designed to combat discrimination. 
23Specifically, the eligible communities shall be defined as the 
24following areas:
25        (1) R3 Areas as established pursuant to Section 10-40 
26    of the Cannabis Regulation and Tax Act, where residents 
 
 
10400SB0025ham003- 128 -LRB104 07069 AAS 29208 a

1    have historically been excluded from economic 
2    opportunities, including opportunities in the energy 
3    sector; and
4        (2) environmental justice communities, as defined by 
5    the Illinois Power Agency pursuant to the Illinois Power 
6    Agency Act, where residents have historically been subject 
7    to disproportionate burdens of pollution, including 
8    pollution from the energy sector.
9    "Equity eligible persons" or "eligible persons" means 
10persons who would most benefit from equitable investments by 
11the State designed to combat discrimination, specifically:
12        (1) persons who graduate from or are current or former 
13    participants in the Clean Jobs Workforce Network Program, 
14    the Clean Energy Contractor Incubator Program, the 
15    Illinois Climate Works Preapprenticeship Program, 
16    Returning Residents Clean Jobs Training Program, or the 
17    Clean Energy Primes Contractor Accelerator Program, and 
18    the solar training pipeline and multi-cultural jobs 
19    program created in paragraphs (1) and (3) of subsection 
20    (a) (a)(1) and (a)(3) of Section 16-108.12 16-208.12 of 
21    the Public Utilities Act;
22        (2) persons who are graduates of or currently enrolled 
23    in the foster care system;
24        (3) persons who were formerly incarcerated;
25        (4) persons whose primary residence is in an equity 
26    investment eligible community.
 
 
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1    "Equity eligible contractor" means a business that is 
2majority-owned by eligible persons, or a nonprofit or 
3cooperative that is majority-governed by eligible persons, or 
4is a natural person that is an eligible person offering 
5personal services as an independent contractor. 
6    "Facility" means an electric generating unit or a 
7co-generating unit that produces electricity along with 
8related equipment necessary to connect the facility to an 
9electric transmission or distribution system.
10    "General contractor" means the entity or organization with 
11main responsibility for the building of a construction project 
12and who is the party signing the prime construction contract 
13for the project. 
14    "Governmental aggregator" means one or more units of local 
15government that individually or collectively procure 
16electricity to serve residential retail electrical loads 
17located within its or their jurisdiction.
18    "High voltage direct current converter station" means the 
19collection of equipment that converts direct current energy 
20from a high voltage direct current transmission line into 
21alternating current using Voltage Source Conversion technology 
22and that is interconnected with transmission or distribution 
23assets located in Illinois.
24    "High voltage direct current renewable energy credit" 
25means a renewable energy credit associated with a renewable 
26energy resource where the renewable energy resource has 
 
 
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1entered into a contract to transmit the energy associated with 
2such renewable energy credit over high voltage direct current 
3transmission facilities. 
4    "High voltage direct current transmission facilities" 
5means the collection of installed equipment that converts 
6alternating current energy in one location to direct current 
7and transmits that direct current energy to a high voltage 
8direct current converter station using Voltage Source 
9Conversion technology. "High voltage direct current 
10transmission facilities" includes the high voltage direct 
11current converter station itself and associated high voltage 
12direct current transmission lines. Notwithstanding the 
13preceding, after September 15, 2021 (the effective date of 
14Public Act 102-662), an otherwise qualifying collection of 
15equipment does not qualify as high voltage direct current 
16transmission facilities unless (1) its developer entered into 
17a project labor agreement, is capable of transmitting 
18electricity at 525kv with an Illinois converter station 
19located and interconnected in the region of the PJM 
20Interconnection, LLC, and the system does not operate as a 
21public utility, as that term is defined in Section 3-105 of the 
22Public Utilities Act, serving more than 100,000 customers as 
23of January 1, 2021; or (2) its developer has entered into a 
24project labor agreement prior to construction, the project is 
25capable of transmitting electricity at 525 kilovolts or above, 
26and the project has a converter station that is located in this 
 
 
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1State or in a state adjacent to this State and is 
2interconnected to PJM Interconnection, LLC, the Midcontinent 
3Independent System Operator, Inc., or their successor.
4    "Hydropower" means any method of electricity generation or 
5storage that results from the flow of water, including 
6impoundment facilities, diversion facilities, and pumped 
7storage facilities. 
8    "Index price" means the real-time energy settlement price 
9at the applicable Illinois trading hub, such as PJM-NIHUB or 
10MISO-IL, for a given settlement period.
11    "Indexed renewable energy credit" means a tradable credit 
12that represents the environmental attributes of one megawatt 
13hour of energy produced from a renewable energy resource, the 
14price of which shall be calculated by subtracting the strike 
15price offered by a new utility-scale wind project or a new 
16utility-scale photovoltaic project from the index price in a 
17given settlement period. 
18    "Indexed renewable energy credit counterparty" has the 
19same meaning as "public utility" as defined in Section 3-105 
20of the Public Utilities Act.
21    "Local government" means a unit of local government as 
22defined in Section 1 of Article VII of the Illinois 
23Constitution.
24    "Modernized" or "retooled" means the construction, repair, 
25maintenance, or significant expansion of turbines and existing 
26hydropower dams. 
 
 
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1    "Municipality" means a city, village, or incorporated 
2town.
3    "Municipal utility" means a public utility owned and 
4operated by any subdivision or municipal corporation of this 
5State. 
6    "Nameplate capacity" means the aggregate inverter 
7nameplate capacity in kilowatts AC. 
8    "Person" means any natural person, firm, partnership, 
9corporation, either domestic or foreign, company, association, 
10limited liability company, joint stock company, or association 
11and includes any trustee, receiver, assignee, or personal 
12representative thereof.
13    "Project" means the planning, bidding, and construction of 
14a facility.
15    "Project labor agreement" means a pre-hire collective 
16bargaining agreement that covers all terms and conditions of 
17employment on a specific construction project and must include 
18the following:
19        (1) provisions establishing the minimum hourly wage 
20    for each class of labor organization employee;
21        (2) provisions establishing the benefits and other 
22    compensation for each class of labor organization 
23    employee;
24        (3) provisions establishing that no strike or disputes 
25    will be engaged in by the labor organization employees;
26        (4) provisions establishing that no lockout or 
 
 
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1    disputes will be engaged in by the general contractor 
2    building the project; and
3        (5) provisions for minorities and women, as defined 
4    under the Business Enterprise for Minorities, Women, and 
5    Persons with Disabilities Act, setting forth goals for 
6    apprenticeship hours to be performed by minorities and 
7    women and setting forth goals for total hours to be 
8    performed by underrepresented minorities and women.
9    A labor organization and the general contractor building 
10the project shall have the authority to include other terms 
11and conditions as they deem necessary. 
12    "Public utility" has the same definition as found in 
13Section 3-105 of the Public Utilities Act.
14    "Qualified combined heat and power systems" means systems 
15that, either simultaneously or sequentially, produce 
16electricity and useful thermal energy from a single fuel 
17source. Such systems are eligible for "renewable energy 
18credits" in an amount equal to its total energy output where a 
19renewable fuel is consumed or in an amount equal to the net 
20reduction in nonrenewable fuel consumed on a total energy 
21output basis. 
22    "Real property" means any interest in land together with 
23all structures, fixtures, and improvements thereon, including 
24lands under water and riparian rights, any easements, 
25covenants, licenses, leases, rights-of-way, uses, and other 
26interests, together with any liens, judgments, mortgages, or 
 
 
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1other claims or security interests related to real property.
2    "Renewable energy credit" means a tradable credit that 
3represents the environmental attributes of one megawatt hour 
4of energy produced from a renewable energy resource.
5    "Renewable energy resources" includes energy and its 
6associated renewable energy credit or renewable energy credits 
7from wind, solar thermal energy, photovoltaic cells and 
8panels, biodiesel, anaerobic digestion, crops and untreated 
9and unadulterated organic waste biomass, and hydropower that 
10does not involve new construction of dams, waste heat to power 
11systems, or qualified combined heat and power systems. For 
12purposes of this Act, landfill gas produced in the State is 
13considered a renewable energy resource. "Renewable energy 
14resources" does not include the incineration or burning of 
15tires, garbage, general household, institutional, and 
16commercial waste, industrial lunchroom or office waste, 
17landscape waste, railroad crossties, utility poles, or 
18construction or demolition debris, other than untreated and 
19unadulterated waste wood. "Renewable energy resources" also 
20includes high voltage direct current renewable energy credits 
21and the associated energy converted to alternating current by 
22a high voltage direct current converter station to the extent 
23that: (1) the generator of such renewable energy resource 
24contracted with a third party to transmit the energy over the 
25high voltage direct current transmission facilities, and (2) 
26the third-party contracting for delivery of renewable energy 
 
 
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1resources over the high voltage direct current transmission 
2facilities have ownership rights over the unretired associated 
3high voltage direct current renewable energy credit. 
4    "Retail customer" has the same definition as found in 
5Section 16-102 of the Public Utilities Act. 
6    "Revenue bond" means any bond, note, or other evidence of 
7indebtedness issued by the Authority, the principal and 
8interest of which is payable solely from revenues or income 
9derived from any project or activity of the Agency.
10    "Sequester" means permanent storage of carbon dioxide by 
11injecting it into a saline aquifer, a depleted gas reservoir, 
12or an oil reservoir, directly or through an enhanced oil 
13recovery process that may involve intermediate storage, 
14regardless of whether these activities are conducted by a 
15clean coal facility, a clean coal SNG facility, a clean coal 
16SNG brownfield facility, or a party with which a clean coal 
17facility, clean coal SNG facility, or clean coal SNG 
18brownfield facility has contracted for such purposes. 
19    "Service area" has the same definition as found in Section 
2016-102 of the Public Utilities Act. 
21    "Settlement period" means the period of time utilized by 
22MISO and PJM and their successor organizations as the basis 
23for settlement calculations in the real-time energy market. 
24    "Sourcing agreement" means (i) in the case of an electric 
25utility, an agreement between the owner of a clean coal 
26facility and such electric utility, which agreement shall have 
 
 
10400SB0025ham003- 136 -LRB104 07069 AAS 29208 a

1terms and conditions meeting the requirements of paragraph (3) 
2of subsection (d) of Section 1-75, (ii) in the case of an 
3alternative retail electric supplier, an agreement between the 
4owner of a clean coal facility and such alternative retail 
5electric supplier, which agreement shall have terms and 
6conditions meeting the requirements of Section 16-115(d)(5) of 
7the Public Utilities Act, and (iii) in case of a gas utility, 
8an agreement between the owner of a clean coal SNG brownfield 
9facility and the gas utility, which agreement shall have the 
10terms and conditions meeting the requirements of subsection 
11(h-1) of Section 9-220 of the Public Utilities Act. 
12    "Strike price" means a contract price for energy and 
13renewable energy credits from a new utility-scale wind project 
14or a new utility-scale photovoltaic project. 
15    "Subscriber" means a person who (i) takes delivery service 
16from an electric utility, and (ii) has a subscription of no 
17less than 200 watts to a community renewable generation 
18project that is located in the electric utility's service 
19area. No subscriber's subscriptions may total more than 40% of 
20the nameplate capacity of an individual community renewable 
21generation project. Entities that are affiliated by virtue of 
22a common parent shall not represent multiple subscriptions 
23that total more than 40% of the nameplate capacity of an 
24individual community renewable generation project.
25    "Subscription" means an interest in a community renewable 
26generation project expressed in kilowatts, which is sized 
 
 
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1primarily to offset part or all of the subscriber's 
2electricity usage. 
3    "Substitute natural gas" or "SNG" means a gas manufactured 
4by gasification of hydrocarbon feedstock, which is 
5substantially interchangeable in use and distribution with 
6conventional natural gas. 
7    "Total resource cost test" or "TRC test" means a standard 
8that is met if, for an investment in energy efficiency or 
9demand-response measures, the benefit-cost ratio is greater 
10than one. The benefit-cost ratio is the ratio of the net 
11present value of the total benefits of the program to the net 
12present value of the total costs as calculated over the 
13lifetime of the measures. A total resource cost test compares 
14the sum of avoided electric utility costs, representing the 
15benefits that accrue to the system and the participant in the 
16delivery of those efficiency measures and including avoided 
17costs associated with reduced use of natural gas or other 
18fuels, avoided costs associated with reduced water 
19consumption, and avoided costs associated with reduced 
20operation and maintenance costs, and avoided societal costs 
21associated with reductions in greenhouse gas emissions, as 
22well as other quantifiable societal benefits, to the sum of 
23all incremental costs of end-use measures that are implemented 
24due to the program (including both utility and participant 
25contributions), plus costs to administer, deliver, and 
26evaluate each demand-side program, to quantify the net savings 
 
 
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1obtained by substituting the demand-side program for supply 
2resources. The societal costs associated with greenhouse gas 
3emissions shall be $200 per short ton, expressed in 2025 
4dollars or the most recently approved estimate developed by 
5the federal government using a real discount rate consistent 
6with long-term Treasury bond yields, whichever is greater. 
7Changes in greenhouse gas emissions due to changes in 
8electricity consumption shall be estimated using long-run 
9marginal emissions rates developed by the National Renewable 
10Energy Laboratory's Cambium model or other Illinois-specific 
11modeling of comparable analytical rigor. In calculating 
12avoided costs of power and energy that an electric utility 
13would otherwise have had to acquire, reasonable estimates 
14shall be included of financial costs likely to be imposed by 
15future regulations and legislation on emissions of greenhouse 
16gases. In discounting future societal costs and benefits for 
17the purpose of calculating net present values, a societal 
18discount rate based on actual, long-term Treasury bond yields 
19should be used. Notwithstanding anything to the contrary, the 
20TRC test shall not include or take into account a calculation 
21of market price suppression effects or demand reduction 
22induced price effects. 
23    "Utility-scale solar project" means an electric generating 
24facility that:
25        (1) generates electricity using photovoltaic cells; 
26    and
 
 
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1        (2) has a nameplate capacity that is greater than 
2    5,000 kilowatts alternating current (AC). 
3    "Utility-scale wind project" means an electric generating 
4facility that:
5        (1) generates electricity using wind; and
6        (2) has a nameplate capacity that is greater than 
7    5,000 kilowatts. 
8    "Waste Heat to Power Systems" means systems that capture 
9and generate electricity from energy that would otherwise be 
10lost to the atmosphere without the use of additional fuel. 
11    "Zero emission credit" means a tradable credit that 
12represents the environmental attributes of one megawatt hour 
13of energy produced from a zero emission facility.
14    "Zero emission facility" means a facility that: (1) is 
15fueled by nuclear power; and (2) is interconnected with PJM 
16Interconnection, LLC or the Midcontinent Independent System 
17Operator, Inc., or their successors.
18(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23; 
19103-380, eff. 1-1-24.)
 
20    (20 ILCS 3855/1-20)
21    Sec. 1-20. General powers and duties of the Agency. 
22    (a) The Agency is authorized to do each of the following:
23        (1) Develop electricity procurement plans to ensure 
24    adequate, reliable, affordable, efficient, and 
25    environmentally sustainable electric service at the lowest 
 
 
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1    total cost over time, taking into account any benefits of 
2    price stability, for electric utilities that on December 
3    31, 2005 provided electric service to at least 100,000 
4    customers in Illinois and for small multi-jurisdictional 
5    electric utilities that (A) on December 31, 2005 served 
6    less than 100,000 customers in Illinois and (B) request a 
7    procurement plan for their Illinois jurisdictional load. 
8    Except as provided in paragraph (1.5) of this subsection 
9    (a), the electricity procurement plans shall be updated on 
10    an annual basis and shall include electricity generated 
11    from renewable resources sufficient to achieve the 
12    standards specified in this Act. Beginning with the 
13    delivery year commencing June 1, 2017, develop procurement 
14    plans to include zero emission credits generated from zero 
15    emission facilities sufficient to achieve the standards 
16    specified in this Act. Beginning with the delivery year 
17    commencing on June 1, 2022, the Agency is authorized to 
18    develop carbon mitigation credit procurement plans to 
19    include carbon mitigation credits generated from 
20    carbon-free energy resources sufficient to achieve the 
21    standards specified in this Act. 
22        (1.5) Develop a long-term renewable resources 
23    procurement plan in accordance with subsection (c) of 
24    Section 1-75 of this Act for renewable energy credits in 
25    amounts sufficient to achieve the standards specified in 
26    this Act for delivery years commencing June 1, 2017 and 
 
 
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1    for the programs and renewable energy credits specified in 
2    Section 1-56 of this Act. Electricity procurement plans 
3    for delivery years commencing after May 31, 2017, shall 
4    not include procurement of renewable energy resources. 
5        (2) Conduct competitive procurement processes to 
6    procure the supply resources identified in the electricity 
7    procurement plan, pursuant to Section 16-111.5 of the 
8    Public Utilities Act, and, for the delivery year 
9    commencing June 1, 2017, conduct procurement processes to 
10    procure zero emission credits from zero emission 
11    facilities, under subsection (d-5) of Section 1-75 of this 
12    Act. For the delivery year commencing June 1, 2022, the 
13    Agency is authorized to conduct procurement processes to 
14    procure carbon mitigation credits from carbon-free energy 
15    resources, under subsection (d-10) of Section 1-75 of this 
16    Act. 
17        (2.5) Beginning with the procurement for the 2017 
18    delivery year, conduct competitive procurement processes 
19    and implement programs to procure renewable energy credits 
20    identified in the long-term renewable resources 
21    procurement plan developed and approved under subsection 
22    (c) of Section 1-75 of this Act and Section 16-111.5 of the 
23    Public Utilities Act. 
24        (2.10) Oversee the procurement by electric utilities 
25    that served more than 300,000 customers in this State as 
26    of January 1, 2019 of renewable energy credits from new 
 
 
10400SB0025ham003- 142 -LRB104 07069 AAS 29208 a

1    renewable energy facilities to be installed, along with 
2    energy storage facilities, at or adjacent to the sites of 
3    electric generating facilities that burned coal as their 
4    primary fuel source as of January 1, 2016 in accordance 
5    with subsection (c-5) of Section 1-75 of this Act.
6        (2.15) Oversee the procurement by electric utilities 
7    of renewable energy credits from newly modernized or 
8    retooled hydropower dams or dams that have been converted 
9    to support hydropower generation. 
10        (3) Develop electric generation and co-generation 
11    facilities that use indigenous coal or renewable 
12    resources, or both, financed with bonds issued by the 
13    Illinois Finance Authority.
14        (4) Supply electricity from the Agency's facilities at 
15    cost to one or more of the following: municipal electric 
16    systems, governmental aggregators, or rural electric 
17    cooperatives in Illinois.
18        (5) Develop a long-term energy storage resources 
19    procurement plan and conduct competitive procurement 
20    processes in accordance with subsection (d-20) of Section 
21    1-75.    
22    (b) Except as otherwise limited by this Act, the Agency 
23has all of the powers necessary or convenient to carry out the 
24purposes and provisions of this Act, including without 
25limitation, each of the following:
26        (1) To have a corporate seal, and to alter that seal at 
 
 
10400SB0025ham003- 143 -LRB104 07069 AAS 29208 a

1    pleasure, and to use it by causing it or a facsimile to be 
2    affixed or impressed or reproduced in any other manner.
3        (2) To use the services of the Illinois Finance 
4    Authority necessary to carry out the Agency's purposes.
5        (3) To negotiate and enter into loan agreements and 
6    other agreements with the Illinois Finance Authority.
7        (4) To obtain and employ personnel and hire 
8    consultants that are necessary to fulfill the Agency's 
9    purposes, and to make expenditures for that purpose within 
10    the appropriations for that purpose.
11        (5) To purchase, receive, take by grant, gift, devise, 
12    bequest, or otherwise, lease, or otherwise acquire, own, 
13    hold, improve, employ, use, and otherwise deal in and 
14    with, real or personal property whether tangible or 
15    intangible, or any interest therein, within the State.
16        (6) To acquire real or personal property, whether 
17    tangible or intangible, including without limitation 
18    property rights, interests in property, franchises, 
19    obligations, contracts, and debt and equity securities, 
20    and to do so by the exercise of the power of eminent domain 
21    in accordance with Section 1-21; except that any real 
22    property acquired by the exercise of the power of eminent 
23    domain must be located within the State.
24        (7) To sell, convey, lease, exchange, transfer, 
25    abandon, or otherwise dispose of, or mortgage, pledge, or 
26    create a security interest in, any of its assets, 
 
 
10400SB0025ham003- 144 -LRB104 07069 AAS 29208 a

1    properties, or any interest therein, wherever situated.
2        (8) To purchase, take, receive, subscribe for, or 
3    otherwise acquire, hold, make a tender offer for, vote, 
4    employ, sell, lend, lease, exchange, transfer, or 
5    otherwise dispose of, mortgage, pledge, or grant a 
6    security interest in, use, and otherwise deal in and with, 
7    bonds and other obligations, shares, or other securities 
8    (or interests therein) issued by others, whether engaged 
9    in a similar or different business or activity.
10        (9) To make and execute agreements, contracts, and 
11    other instruments necessary or convenient in the exercise 
12    of the powers and functions of the Agency under this Act, 
13    including contracts with any person, including personal 
14    service contracts, or with any local government, State 
15    agency, or other entity; and all State agencies and all 
16    local governments are authorized to enter into and do all 
17    things necessary to perform any such agreement, contract, 
18    or other instrument with the Agency. No such agreement, 
19    contract, or other instrument shall exceed 40 years.
20        (10) To lend money, invest and reinvest its funds in 
21    accordance with the Public Funds Investment Act, and take 
22    and hold real and personal property as security for the 
23    payment of funds loaned or invested.
24        (11) To borrow money at such rate or rates of interest 
25    as the Agency may determine, issue its notes, bonds, or 
26    other obligations to evidence that indebtedness, and 
 
 
10400SB0025ham003- 145 -LRB104 07069 AAS 29208 a

1    secure any of its obligations by mortgage or pledge of its 
2    real or personal property, machinery, equipment, 
3    structures, fixtures, inventories, revenues, grants, and 
4    other funds as provided or any interest therein, wherever 
5    situated.
6        (12) To enter into agreements with the Illinois 
7    Finance Authority to issue bonds whether or not the income 
8    therefrom is exempt from federal taxation.
9        (13) To procure insurance against any loss in 
10    connection with its properties or operations in such 
11    amount or amounts and from such insurers, including the 
12    federal government, as it may deem necessary or desirable, 
13    and to pay any premiums therefor.
14        (14) To negotiate and enter into agreements with 
15    trustees or receivers appointed by United States 
16    bankruptcy courts or federal district courts or in other 
17    proceedings involving adjustment of debts and authorize 
18    proceedings involving adjustment of debts and authorize 
19    legal counsel for the Agency to appear in any such 
20    proceedings.
21        (15) To file a petition under Chapter 9 of Title 11 of 
22    the United States Bankruptcy Code or take other similar 
23    action for the adjustment of its debts.
24        (16) To enter into management agreements for the 
25    operation of any of the property or facilities owned by 
26    the Agency.
 
 
10400SB0025ham003- 146 -LRB104 07069 AAS 29208 a

1        (17) To enter into an agreement to transfer and to 
2    transfer any land, facilities, fixtures, or equipment of 
3    the Agency to one or more municipal electric systems, 
4    governmental aggregators, or rural electric agencies or 
5    cooperatives, for such consideration and upon such terms 
6    as the Agency may determine to be in the best interest of 
7    the residents of Illinois.
8        (18) To enter upon any lands and within any building 
9    whenever in its judgment it may be necessary for the 
10    purpose of making surveys and examinations to accomplish 
11    any purpose authorized by this Act.
12        (19) To maintain an office or offices at such place or 
13    places in the State as it may determine.
14        (20) To request information, and to make any inquiry, 
15    investigation, survey, or study that the Agency may deem 
16    necessary to enable it effectively to carry out the 
17    provisions of this Act.
18        (21) To accept and expend appropriations.
19        (22) To engage in any activity or operation that is 
20    incidental to and in furtherance of efficient operation to 
21    accomplish the Agency's purposes, including hiring 
22    employees that the Director deems essential for the 
23    operations of the Agency.
24        (23) To adopt, revise, amend, and repeal rules with 
25    respect to its operations, properties, and facilities as 
26    may be necessary or convenient to carry out the purposes 
 
 
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1    of this Act, subject to the provisions of the Illinois 
2    Administrative Procedure Act and Sections 1-22 and 1-35 of 
3    this Act.
4        (24) To establish and collect charges and fees as 
5    described in this Act.
6        (25) To conduct competitive gasification feedstock 
7    procurement processes to procure the feedstocks for the 
8    clean coal SNG brownfield facility in accordance with the 
9    requirements of Section 1-78 of this Act. 
10        (26) To review, revise, and approve sourcing 
11    agreements and mediate and resolve disputes between gas 
12    utilities and the clean coal SNG brownfield facility 
13    pursuant to subsection (h-1) of Section 9-220 of the 
14    Public Utilities Act. 
15        (27) To request, review and accept proposals, execute 
16    contracts, purchase renewable energy credits and otherwise 
17    dedicate funds from the Illinois Power Agency Renewable 
18    Energy Resources Fund to create and carry out the 
19    objectives of the Illinois Solar for All Program in 
20    accordance with Section 1-56 of this Act. 
21        (28) To ensure Illinois residents and business benefit 
22    from programs administered by the Agency and are properly 
23    protected from any deceptive or misleading marketing 
24    practices by participants in the Agency's programs and 
25    procurements. 
26    (c) In conducting the procurement of electricity or other 
 
 
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1products, beginning January 1, 2022, the Agency shall not 
2procure any products or services from persons or organizations 
3that are in violation of the Displaced Energy Workers Bill of 
4Rights, as provided under the Energy Community Reinvestment 
5Act at the time of the procurement event or fail to comply the 
6labor standards established in subparagraph (Q) of paragraph 
7(1) of subsection (c) of Section 1-75. 
8(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
 
9    (20 ILCS 3855/1-56)
10    Sec. 1-56. Illinois Power Agency Renewable Energy 
11Resources Fund; Illinois Solar for All Program.
12    (a) The Illinois Power Agency Renewable Energy Resources 
13Fund is created as a special fund in the State treasury.
14    (b) The Illinois Power Agency Renewable Energy Resources 
15Fund shall be administered by the Agency as described in this 
16subsection (b), provided that the changes to this subsection 
17(b) made by Public Act 99-906 shall not interfere with 
18existing contracts under this Section. 
19        (1) The Illinois Power Agency Renewable Energy 
20    Resources Fund shall be used to purchase renewable energy 
21    credits according to any approved procurement plan 
22    developed by the Agency prior to June 1, 2017.
23        (2) The Illinois Power Agency Renewable Energy 
24    Resources Fund shall also be used to create the Illinois 
25    Solar for All Program, which provides incentives for 
 
 
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1    low-income distributed generation and community solar 
2    projects, and other associated approved expenditures. The 
3    objectives of the Illinois Solar for All Program are to 
4    bring photovoltaics to low-income communities in this 
5    State in a manner that maximizes the development of new 
6    photovoltaic generating facilities, to create a long-term, 
7    low-income solar marketplace throughout this State, to 
8    integrate, through interaction with stakeholders, with 
9    existing energy efficiency initiatives, and to minimize 
10    administrative costs. The Illinois Solar for All Program 
11    shall be implemented in a manner that seeks to minimize 
12    administrative costs, and maximize efficiencies and 
13    synergies available through coordination with similar 
14    initiatives, including the Adjustable Block program 
15    described in subparagraphs (K) through (M) of paragraph 
16    (1) of subsection (c) of Section 1-75, energy efficiency 
17    programs, job training programs, and community action 
18    agencies , and agencies that administer the Low-Income 
19    Home Energy Assistance Program. The Agency shall strive to 
20    ensure that renewable energy credits procured through the 
21    Illinois Solar for All Program and each of its subprograms 
22    are purchased from projects across the breadth of 
23    low-income and environmental justice communities in 
24    Illinois, including both urban and rural communities, are 
25    not concentrated in a few communities, and do not exclude 
26    particular low-income or environmental justice 
 
 
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1    communities. The Agency shall include a description of its 
2    proposed approach to the design, administration, 
3    implementation and evaluation of the Illinois Solar for 
4    All Program, as part of the long-term renewable resources 
5    procurement plan authorized by subsection (c) of Section 
6    1-75 of this Act, and the program shall be designed to grow 
7    the low-income solar market. The Agency or utility, as 
8    applicable, shall purchase renewable energy credits from 
9    the (i) photovoltaic distributed renewable energy 
10    generation projects and (ii) community solar projects that 
11    are procured under procurement processes authorized by the 
12    long-term renewable resources procurement plans approved 
13    by the Commission.
14        The Illinois Solar for All Program shall include the 
15    program offerings described in subparagraphs (A) through 
16    (E) of this paragraph (2), which the Agency shall 
17    implement through contracts with third-party providers 
18    and, subject to appropriation, pay the approximate amounts 
19    identified using monies available in the Illinois Power 
20    Agency Renewable Energy Resources Fund. Each contract that 
21    provides for the installation of solar facilities shall 
22    provide that the solar facilities will produce energy and 
23    economic benefits, at a level determined by the Agency to 
24    be reasonable, for the participating low-income customers. 
25    The monies available in the Illinois Power Agency 
26    Renewable Energy Resources Fund and not otherwise 
 
 
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1    committed to contracts executed under subsection (i) of 
2    this Section, as well as, in the case of the programs 
3    described under subparagraphs (A) through (E) of this 
4    paragraph (2), funding authorized pursuant to subparagraph 
5    (O) of paragraph (1) of subsection (c) of Section 1-75 of 
6    this Act, shall initially be allocated among the programs 
7    described in this paragraph (2), as follows: 35% of these 
8    funds shall be allocated to programs described in 
9    subparagraphs (A) and (E) of this paragraph (2), 40% of 
10    these funds shall be allocated to programs described in 
11    subparagraph (B) of this paragraph (2), and 25% of these 
12    funds shall be allocated to programs described in 
13    subparagraph (C) of this paragraph (2). The allocation of 
14    funds among subparagraphs (A), (B), (C), and (E) of this 
15    paragraph (2) may be changed if the Agency, after 
16    receiving input through a stakeholder process, determines 
17    incentives in subparagraph subparagraphs (A), (B), (C), or 
18    (E) of this paragraph (2) have not been adequately 
19    subscribed to fully utilize available Illinois Solar for 
20    All Program funds.
21        Contracts that will be paid with funds in the Illinois 
22    Power Agency Renewable Energy Resources Fund shall be 
23    executed by the Agency. Contracts that will be paid with 
24    funds collected by an electric utility shall be executed 
25    by the electric utility.
26        Contracts under the Illinois Solar for All Program 
 
 
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1    shall include an approach, as set forth in the long-term 
2    renewable resources procurement plans, to ensure the 
3    wholesale market value of the energy is credited to 
4    participating low-income customers or organizations and to 
5    ensure tangible economic benefits flow directly to program 
6    participants, except in the case of low-income 
7    multi-family housing where the low-income customer does 
8    not directly pay for energy. Priority shall be given to 
9    projects that demonstrate meaningful involvement of 
10    low-income community members in designing the initial 
11    proposals. Acceptable proposals to implement projects must 
12    demonstrate the applicant's ability to conduct initial 
13    community outreach, education, and recruitment of 
14    low-income participants in the community. Projects 
15    submitted by approved vendors must either comply with the 
16    minimum equity standard set forth in subsection (c-10) of 
17    Section 1-75 of this Act or must include job training 
18    opportunities if available, with the specific level of 
19    trainee usage to be determined through the Agency's 
20    long-term renewable resources procurement plan, and the 
21    Illinois Solar for All Program Administrator shall 
22    coordinate with the job training programs described in 
23    paragraph (1) of subsection (a) of Section 16-108.12 of 
24    the Public Utilities Act and in the Energy Transition Act. 
25        The Agency shall make every effort to ensure that 
26    small and emerging businesses, particularly those located 
 
 
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1    in low-income and environmental justice communities, are 
2    able to participate in the Illinois Solar for All Program. 
3    These efforts may include, but shall not be limited to, 
4    proactive support from the program administrator, 
5    different or preferred access to subprograms and 
6    administrator-identified customers or grassroots 
7    education provider-identified customers, and different 
8    incentive levels. The Agency shall report on progress and 
9    barriers to participation of small and emerging businesses 
10    in the Illinois Solar for All Program at least once a year. 
11    The report shall be made available on the Agency's website 
12    and, in years when the Agency is updating its long-term 
13    renewable resources procurement plan, included in that 
14    Plan. 
15            (A) Low-income single-family and small multifamily 
16        solar incentive. This program will provide incentives 
17        to low-income customers, either directly or through 
18        solar providers, to increase the participation of 
19        low-income households in photovoltaic on-site 
20        distributed generation at residential buildings 
21        containing one to 4 units. Companies participating in 
22        this program that install solar panels shall commit to 
23        meeting a minimum equity standard or hiring job 
24        trainees for a portion of their low-income 
25        installations, and an administrator shall facilitate 
26        partnering the companies that install solar panels 
 
 
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1        with entities that provide solar panel installation 
2        job training. It is a goal of this program that a 
3        minimum of 25% of the incentives for this program be 
4        allocated to projects located within environmental 
5        justice communities. Contracts entered into under this 
6        paragraph may be entered into with an entity that will 
7        develop and administer the program and shall also 
8        include contracts for renewable energy credits from 
9        the photovoltaic distributed generation that is the 
10        subject of the program, as set forth in the long-term 
11        renewable resources procurement plan. Additionally:
12                (i) The Agency shall reserve a portion of this 
13            program for projects that promote energy 
14            sovereignty through ownership of projects by 
15            low-income households, not-for-profit 
16            organizations providing services to low-income 
17            households, affordable housing owners, community 
18            cooperatives, or community-based limited liability 
19            companies providing services to low-income 
20            households. Projects that feature energy ownership 
21            should ensure that local people have control of 
22            the project and reap benefits from the project 
23            over and above energy bill savings. The Agency may 
24            consider the inclusion of projects that promote 
25            ownership over time or that involve partial 
26            project ownership by communities, as promoting 
 
 
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1            energy sovereignty. Incentives for projects that 
2            promote energy sovereignty may be higher than 
3            incentives for equivalent projects that do not 
4            promote energy sovereignty under this same 
5            program.
6                (ii) Through its long-term renewable resources 
7            procurement plan, the Agency shall consider 
8            additional program and contract requirements to 
9            ensure faithful compliance by applicants 
10            benefiting from preferences for projects 
11            designated to promote energy sovereignty. The 
12            Agency shall make every effort to enable solar 
13            providers already participating in the Adjustable 
14            Block program Program under subparagraph (K) of 
15            paragraph (1) of subsection (c) of Section 1-75 of 
16            this Act, and particularly solar providers 
17            developing projects under item (i) of subparagraph 
18            (K) of paragraph (1) of subsection (c) of Section 
19            1-75 of this Act to easily participate in the 
20            Low-Income Distributed Generation Incentive 
21            program described under this subparagraph (A), and 
22            vice versa. This effort may include, but shall not 
23            be limited to, utilizing similar or the same 
24            application systems and processes, utilizing    
25            similar or the same forms and formats of 
26            communication, and providing active outreach to 
 
 
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1            companies participating in one program but not the 
2            other. The Agency shall report on efforts made to 
3            encourage this cross-participation in its 
4            long-term renewable resources procurement plan. 
5                (iii) To maximize equitable participation in 
6            this program and overcome challenges facing the 
7            development of residential solar projects, the 
8            Agency may propose a payment structure for 
9            contracts executed pursuant to this subparagraph 
10            (A) under which applicant firms are advanced 
11            capital that is disbursed after contract execution 
12            but before the contracted project's energization, 
13            upon a demonstration of qualification or need 
14            under criteria established by the Agency that are 
15            focused on supporting the small and emerging 
16            businesses and the businesses that most acutely 
17            face barriers to capital access, which severely 
18            limits the businesses' participation in the 
19            program described in this subparagraph (A). The 
20            amount or percentage of capital advanced before 
21            project energization shall be designed to overcome 
22            the barriers in access to capital that are faced 
23            by an applicant. The amount or percentage of 
24            advanced capital may vary under this subparagraph 
25            (A) by an applicant's demonstration of need, with 
26            such levels to be established through the 
 
 
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1            Long-Term Renewable Resources Procurement Plan and 
2            any application requirements or evaluation 
3            criteria developed under that Plan.    
4            (B) Low-Income Community Solar Project Initiative. 
5        Incentives shall be offered to low-income customers, 
6        either directly or through developers, to increase the 
7        participation of low-income subscribers of community 
8        solar projects. The developer of each project shall 
9        identify its partnership with community stakeholders 
10        regarding the location, development, and participation 
11        in the project, provided that nothing shall preclude a 
12        project from including an anchor tenant that does not 
13        qualify as low-income. Companies participating in this 
14        program that develop or install solar projects shall 
15        commit to meeting a minimum equity standard or to    
16        hiring job trainees for a portion of their low-income 
17        installations, and an administrator shall facilitate 
18        partnering the companies that install solar projects 
19        with entities that provide solar installation and 
20        related job training. It is a goal of this program that 
21        a minimum of 25% of the incentives for this program be 
22        allocated to community photovoltaic projects in 
23        environmental justice communities. The Agency shall 
24        reserve a portion of this program for projects that 
25        promote energy sovereignty through ownership of 
26        projects by low-income households, not-for-profit 
 
 
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1        organizations providing services to low-income 
2        households, affordable housing owners, or 
3        community-based limited liability companies providing 
4        services to low-income households. Projects that 
5        feature energy ownership should ensure that local 
6        people have control of the project and reap benefits 
7        from the project over and above energy bill savings. 
8        The Agency may consider the inclusion of projects that 
9        promote ownership over time or that involve partial 
10        project ownership by communities, as promoting energy 
11        sovereignty. Incentives for projects that promote 
12        energy sovereignty may be higher than incentives for 
13        equivalent projects that do not promote energy 
14        sovereignty under this same program. Contracts entered 
15        into under this paragraph may be entered into with 
16        developers and shall also include contracts for 
17        renewable energy credits related to the program.
18            (C) Incentives for non-profits and public 
19        facilities. Under this program funds shall be used to 
20        support on-site photovoltaic distributed renewable 
21        energy generation devices to serve the load associated 
22        with not-for-profit customers and to support 
23        photovoltaic distributed renewable energy generation 
24        that uses photovoltaic technology to serve the load 
25        associated with public sector customers taking service 
26        at public buildings. Master-metered multifamily 
 
 
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1        buildings that primarily house income-eligible 
2        residents may qualify under this subparagraph (C). 
3        Nonprofits and public facilities that can demonstrate 
4        that the nonprofit or public facility serves 
5        income-qualified or environmental justice communities 
6        may potentially qualify for the program, regardless of 
7        physical location. Qualification may be determined 
8        using the same procedures applied to critical service 
9        provider requests for the purpose of establishing 
10        project eligibility in areas that are not designated 
11        as income-eligible or environmental justice 
12        communities. Companies participating in this program 
13        that develop or install solar projects shall commit to 
14        meeting a minimum equity standard or to hiring job 
15        trainees for a portion of their low-income 
16        installations, and an administrator shall facilitate 
17        partnering the companies that install solar projects 
18        with entities that provide solar installation and 
19        related job training. Through its long-term renewable 
20        resources procurement plan, the Agency shall consider 
21        additional program and contract requirements to ensure 
22        faithful compliance by applicants benefiting from 
23        preferences for projects designated to promote energy 
24        sovereignty. It is a goal of this program that at least 
25        25% of the incentives for this program be allocated to 
26        projects located in environmental justice communities. 
 
 
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1        Contracts entered into under this paragraph may be 
2        entered into with an entity that will develop and 
3        administer the program or with developers and shall 
4        also include contracts for renewable energy credits 
5        related to the program.
6            (D) (Blank). 
7            (E) Low-income large multifamily solar incentive. 
8        This program shall provide incentives to low-income 
9        customers, either directly or through solar providers, 
10        to increase the participation of low-income households 
11        in photovoltaic on-site distributed generation at 
12        residential buildings with 5 or more units. Companies 
13        participating in this program that develop or install 
14        solar projects shall commit to meeting a minimum 
15        equity standard or to hiring job trainees for a 
16        portion of their low-income installations, and an 
17        administrator shall facilitate partnering the 
18        companies that install solar projects with entities 
19        that provide solar installation and related job 
20        training. It is a goal of this program that a minimum 
21        of 25% of the incentives for this program be allocated 
22        to projects located within environmental justice 
23        communities. The Agency shall reserve a portion of 
24        this program for projects that promote energy 
25        sovereignty through ownership of projects by 
26        low-income households, not-for-profit organizations 
 
 
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1        providing services to low-income households, 
2        affordable housing owners, or community-based limited 
3        liability companies providing services to low-income 
4        households. Projects that feature energy ownership 
5        should ensure that local people have control of the 
6        project and reap benefits from the project over and 
7        above energy bill savings. The Agency may consider the 
8        inclusion of projects that promote ownership over time 
9        or that involve partial project ownership by 
10        communities, as promoting energy sovereignty. 
11        Incentives for projects that promote energy 
12        sovereignty may be higher than incentives for 
13        equivalent projects that do not promote energy 
14        sovereignty under this same program. 
15        The requirement that a qualified person, as defined in 
16    paragraph (1) of subsection (i) of this Section, install 
17    photovoltaic devices does not apply to the Illinois Solar 
18    for All Program described in this subsection (b).
19        In addition to the programs outlined in paragraphs (A) 
20    through (E), the Agency and other parties may propose 
21    additional programs through the long-term renewable 
22    resources procurement plan Long-Term Renewable Resources 
23    Procurement Plan developed and approved under paragraph 
24    (5) of subsection (b) of Section 16-111.5 of the Public 
25    Utilities Act. Additional programs may target market 
26    segments not specified above and may also include 
 
 
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1    incentives targeted to increase the uptake of 
2    nonphotovoltaic technologies by low-income customers, 
3    including energy storage paired with photovoltaics, if the 
4    Commission determines that the Illinois Solar for All 
5    Program would provide greater benefits to the public 
6    health and well-being of low-income residents through also 
7    supporting that additional program versus supporting 
8    programs already authorized. 
9        (3) Costs associated with the Illinois Solar for All 
10    Program and its components described in paragraph (2) of 
11    this subsection (b), including, but not limited to, costs 
12    associated with procuring experts, consultants, and the 
13    program administrator referenced in this subsection (b) 
14    and related incremental costs, costs related to income 
15    verification and facilitating customer participation in 
16    the program through referrals and other methods, costs 
17    related to obtaining feedback on the program from parties 
18    that do not have a financial interest, and costs related 
19    to the evaluation of the Illinois Solar for All Program, 
20    may be paid for using monies in the Illinois Power Agency 
21    Renewable Energy Resources Fund, and funds allocated 
22    pursuant to subparagraph (O) of paragraph (1) of 
23    subsection (c) of Section 1-75, but the Agency or program 
24    administrator shall strive to minimize costs in the 
25    implementation of the program. The Agency or contracting 
26    electric utility shall purchase renewable energy credits 
 
 
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1    from generation that is the subject of a contract under 
2    subparagraphs (A) through (E) of paragraph (2) of this 
3    subsection (b), and may pay for such renewable energy 
4    credits through an upfront payment per installed kilowatt 
5    of nameplate capacity paid once the device is 
6    interconnected at the distribution system level of the 
7    interconnecting utility and verified as energized. Unless 
8    otherwise provided in the Agency's long-term renewable 
9    resources procurement plan, payments Payments for 
10    renewable energy credits shall be in exchange for all 
11    renewable energy credits generated by the system during 
12    the first 15 years of operation and shall be structured to 
13    overcome barriers to participation in the solar market by 
14    the low-income community. The incentives provided for in 
15    this Section may be implemented through the pricing of 
16    renewable energy credits where the prices paid for the 
17    credits are higher than the prices from programs offered 
18    under subsection (c) of Section 1-75 of this Act to 
19    account for the additional capital necessary to 
20    successfully access targeted market segments. The Agency 
21    or contracting electric utility shall retire any renewable 
22    energy credits purchased under this program and the 
23    credits shall count toward the obligation under subsection 
24    (c) of Section 1-75 of this Act for the electric utility to 
25    which the project is interconnected, if applicable.
26        The Agency shall direct that up to 5% of the funds 
 
 
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1    available under the Illinois Solar for All Program to 
2    community-based groups and other qualifying organizations 
3    to assist in community-driven education efforts related to 
4    the Illinois Solar for All Program, including general 
5    energy education, job training program outreach efforts, 
6    and other activities deemed to be qualified by the Agency. 
7    Grassroots education funding shall not be used to support 
8    the marketing by solar project development firms and 
9    organizations, unless such education provides equal 
10    opportunities for all applicable firms and organizations.
11        The Agency may direct up to 25% of the funds currently 
12    allocated to subparagraphs (A), (C), and (E) of paragraph 
13    (2) toward the Illinois Storage for All Program, which 
14    provides incentives through grants, rebates, or other 
15    incentives to encourage development of energy storage 
16    colocated with photovoltaic distributed renewable energy 
17    generation devices developed through the Illinois Solar 
18    for All Program. Any unused Storage for All funds during a 
19    program year may be reallocated to other Solar for All 
20    Program projects that are waitlisted or otherwise not 
21    selected due to funding limitation per the Agency's 
22    defined process. The Illinois Storage for All Program 
23    shall be available to current and future participants of 
24    the low-income single-family and multifamily subprogram 
25    described in subparagraphs (A) and (E) of paragraph (2), 
26    and the subprogram for nonprofit and public facilities 
 
 
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1    described in subparagraph (C) of paragraph (2). If 
2    developed, the Illinois Storage for All Program may be 
3    designed to support community energy resilience, disaster 
4    preparedness, and energy bill reductions, particularly for 
5    residents of low-income and environmental justice 
6    communities. The Agency may propose the funding amount, 
7    structure, and details of the Illinois Storage for All 
8    Program in the Agency's long-term renewable resources 
9    procurement plan described in subsection (c) of Section 
10    1-75 of this Act and Section 16-111.5 of the Public 
11    Utilities Act, or through its energy storage resources 
12    procurement plan described in subsection (d-20) of Section 
13    1-75 of this Act. As part of the development of its initial 
14    energy storage resources procurement plan, the Agency 
15    shall engage stakeholders in the development of the 
16    Illinois Storage for All Program, including, but not 
17    limited to, members of the Illinois Commission on 
18    Environmental Justice described in Section 10 of the 
19    Environmental Justice Act, representatives of approved 
20    vendors participating in the Illinois Solar for All 
21    Program, representatives of community-based 
22    organizations, and members of the Illinois Solar for All 
23    Stakeholder Advisory Group. The stakeholder process shall 
24    include, but not be limited to, an exploration of how to 
25    ensure that the distributed storage will be accessible to 
26    income-qualified households with zero upfront costs and in 
 
 
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1    coordination with job training programs, as well as how 
2    the program may be supported by other programs or 
3    initiatives to maximize storage benefits and limit 
4    double-counting of incentives.    
5        (4) The Agency shall, consistent with the requirements 
6    of this subsection (b), propose the Illinois Solar for All 
7    Program terms, conditions, and requirements, including the 
8    prices to be paid for renewable energy credits, and which 
9    prices may be determined through a formula, through the 
10    development, review, and approval of the Agency's 
11    long-term renewable resources procurement plan described 
12    in subsection (c) of Section 1-75 of this Act and Section 
13    16-111.5 of the Public Utilities Act. In the course of the 
14    Commission proceeding initiated to review and approve the 
15    plan, including the Illinois Solar for All Program 
16    proposed by the Agency, a party may propose an additional 
17    low-income solar or solar incentive program, or 
18    modifications to the programs proposed by the Agency, and 
19    the Commission may approve an additional program, or 
20    modifications to the Agency's proposed program, if the 
21    additional or modified program more effectively maximizes 
22    the benefits to low-income customers after taking into 
23    account all relevant factors, including, but not limited 
24    to, the extent to which a competitive market for 
25    low-income solar has developed. Following the Commission's 
26    approval of the Illinois Solar for All Program, the Agency 
 
 
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1    or a party may propose adjustments to the program terms, 
2    conditions, and requirements, including the price offered 
3    to new systems, to ensure the long-term viability and 
4    success of the program. The Commission shall review and 
5    approve any modifications to the program through the plan 
6    revision process described in Section 16-111.5 of the 
7    Public Utilities Act.
8        (5) The Agency shall issue a request for 
9    qualifications for a third-party program administrator or 
10    administrators to administer all or a portion of the 
11    Illinois Solar for All Program. The third-party program 
12    administrator shall be chosen through a competitive bid 
13    process based on selection criteria and requirements 
14    developed by the Agency, including, but not limited to, 
15    experience in administering low-income energy programs and 
16    overseeing statewide clean energy or energy efficiency 
17    services. If the Agency retains a program administrator or 
18    administrators to implement all or a portion of the 
19    Illinois Solar for All Program, each administrator shall 
20    periodically submit reports to the Agency and Commission 
21    for each program that it administers, at appropriate 
22    intervals to be identified by the Agency in its long-term 
23    renewable resources procurement plan, subject to 
24    Commission approval, provided that the reporting interval 
25    is at least an annual period quarterly. The third-party 
26    program administrator may be, but need not be, the same 
 
 
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1    administrator as for the Adjustable Block program 
2    described in subparagraphs (K) through (M) of paragraph 
3    (1) of subsection (c) of Section 1-75. The Agency, through 
4    its long-term renewable resources procurement plan 
5    approval process, shall also determine if individual 
6    subprograms of the Illinois Solar for All Program are 
7    better served by a different or separate Program 
8    Administrator.
9        The third-party administrator's responsibilities 
10    shall also include facilitating placement for graduates of 
11    Illinois-based renewable energy-specific job training 
12    programs, including the Clean Jobs Workforce Network 
13    Program and the Illinois Climate Works Preapprenticeship 
14    Program administered by the Department of Commerce and 
15    Economic Opportunity and programs administered under 
16    Section 16-108.12 of the Public Utilities Act. To increase 
17    the uptake of trainees by participating firms, the 
18    administrator shall also develop a web-based clearinghouse 
19    for information available to both job training program 
20    graduates and firms participating, directly or indirectly, 
21    in Illinois solar incentive programs. The program 
22    administrator shall also coordinate its activities with 
23    entities implementing electric and natural gas 
24    income-qualified energy efficiency programs, including 
25    customer referrals to and from such programs, and connect 
26    prospective low-income solar customers with any existing 
 
 
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1    deferred maintenance programs where applicable. 
2        (6) The long-term renewable resources procurement plan 
3    shall also provide for an independent evaluation of the 
4    Illinois Solar for All Program. At least every 5 2 years, 
5    the Agency shall select an independent evaluator to review 
6    and report on the Illinois Solar for All Program and the 
7    performance of the third-party program administrator of 
8    the Illinois Solar for All Program. The evaluation shall 
9    be based on objective criteria developed through a public 
10    stakeholder process. The process shall include feedback 
11    and participation from Illinois Solar for All Program 
12    stakeholders, including participants and organizations in 
13    environmental justice and historically underserved 
14    communities. The report shall include a summary of the 
15    evaluation of the Illinois Solar for All Program based on 
16    the stakeholder developed objective criteria. The report 
17    shall include the number of projects installed; the total 
18    installed capacity in kilowatts; the average cost per 
19    kilowatt of installed capacity to the extent reasonably 
20    obtainable by the Agency; the number of jobs or job 
21    opportunities created; economic, social, and environmental 
22    benefits created; and the total administrative costs 
23    expended by the Agency and program administrator to 
24    implement and evaluate the program. The report shall be 
25    prepared at least every 2 years and shall be delivered to 
26    the Commission and posted on the Agency's website, and 
 
 
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1    shall be used, as needed, to revise the Illinois Solar for 
2    All Program. The Commission shall also consider the 
3    results of the evaluation as part of its review of the 
4    long-term renewable resources procurement plan under 
5    subsection (c) of Section 1-75 of this Act.
6        (7) If additional funding for the programs described 
7    in this subsection (b) is available under subsection (k) 
8    of Section 16-108 of the Public Utilities Act, then the 
9    Agency shall submit a procurement plan to the Commission 
10    no later than September 1, 2018, that proposes how the 
11    Agency will procure programs on behalf of the applicable 
12    utility. After notice and hearing, the Commission shall 
13    approve, or approve with modification, the plan no later 
14    than November 1, 2018.
15        (8) As part of the development and update of the 
16    long-term renewable resources procurement plan authorized 
17    by subsection (c) of Section 1-75 of this Act, the Agency 
18    shall plan for: (A) actions to refer customers from the 
19    Illinois Solar for All Program to electric and natural gas 
20    income-qualified energy efficiency programs, and vice 
21    versa, with the goal of increasing participation in both 
22    of these programs; (B) effective procedures for data 
23    sharing, as needed, to effectuate referrals between the 
24    Illinois Solar for All Program and both electric and 
25    natural gas income-qualified energy efficiency programs, 
26    including sharing customer information directly with the 
 
 
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1    utilities, as needed and appropriate; and (C) efforts to 
2    identify any existing deferred maintenance programs for 
3    which prospective Solar for All Program customers may be 
4    eligible and connect prospective customers for whom 
5    deferred maintenance is or may be a barrier to solar 
6    installation to those programs. 
7    Income verification for participation in the Illinois 
8Solar for All subprograms described in subparagraphs (A) and 
9(C) of paragraph (2) may include pathways for verification 
10that rely on self-attestation by the applicant if the 
11applicant's residence is located within a low-income or 
12environmental justice community as defined in this subsection 
13(b). The Agency shall proactively explore approaches that make 
14the income verification process less burdensome for residents 
15of low-income or environmental justice communities, as defined 
16in this subsection (b).    
17    As used in this subsection (b), "low-income households" 
18means persons and families whose income does not exceed 80% of 
19area median income, adjusted for family size and revised every 
20year.
21    For the purposes of this subsection (b), the Agency shall 
22define "environmental justice community" based on the 
23methodologies and findings established by the Agency and the 
24Administrator for the Illinois Solar for All Program in its 
25initial long-term renewable resources procurement plan and as 
26updated by the Agency and the Administrator for the Illinois 
 
 
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1Solar for All Program as part of the long-term renewable 
2resources procurement plan update. 
3    (b-5) After the receipt of all payments required by 
4Section 16-115D of the Public Utilities Act, no additional 
5funds shall be deposited into the Illinois Power Agency 
6Renewable Energy Resources Fund unless directed by order of 
7the Commission.
8    (b-10) After the receipt of all payments required by 
9Section 16-115D of the Public Utilities Act and payment in 
10full of all contracts executed by the Agency under subsections 
11(b) and (i) of this Section, if the balance of the Illinois 
12Power Agency Renewable Energy Resources Fund is under $5,000, 
13then the Fund shall be inoperative and any remaining funds and 
14any funds submitted to the Fund after that date, shall be 
15transferred to the Supplemental Low-Income Energy Assistance 
16Fund for use in the Low-Income Home Energy Assistance Program, 
17as authorized by the Energy Assistance Act.
18    (b-15) The prevailing wage requirements set forth in the 
19Prevailing Wage Act apply to each project that is undertaken 
20pursuant to one or more of the programs of incentives and 
21initiatives described in subsection (b) of this Section and 
22for which a project application is submitted to the program 
23after June 30, 2023 (the effective date of Public Act 103-188)    
24this amendatory Act of the 103rd General Assembly, except (i) 
25projects that serve single-family or multi-family residential 
26buildings and (ii) projects with an aggregate capacity of less 
 
 
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1than 100 kilowatts that serve houses of worship. The Agency 
2shall require verification that all construction performed on 
3a project by the renewable energy credit delivery contract 
4holder, its contractors, or its subcontractors relating to the 
5construction of the facility is performed by workers receiving 
6an amount for that work that is greater than or equal to the 
7general prevailing rate of wages as that term is defined in the 
8Prevailing Wage Act, and the Agency may adjust renewable 
9energy credit prices to account for increased labor costs.
10    In this subsection (b-15), "house of worship" has the 
11meaning given in subparagraph (Q) of paragraph (1) of 
12subsection (c) of Section 1-75. 
13    (c) (Blank).
14    (d) (Blank).
15    (e) All renewable energy credits procured using monies 
16from the Illinois Power Agency Renewable Energy Resources Fund 
17shall be permanently retired.
18    (f) The selection of one or more third-party program 
19managers or administrators, the selection of the independent 
20evaluator, and the procurement processes described in this 
21Section are exempt from the requirements of the Illinois 
22Procurement Code, under Section 20-10 of that Code.
23    (g) All disbursements from the Illinois Power Agency 
24Renewable Energy Resources Fund shall be made only upon 
25warrants of the Comptroller drawn upon the Treasurer as 
26custodian of the Fund upon vouchers signed by the Director or 
 
 
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1by the person or persons designated by the Director for that 
2purpose. The Comptroller is authorized to draw the warrant 
3upon vouchers so signed. The Treasurer shall accept all 
4warrants so signed and shall be released from liability for 
5all payments made on those warrants.
6    (h) The Illinois Power Agency Renewable Energy Resources 
7Fund shall not be subject to sweeps, administrative charges, 
8or chargebacks, including, but not limited to, those 
9authorized under Section 8h of the State Finance Act, that 
10would in any way result in the transfer of any funds from this 
11Fund to any other fund of this State or in having any such 
12funds utilized for any purpose other than the express purposes 
13set forth in this Section.
14    (h-5) The Agency may assess fees to each bidder to recover 
15the costs incurred in connection with a procurement process 
16held under this Section. Fees collected from bidders shall be 
17deposited into the Illinois Power Agency Renewable Energy 
18Resources Fund. 
19    (i) Supplemental procurement process.
20        (1) Within 90 days after June 30, 2014 (the effective 
21    date of Public Act 98-672), the Agency shall develop a 
22    one-time supplemental procurement plan limited to the 
23    procurement of renewable energy credits, if available, 
24    from new or existing photovoltaics, including, but not 
25    limited to, distributed photovoltaic generation. Nothing 
26    in this subsection (i) requires procurement of wind 
 
 
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1    generation through the supplemental procurement.
2        Renewable energy credits procured from new 
3    photovoltaics, including, but not limited to, distributed 
4    photovoltaic generation, under this subsection (i) must be 
5    procured from devices installed by a qualified person. In 
6    its supplemental procurement plan, the Agency shall 
7    establish contractually enforceable mechanisms for 
8    ensuring that the installation of new photovoltaics is 
9    performed by a qualified person.
10        For the purposes of this paragraph (1), "qualified 
11    person" means a person who performs installations of 
12    photovoltaics, including, but not limited to, distributed 
13    photovoltaic generation, and who: (A) has completed an 
14    apprenticeship as a journeyman electrician from a United 
15    States Department of Labor registered electrical 
16    apprenticeship and training program and received a 
17    certification of satisfactory completion; or (B) does not 
18    currently meet the criteria under clause (A) of this 
19    paragraph (1), but is enrolled in a United States 
20    Department of Labor registered electrical apprenticeship 
21    program, provided that the person is directly supervised 
22    by a person who meets the criteria under clause (A) of this 
23    paragraph (1); or (C) has obtained one of the following 
24    credentials in addition to attesting to satisfactory 
25    completion of at least 5 years or 8,000 hours of 
26    documented hands-on electrical experience: (i) a North 
 
 
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1    American Board of Certified Energy Practitioners (NABCEP) 
2    Installer Certificate for Solar PV; (ii) an Underwriters 
3    Laboratories (UL) PV Systems Installer Certificate; (iii) 
4    an Electronics Technicians Association, International 
5    (ETAI) Level 3 PV Installer Certificate; or (iv) an 
6    Associate in Applied Science degree from an Illinois 
7    Community College Board approved community college program 
8    in renewable energy or a distributed generation 
9    technology.
10        For the purposes of this paragraph (1), "directly 
11    supervised" means that there is a qualified person who 
12    meets the qualifications under clause (A) of this 
13    paragraph (1) and who is available for supervision and 
14    consultation regarding the work performed by persons under 
15    clause (B) of this paragraph (1), including a final 
16    inspection of the installation work that has been directly 
17    supervised to ensure safety and conformity with applicable 
18    codes.
19        For the purposes of this paragraph (1), "install" 
20    means the major activities and actions required to 
21    connect, in accordance with applicable building and 
22    electrical codes, the conductors, connectors, and all 
23    associated fittings, devices, power outlets, or 
24    apparatuses mounted at the premises that are directly 
25    involved in delivering energy to the premises' electrical 
26    wiring from the photovoltaics, including, but not limited 
 
 
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1    to, to distributed photovoltaic generation. 
2        The renewable energy credits procured pursuant to the 
3    supplemental procurement plan shall be procured using up 
4    to $30,000,000 from the Illinois Power Agency Renewable 
5    Energy Resources Fund. The Agency shall not plan to use 
6    funds from the Illinois Power Agency Renewable Energy 
7    Resources Fund in excess of the monies on deposit in such 
8    fund or projected to be deposited into such fund. The 
9    supplemental procurement plan shall ensure adequate, 
10    reliable, affordable, efficient, and environmentally 
11    sustainable renewable energy resources (including credits) 
12    at the lowest total cost over time, taking into account 
13    any benefits of price stability.
14        To the extent available, 50% of the renewable energy 
15    credits procured from distributed renewable energy 
16    generation shall come from devices of less than 25 
17    kilowatts in nameplate capacity. Procurement of renewable 
18    energy credits from distributed renewable energy 
19    generation devices shall be done through multi-year 
20    contracts of no less than 5 years. The Agency shall create 
21    credit requirements for counterparties. In order to 
22    minimize the administrative burden on contracting 
23    entities, the Agency shall solicit the use of third 
24    parties to aggregate distributed renewable energy. These 
25    third parties shall enter into and administer contracts 
26    with individual distributed renewable energy generation 
 
 
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1    device owners. An individual distributed renewable energy 
2    generation device owner shall have the ability to measure 
3    the output of his or her distributed renewable energy 
4    generation device.
5        In developing the supplemental procurement plan, the 
6    Agency shall hold at least one workshop open to the public 
7    within 90 days after June 30, 2014 (the effective date of 
8    Public Act 98-672) and shall consider any comments made by 
9    stakeholders or the public. Upon development of the 
10    supplemental procurement plan within this 90-day period, 
11    copies of the supplemental procurement plan shall be 
12    posted and made publicly available on the Agency's and 
13    Commission's websites. All interested parties shall have 
14    14 days following the date of posting to provide comment 
15    to the Agency on the supplemental procurement plan. All 
16    comments submitted to the Agency shall be specific, 
17    supported by data or other detailed analyses, and, if 
18    objecting to all or a portion of the supplemental 
19    procurement plan, accompanied by specific alternative 
20    wording or proposals. All comments shall be posted on the 
21    Agency's and Commission's websites. Within 14 days 
22    following the end of the 14-day review period, the Agency 
23    shall revise the supplemental procurement plan as 
24    necessary based on the comments received and file its 
25    revised supplemental procurement plan with the Commission 
26    for approval.
 
 
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1        (2) Within 5 days after the filing of the supplemental 
2    procurement plan at the Commission, any person objecting 
3    to the supplemental procurement plan shall file an 
4    objection with the Commission. Within 10 days after the 
5    filing, the Commission shall determine whether a hearing 
6    is necessary. The Commission shall enter its order 
7    confirming or modifying the supplemental procurement plan 
8    within 90 days after the filing of the supplemental 
9    procurement plan by the Agency.
10        (3) The Commission shall approve the supplemental 
11    procurement plan of renewable energy credits to be 
12    procured from new or existing photovoltaics, including, 
13    but not limited to, distributed photovoltaic generation, 
14    if the Commission determines that it will ensure adequate, 
15    reliable, affordable, efficient, and environmentally 
16    sustainable electric service in the form of renewable 
17    energy credits at the lowest total cost over time, taking 
18    into account any benefits of price stability.
19        (4) The supplemental procurement process under this 
20    subsection (i) shall include each of the following 
21    components:
22            (A) Procurement administrator. The Agency may 
23        retain a procurement administrator in the manner set 
24        forth in item (2) of subsection (a) of Section 1-75 of 
25        this Act to conduct the supplemental procurement or 
26        may elect to use the same procurement administrator 
 
 
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1        administering the Agency's annual procurement under 
2        Section 1-75.
3            (B) Procurement monitor. The procurement monitor 
4        retained by the Commission pursuant to Section 
5        16-111.5 of the Public Utilities Act shall:
6                (i) monitor interactions among the procurement 
7            administrator and bidders and suppliers;
8                (ii) monitor and report to the Commission on 
9            the progress of the supplemental procurement 
10            process;
11                (iii) provide an independent confidential 
12            report to the Commission regarding the results of 
13            the procurement events;
14                (iv) assess compliance with the procurement 
15            plan approved by the Commission for the 
16            supplemental procurement process;
17                (v) preserve the confidentiality of supplier 
18            and bidding information in a manner consistent 
19            with all applicable laws, rules, regulations, and 
20            tariffs;
21                (vi) provide expert advice to the Commission 
22            and consult with the procurement administrator 
23            regarding issues related to procurement process 
24            design, rules, protocols, and policy-related 
25            matters;
26                (vii) consult with the procurement 
 
 
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1            administrator regarding the development and use of 
2            benchmark criteria, standard form contracts, 
3            credit policies, and bid documents; and
4                (viii) perform, with respect to the 
5            supplemental procurement process, any other 
6            procurement monitor duties specifically delineated 
7            within subsection (i) of this Section. 
8            (C) Solicitation, prequalification, and 
9        registration of bidders. The procurement administrator 
10        shall disseminate information to potential bidders to 
11        promote a procurement event, notify potential bidders 
12        that the procurement administrator may enter into a 
13        post-bid price negotiation with bidders that meet the 
14        applicable benchmarks, provide supply requirements, 
15        and otherwise explain the competitive procurement 
16        process. In addition to such other publication as the 
17        procurement administrator determines is appropriate, 
18        this information shall be posted on the Agency's and 
19        the Commission's websites. The procurement 
20        administrator shall also administer the 
21        prequalification process, including evaluation of 
22        credit worthiness, compliance with procurement rules, 
23        and agreement to the standard form contract developed 
24        pursuant to item (D) of this paragraph (4). The 
25        procurement administrator shall then identify and 
26        register bidders to participate in the procurement 
 
 
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1        event.
2            (D) Standard contract forms and credit terms and 
3        instruments. The procurement administrator, in 
4        consultation with the Agency, the Commission, and 
5        other interested parties and subject to Commission 
6        oversight, shall develop and provide standard contract 
7        forms for the supplier contracts that meet generally 
8        accepted industry practices as well as include any 
9        applicable State of Illinois terms and conditions that 
10        are required for contracts entered into by an agency 
11        of the State of Illinois. Standard credit terms and 
12        instruments that meet generally accepted industry 
13        practices shall be similarly developed. Contracts for 
14        new photovoltaics shall include a provision attesting 
15        that the supplier will use a qualified person for the 
16        installation of the device pursuant to paragraph (1) 
17        of subsection (i) of this Section. The procurement 
18        administrator shall make available to the Commission 
19        all written comments it receives on the contract 
20        forms, credit terms, or instruments. If the 
21        procurement administrator cannot reach agreement with 
22        the parties as to the contract terms and conditions, 
23        the procurement administrator must notify the 
24        Commission of any disputed terms and the Commission 
25        shall resolve the dispute. The terms of the contracts 
26        shall not be subject to negotiation by winning 
 
 
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1        bidders, and the bidders must agree to the terms of the 
2        contract in advance so that winning bids are selected 
3        solely on the basis of price.
4            (E) Requests for proposals; competitive 
5        procurement process. The procurement administrator 
6        shall design and issue requests for proposals to 
7        supply renewable energy credits in accordance with the 
8        supplemental procurement plan, as approved by the 
9        Commission. The requests for proposals shall set forth 
10        a procedure for sealed, binding commitment bidding 
11        with pay-as-bid settlement, and provision for 
12        selection of bids on the basis of price, provided, 
13        however, that no bid shall be accepted if it exceeds 
14        the benchmark developed pursuant to item (F) of this 
15        paragraph (4).
16            (F) Benchmarks. Benchmarks for each product to be 
17        procured shall be developed by the procurement 
18        administrator in consultation with Commission staff, 
19        the Agency, and the procurement monitor for use in 
20        this supplemental procurement.
21            (G) A plan for implementing contingencies in the 
22        event of supplier default, Commission rejection of 
23        results, or any other cause.
24        (5) Within 2 business days after opening the sealed 
25    bids, the procurement administrator shall submit a 
26    confidential report to the Commission. The report shall 
 
 
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1    contain the results of the bidding for each of the 
2    products along with the procurement administrator's 
3    recommendation for the acceptance and rejection of bids 
4    based on the price benchmark criteria and other factors 
5    observed in the process. The procurement monitor also 
6    shall submit a confidential report to the Commission 
7    within 2 business days after opening the sealed bids. The 
8    report shall contain the procurement monitor's assessment 
9    of bidder behavior in the process as well as an assessment 
10    of the procurement administrator's compliance with the 
11    procurement process and rules. The Commission shall review 
12    the confidential reports submitted by the procurement 
13    administrator and procurement monitor and shall accept or 
14    reject the recommendations of the procurement 
15    administrator within 2 business days after receipt of the 
16    reports.
17        (6) Within 3 business days after the Commission 
18    decision approving the results of a procurement event, the 
19    Agency shall enter into binding contractual arrangements 
20    with the winning suppliers using the standard form 
21    contracts.
22        (7) The names of the successful bidders and the 
23    average of the winning bid prices for each contract type 
24    and for each contract term shall be made available to the 
25    public within 2 days after the supplemental procurement 
26    event. The Commission, the procurement monitor, the 
 
 
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1    procurement administrator, the Agency, and all 
2    participants in the procurement process shall maintain the 
3    confidentiality of all other supplier and bidding 
4    information in a manner consistent with all applicable 
5    laws, rules, regulations, and tariffs. Confidential 
6    information, including the confidential reports submitted 
7    by the procurement administrator and procurement monitor 
8    pursuant to this Section, shall not be made publicly 
9    available and shall not be discoverable by any party in 
10    any proceeding, absent a compelling demonstration of need, 
11    nor shall those reports be admissible in any proceeding 
12    other than one for law enforcement purposes.
13        (8) The supplemental procurement provided in this 
14    subsection (i) shall not be subject to the requirements 
15    and limitations of subsections (c) and (d) of this 
16    Section.
17        (9) Expenses incurred in connection with the 
18    procurement process held pursuant to this Section, 
19    including, but not limited to, the cost of developing the 
20    supplemental procurement plan, the procurement 
21    administrator, procurement monitor, and the cost of the 
22    retirement of renewable energy credits purchased pursuant 
23    to the supplemental procurement shall be paid for from the 
24    Illinois Power Agency Renewable Energy Resources Fund. The 
25    Agency shall enter into an interagency agreement with the 
26    Commission to reimburse the Commission for its costs 
 
 
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1    associated with the procurement monitor for the 
2    supplemental procurement process. 
3(Source: P.A. 102-662, eff. 9-15-21; 103-188, eff. 6-30-23; 
4103-605, eff. 7-1-24; 103-1066, eff. 2-20-25; revised 
56-23-25.)
 
6    (20 ILCS 3855/1-75)
7    Sec. 1-75. Planning and Procurement Bureau. The Planning 
8and Procurement Bureau has the following duties and 
9responsibilities:
10    (a) The Planning and Procurement Bureau shall each year, 
11beginning in 2008, develop procurement plans and conduct 
12competitive procurement processes in accordance with the 
13requirements of Section 16-111.5 of the Public Utilities Act 
14for the eligible retail customers of electric utilities that 
15on December 31, 2005 provided electric service to at least 
16100,000 customers in Illinois. Beginning with the delivery 
17year commencing on June 1, 2017, the Planning and Procurement 
18Bureau shall develop plans and processes for the procurement 
19of zero emission credits from zero emission facilities in 
20accordance with the requirements of subsection (d-5) of this 
21Section. Beginning on the effective date of this amendatory 
22Act of the 102nd General Assembly, the Planning and 
23Procurement Bureau shall develop plans and processes for the 
24procurement of carbon mitigation credits from carbon-free 
25energy resources in accordance with the requirements of 
 
 
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1subsection (d-10) of this Section. The Planning and 
2Procurement Bureau shall also develop procurement plans and 
3conduct competitive procurement processes in accordance with 
4the requirements of Section 16-111.5 of the Public Utilities 
5Act for the eligible retail customers of small 
6multi-jurisdictional electric utilities that (i) on December 
731, 2005 served less than 100,000 customers in Illinois and 
8(ii) request a procurement plan for their Illinois 
9jurisdictional load. This Section shall not apply to a small 
10multi-jurisdictional utility until such time as a small 
11multi-jurisdictional utility requests the Agency to prepare a 
12procurement plan for their Illinois jurisdictional load. For 
13the purposes of this Section, the term "eligible retail 
14customers" has the same definition as found in Section 
1516-111.5(a) of the Public Utilities Act.
16    Beginning with the plan or plans to be implemented in the 
172017 delivery year, the Agency shall no longer include the 
18procurement of renewable energy resources in the annual 
19procurement plans required by this subsection (a), except as 
20provided in subsection (q) of Section 16-111.5 of the Public 
21Utilities Act, and shall instead develop a long-term renewable 
22resources procurement plan in accordance with subsection (c) 
23of this Section and Section 16-111.5 of the Public Utilities 
24Act. 
25    In accordance with subsection (c-5) of this Section, the 
26Planning and Procurement Bureau shall oversee the procurement 
 
 
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1by electric utilities that served more than 300,000 retail 
2customers in this State as of January 1, 2019 of renewable 
3energy credits from new utility-scale solar projects to be 
4installed, along with energy storage facilities, at or 
5adjacent to the sites of electric generating facilities that, 
6as of January 1, 2016, burned coal as their primary fuel 
7source. 
8        (1) The Agency shall each year, beginning in 2008, as 
9    needed, issue a request for qualifications for experts or 
10    expert consulting firms to develop the procurement plans 
11    in accordance with Section 16-111.5 of the Public 
12    Utilities Act. In order to qualify an expert or expert 
13    consulting firm must have:
14            (A) direct previous experience assembling 
15        large-scale power supply plans or portfolios for 
16        end-use customers;
17            (B) an advanced degree in economics, mathematics, 
18        engineering, risk management, or a related area of 
19        study;
20            (C) 10 years of experience in the electricity 
21        sector, including managing supply risk;
22            (D) expertise in wholesale electricity market 
23        rules, including those established by the Federal 
24        Energy Regulatory Commission and regional transmission 
25        organizations;
26            (E) expertise in credit protocols and familiarity 
 
 
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1        with contract protocols;
2            (F) adequate resources to perform and fulfill the 
3        required functions and responsibilities; and
4            (G) the absence of a conflict of interest and 
5        inappropriate bias for or against potential bidders or 
6        the affected electric utilities.
7        (2) The Agency shall each year, as needed, issue a 
8    request for qualifications for a procurement administrator 
9    to conduct the competitive procurement processes in 
10    accordance with Section 16-111.5 of the Public Utilities 
11    Act. In order to qualify an expert or expert consulting 
12    firm must have:
13            (A) direct previous experience administering a 
14        large-scale competitive procurement process;
15            (B) an advanced degree in economics, mathematics, 
16        engineering, or a related area of study;
17            (C) 10 years of experience in the electricity 
18        sector, including risk management experience;
19            (D) expertise in wholesale electricity market 
20        rules, including those established by the Federal 
21        Energy Regulatory Commission and regional transmission 
22        organizations; 
23            (E) expertise in credit and contract protocols;
24            (F) adequate resources to perform and fulfill the 
25        required functions and responsibilities; and
26            (G) the absence of a conflict of interest and 
 
 
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1        inappropriate bias for or against potential bidders or 
2        the affected electric utilities.
3        (3) The Agency shall provide affected utilities and 
4    other interested parties with the lists of qualified 
5    experts or expert consulting firms identified through the 
6    request for qualifications processes that are under 
7    consideration to develop the procurement plans and to 
8    serve as the procurement administrator. The Agency shall 
9    also provide each qualified expert's or expert consulting 
10    firm's response to the request for qualifications. All 
11    information provided under this subparagraph shall also be 
12    provided to the Commission. The Agency may provide by rule 
13    for fees associated with supplying the information to 
14    utilities and other interested parties. These parties 
15    shall, within 5 business days, notify the Agency in 
16    writing if they object to any experts or expert consulting 
17    firms on the lists. Objections shall be based on:
18            (A) failure to satisfy qualification criteria;
19            (B) identification of a conflict of interest; or
20            (C) evidence of inappropriate bias for or against 
21        potential bidders or the affected utilities.
22        The Agency shall remove experts or expert consulting 
23    firms from the lists within 10 days if there is a 
24    reasonable basis for an objection and provide the updated 
25    lists to the affected utilities and other interested 
26    parties. If the Agency fails to remove an expert or expert 
 
 
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1    consulting firm from a list, an objecting party may seek 
2    review by the Commission within 5 days thereafter by 
3    filing a petition, and the Commission shall render a 
4    ruling on the petition within 10 days. There is no right of 
5    appeal of the Commission's ruling.
6        (4) The Agency shall issue requests for proposals to 
7    the qualified experts or expert consulting firms to 
8    develop a procurement plan for the affected utilities and 
9    to serve as procurement administrator.
10        (5) The Agency shall select an expert or expert 
11    consulting firm to develop procurement plans based on the 
12    proposals submitted and shall award contracts of up to 5 
13    years to those selected.
14        (6) The Agency shall select an expert or expert 
15    consulting firm, with approval of the Commission, to serve 
16    as procurement administrator based on the proposals 
17    submitted. If the Commission rejects, within 5 days, the 
18    Agency's selection, the Agency shall submit another 
19    recommendation within 3 days based on the proposals 
20    submitted. The Agency shall award a 5-year contract to the 
21    expert or expert consulting firm so selected with 
22    Commission approval.
23    (b) The experts or expert consulting firms retained by the 
24Agency shall, as appropriate, prepare procurement plans, and 
25conduct a competitive procurement process as prescribed in 
26Section 16-111.5 of the Public Utilities Act, to ensure 
 
 
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1adequate, reliable, affordable, efficient, and environmentally 
2sustainable electric service at the lowest total cost over 
3time, taking into account any benefits of price stability, for 
4eligible retail customers of electric utilities that on 
5December 31, 2005 provided electric service to at least 
6100,000 customers in the State of Illinois, and for eligible 
7Illinois retail customers of small multi-jurisdictional 
8electric utilities that (i) on December 31, 2005 served less 
9than 100,000 customers in Illinois and (ii) request a 
10procurement plan for their Illinois jurisdictional load.
11    (c) Renewable portfolio standard.
12        (1)(A) The Agency shall develop a long-term renewable 
13    resources procurement plan that shall include procurement 
14    programs and competitive procurement events necessary to 
15    meet the goals set forth in this subsection (c). The 
16    initial long-term renewable resources procurement plan 
17    shall be released for comment no later than 160 days after 
18    June 1, 2017 (the effective date of Public Act 99-906). 
19    The Agency shall review, and may revise on an expedited 
20    basis, the long-term renewable resources procurement plan 
21    at least every 2 years, which shall be conducted in 
22    conjunction with the procurement plan under Section 
23    16-111.5 of the Public Utilities Act to the extent 
24    practicable to minimize administrative expense. No later 
25    than 120 days after the effective date of this amendatory 
26    Act of the 103rd General Assembly, the Agency shall 
 
 
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1    release for comment a revision to the long-term renewable 
2    resources procurement plan, updating elements of the most 
3    recently approved plan as needed to comply with this 
4    amendatory Act of the 103rd General Assembly, and any 
5    long-term renewable resources procurement plan update 
6    published by the Agency but not yet approved by the 
7    Illinois Commerce Commission shall be withdrawn. The 
8    long-term renewable resources procurement plans shall be 
9    subject to review and approval by the Commission under 
10    Section 16-111.5 of the Public Utilities Act.
11        (B) Subject to subparagraph (F) of this paragraph (1), 
12    the long-term renewable resources procurement plan shall 
13    attempt to meet the goals for procurement of renewable 
14    energy credits at levels of at least the following overall 
15    percentages: 13% by the 2017 delivery year; increasing by 
16    at least 1.5% each delivery year thereafter to at least 
17    25% by the 2025 delivery year; increasing by at least 3% 
18    each delivery year thereafter to at least 40% by the 2030 
19    delivery year, and continuing at no less than 40% for each 
20    delivery year thereafter. The Agency shall attempt to 
21    procure 50% by delivery year 2040. The Agency shall 
22    determine the annual increase between delivery year 2030 
23    and delivery year 2040, if any, taking into account energy 
24    demand, other energy resources, and other public policy 
25    goals. In the event of a conflict between these goals and 
26    the new wind, new photovoltaic, new geothermal heating and 
 
 
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1    cooling, and hydropower procurement requirements described 
2    in items (i) through (iii) of subparagraph (C) of this 
3    paragraph (1), the long-term plan shall prioritize 
4    compliance with the new wind, new photovoltaic, new 
5    geothermal heating and cooling, and hydropower procurement 
6    requirements described in items (i) through (iii) of 
7    subparagraph (C) of this paragraph (1) over the annual 
8    percentage targets described in this subparagraph (B). The 
9    Agency shall not comply with the annual percentage targets 
10    described in this subparagraph (B) by procuring renewable 
11    energy credits that are unlikely to lead to the 
12    development of new renewable resources or new, modernized, 
13    or retooled hydropower facilities. 
14        For the delivery year beginning June 1, 2017, the 
15    procurement plan shall attempt to include, subject to the 
16    prioritization outlined in this subparagraph (B), 
17    cost-effective renewable energy resources equal to at 
18    least 13% of each utility's load for eligible retail 
19    customers and 13% of the applicable portion of each 
20    utility's load for retail customers who are not eligible 
21    retail customers, which applicable portion shall equal 50% 
22    of the utility's load for retail customers who are not 
23    eligible retail customers on February 28, 2017. 
24        For the delivery year beginning June 1, 2018, the 
25    procurement plan shall attempt to include, subject to the 
26    prioritization outlined in this subparagraph (B), 
 
 
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1    cost-effective renewable energy resources equal to at 
2    least 14.5% of each utility's load for eligible retail 
3    customers and 14.5% of the applicable portion of each 
4    utility's load for retail customers who are not eligible 
5    retail customers, which applicable portion shall equal 75% 
6    of the utility's load for retail customers who are not 
7    eligible retail customers on February 28, 2017. 
8        For the delivery year beginning June 1, 2019, and for 
9    each year thereafter, the procurement plans shall attempt 
10    to include, subject to the prioritization outlined in this 
11    subparagraph (B), cost-effective renewable energy 
12    resources equal to a minimum percentage of each utility's 
13    load for all retail customers as follows: 16% by June 1, 
14    2019; increasing by 1.5% each year thereafter to 25% by 
15    June 1, 2025; and 25% by June 1, 2026; increasing by at 
16    least 3% each delivery year thereafter to at least 40% by 
17    the 2030 delivery year, and continuing at no less than 40% 
18    for each delivery year thereafter. The Agency shall 
19    attempt to procure 50% by delivery year 2040. The Agency 
20    shall determine the annual increase between delivery year 
21    2030 and delivery year 2040, if any, taking into account 
22    energy demand, other energy resources, and other public 
23    policy goals. 
24        For each delivery year, the Agency shall first 
25    recognize each utility's obligations for that delivery 
26    year under existing contracts. Any renewable energy 
 
 
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1    credits under existing contracts, including renewable 
2    energy credits as part of renewable energy resources, 
3    shall be used to meet the goals set forth in this 
4    subsection (c) for the delivery year. 
5        (C) The long-term renewable resources procurement plan 
6    described in subparagraph (A) of this paragraph (1) shall 
7    include the procurement of renewable energy credits from 
8    new projects pursuant to the following terms: 
9            (i) At least 10,000,000 renewable energy credits 
10        delivered annually by the end of the 2021 delivery 
11        year, and increasing ratably to reach 45,000,000 
12        renewable energy credits delivered annually from new 
13        wind and solar projects, from repowered wind projects, 
14        or from retooled hydropower facilities by the end of 
15        delivery year 2030 such that the goals in subparagraph 
16        (B) of this paragraph (1) are met entirely by 
17        procurements of renewable energy credits from new wind 
18        and photovoltaic projects. Of that amount, to the 
19        extent possible, the Agency shall endeavor to procure 
20        45% from new and repowered wind and hydropower 
21        projects and shall procure at least 55% from 
22        photovoltaic projects. Of the amount to be procured 
23        from photovoltaic projects, the Agency shall procure: 
24        at least 50% from solar photovoltaic projects using 
25        the program outlined in subparagraph (K) of this 
26        paragraph (1) from distributed renewable energy 
 
 
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1        generation devices or community renewable generation 
2        projects; at least 47% from utility-scale solar 
3        projects; at least 3% from brownfield site 
4        photovoltaic projects that are not community renewable 
5        generation projects. The Agency may propose 
6        adjustments to these percentages, including 
7        establishing percentage-based goals for the 
8        procurement of renewable energy credits from 
9        modernized or retooled hydropower facilities and 
10        repowered wind projects, through its long-term 
11        renewable resources plan described in subparagraph (A) 
12        of this paragraph (1) as necessary based on developer 
13        interest, market conditions, budget considerations, 
14        resource adequacy needs, or other factors. 
15        Notwithstanding the percentage-based goals as 
16        described in this Section, the Agency shall develop a 
17        Geothermal Homes and Businesses Program for the 
18        procurement of renewable energy credits from 
19        geothermal heating and cooling systems.    
20            In developing the long-term renewable resources 
21        procurement plan, the Agency shall consider other 
22        approaches, in addition to competitive procurements, 
23        that can be used to procure renewable energy credits 
24        from brownfield site photovoltaic projects and thereby 
25        help return blighted or contaminated land to 
26        productive use while enhancing public health and the 
 
 
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1        well-being of Illinois residents, including those in 
2        environmental justice communities, as defined using 
3        existing methodologies and findings used by the Agency 
4        and its Administrator in its Illinois Solar for All 
5        Program. The Agency shall also consider other 
6        approaches, in addition to competitive procurements, 
7        to procure renewable energy credits from new and 
8        existing hydropower facilities to support the 
9        development and maintenance of these facilities. The 
10        Agency shall explore options to convert existing dams 
11        but shall not consider approaches to develop new dams 
12        where they do not already exist. To encourage the 
13        continued operation of utility-scale wind projects, 
14        the Agency shall consider and may propose other 
15        approaches in addition to competitive procurements to 
16        procure renewable energy credits from repowered wind 
17        projects. 
18            (ii) In any given delivery year, if forecasted 
19        expenses are less than the maximum budget available 
20        under subparagraph (E) of this paragraph (1), the 
21        Agency shall continue to procure new renewable energy 
22        credits until that budget is exhausted in the manner 
23        outlined in item (i) of this subparagraph (C).
24            (iii) For purposes of this Section:
25            "New wind projects" means wind renewable energy 
26        facilities that are energized after June 1, 2017 for 
 
 
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1        the delivery year commencing June 1, 2017.
2            "New photovoltaic projects" means photovoltaic 
3        renewable energy facilities that are energized after 
4        June 1, 2017. Photovoltaic projects developed under 
5        Section 1-56 of this Act shall not apply towards the 
6        new photovoltaic project requirements in this 
7        subparagraph (C). 
8            "Repowered wind projects" means utility-scale wind 
9        projects featuring the removal, replacement, or 
10        expansion of turbines at an existing project site, as 
11        defined in the long-term renewable resources 
12        procurement plan, after the effective date of this 
13        amendatory Act of the 103rd General Assembly. 
14        Renewable energy credit contract awards used to 
15        support repowered wind projects shall only cover the 
16        incremental increase in facility electricity 
17        production resultant from repowering. 
18            "Geothermal heating and cooling system" means a 
19        system located in this State that meets all of the 
20        following requirements:
21                (I) the system exchanges thermal energy from 
22            groundwater or a shallow ground source to generate 
23            thermal energy through an electric geothermal heat 
24            pump or a system of electric geothermal heat pumps 
25            interconnected with any geothermal extraction 
26            facility that is (1) a closed loop or a series of 
 
 
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1            closed loop systems in which fluid is permanently 
2            confined within a pipe or tubing and does not come 
3            in contact with the outside environment or (2) an 
4            open loop system in which ground or surface water 
5            is circulated in an environmentally safe manner 
6            directly into the facility and returned to the 
7            same aquifer or surface water source;
8                (II) the system meets or exceeds federal 
9            Energy Star product specification standards, or 
10            any successor standards, to the extent applicable;
11                (III) the system replaces or displaces less 
12            efficient space or water heating systems, 
13            regardless of fuel type;
14                (IV) the system replaces or displaces less 
15            efficient space cooling systems, when applicable;
16                (V) the system does not feed electricity back 
17            to the grid, as defined at the level of the 
18            geothermal heat pump; and
19                (VI) the system became operational on or after 
20            the effective date of this amendatory Act of the 
21            104th General Assembly.    
22            For purposes of calculating whether the Agency has 
23        procured enough new wind and solar renewable energy 
24        credits required by this subparagraph (C), renewable 
25        energy facilities that have a multi-year renewable 
26        energy credit delivery contract with the utility 
 
 
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1        through at least delivery year 2030 shall be 
2        considered new, however no renewable energy credits 
3        from contracts entered into before June 1, 2021 shall 
4        be used to calculate whether the Agency has procured 
5        the correct proportion of new wind and new solar 
6        contracts described in this subparagraph (C) for 
7        delivery year 2021 and thereafter.
8            (iv) The Agency may implement additional measures, 
9        including eligibility requirements, to ensure that new 
10        wind projects and new photovoltaic projects supported 
11        through renewable energy credit contract awards are a 
12        result of a contract award and are otherwise developed 
13        pursuant to the financial certainty provided through a 
14        contract award.
15        (D) Renewable energy credits shall be cost effective. 
16    For purposes of this subsection (c), "cost effective" 
17    means that the costs of procuring renewable energy 
18    resources do not cause the limit stated in subparagraph 
19    (E) of this paragraph (1) to be exceeded and, for 
20    renewable energy credits procured through a competitive 
21    procurement event, do not exceed benchmarks based on 
22    market prices for like products in the region. For 
23    purposes of this subsection (c), "like products" means 
24    contracts for renewable energy credits from the same or 
25    substantially similar technology, same or substantially 
26    similar vintage (new or existing), the same or 
 
 
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1    substantially similar quantity, and the same or 
2    substantially similar contract length and structure. 
3    Benchmarks shall reflect development, financing, or 
4    related costs resulting from requirements imposed through 
5    other provisions of State law, including, but not limited 
6    to, requirements in subparagraphs (P) and (Q) of this 
7    paragraph (1) and the Renewable Energy Facilities 
8    Agricultural Impact Mitigation Act. Confidential 
9    benchmarks shall be developed by the procurement 
10    administrator, in consultation with the Commission staff, 
11    Agency staff, and the procurement monitor and shall be 
12    subject to Commission review and approval. If price 
13    benchmarks for like products in the region are not 
14    available, the procurement administrator shall establish 
15    price benchmarks based on publicly available data on 
16    regional technology costs and expected current and future 
17    regional energy prices. The benchmarks in this Section 
18    shall not be used to curtail or otherwise reduce 
19    contractual obligations entered into by or through the 
20    Agency prior to June 1, 2017 (the effective date of Public 
21    Act 99-906). 
22        (E) For purposes of this subsection (c), the required 
23    procurement of cost-effective renewable energy resources 
24    for a particular year commencing prior to June 1, 2017 
25    shall be measured as a percentage of the actual amount of 
26    electricity (megawatt-hours) supplied by the electric 
 
 
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1    utility to eligible retail customers in the delivery year 
2    ending immediately prior to the procurement, and, for 
3    delivery years commencing on and after June 1, 2017, the 
4    required procurement of cost-effective renewable energy 
5    resources for a particular year shall be measured as a 
6    percentage of the actual amount of electricity 
7    (megawatt-hours) delivered by the electric utility in the 
8    delivery year ending immediately prior to the procurement, 
9    to all retail customers in its service territory. For 
10    purposes of this subsection (c), the amount paid per 
11    kilowatthour means the total amount paid for electric 
12    service expressed on a per kilowatthour basis. For 
13    purposes of this subsection (c), the total amount paid for 
14    electric service includes without limitation amounts paid 
15    for supply, transmission, capacity, distribution, 
16    surcharges, and add-on taxes. 
17        Notwithstanding the requirements of this subsection 
18    (c), and except as provided in subparagraph (E-5) of 
19    paragraph (1) of this subsection (c) or except as 
20    otherwise authorized by the Commission in its approval of 
21    the integrated resource plan under Section 16-202 of the 
22    Public Utilities Act, the total of renewable energy 
23    resources procured under the procurement plan for any 
24    single year shall be subject to the limitations of this 
25    subparagraph (E). Such procurement shall be reduced for 
26    all retail customers based on the amount necessary to 
 
 
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1    limit the annual estimated average net increase due to the 
2    costs of these resources included in the amounts paid by 
3    eligible retail customers in connection with electric 
4    service to no more than 4.25% of the amount paid per 
5    kilowatthour by those customers during the year ending May 
6    31, 2009, adjusted annually for inflation starting with 
7    the first adjustment in the delivery year commencing June 
8    1, 2026. For the purposes of this Section, the inflation 
9    adjustment shall not be accrued or applied retroactively 
10    prior to the effective date of this amendatory Act of the 
11    104th General Assembly and shall apply prospectively 
12    starting in 2025. The limitation shall be increased by an 
13    additional 1.65 percentage points of the amount paid per 
14    kilowatthour by eligible retail customers during the year 
15    ending May 31, 2009 starting with the delivery year 
16    commencing June 1, 2027. To arrive at a maximum dollar 
17    amount of renewable energy resources to be procured for 
18    the particular delivery year, the resulting per 
19    kilowatthour amount shall be applied to the actual amount 
20    of kilowatthours of electricity delivered, or applicable 
21    portion of such amount as specified in paragraph (1) of 
22    this subsection (c), as applicable, by the electric 
23    utility in the delivery year immediately prior to the 
24    procurement to all retail customers in its service 
25    territory. The calculations required by this subparagraph 
26    (E) shall be made only once for each delivery year at the 
 
 
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1    time that the renewable energy resources are procured. 
2    Once the determination as to the amount of renewable 
3    energy resources to procure is made based on the 
4    calculations set forth in this subparagraph (E) and the 
5    contracts procuring those amounts are executed between the 
6    seller and applicable electric utility, no subsequent rate 
7    impact determinations shall be made and no adjustments to 
8    those contract amounts shall be allowed. As provided in 
9    subparagraph (E-5) of paragraph (1) of this subsection 
10    (c), the seller shall be entitled to full, prompt, and 
11    uninterrupted payment under the applicable contract 
12    notwithstanding the application of this subparagraph (E), 
13    and all costs incurred under such contracts shall be fully 
14    recoverable by the electric utility as provided in this 
15    Section. 
16        (E-5) If, for a particular delivery year, the 
17    limitation on the amount of renewable energy resources to 
18    be procured, as calculated pursuant to subparagraph (E) of 
19    paragraph (1) of this subsection (c), would result in an 
20    insufficient collection of funds to fully pay amounts due 
21    to a seller under existing contracts executed under this 
22    Section or executed under Section 1-56 of this Act, then 
23    the following provisions shall apply to ensure full and 
24    uninterrupted payment is made to such seller or sellers:
25            (i) If the electric utility has retained unspent 
26        funds in an interest-bearing account as prescribed in 
 
 
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1        subsection (k) of Section 16-108 of the Public 
2        Utilities Act, then the utility shall use those funds 
3        to remit full payment to the sellers to ensure prompt 
4        and uninterrupted payment of existing contractual 
5        obligation.
6            (ii) If the funds described in item (i) of this 
7        subparagraph (E-5) are insufficient to satisfy all 
8        existing contractual obligations, then the electric 
9        utility shall, nonetheless, remit full payment to the 
10        sellers to ensure prompt and uninterrupted payment of 
11        existing contractual obligations, provided that the 
12        full costs shall be recoverable by the utility in 
13        accordance with part (ee) of item (iv) of this 
14        subsection (E-5).
15            (iii) The Agency shall promptly notify the 
16        Commission that existing contractual obligations are 
17        reasonably expected to exceed the maximum collection 
18        authorized under subparagraph (E) of paragraph (1) of 
19        this subsection (c) for the applicable delivery year. 
20        The Agency shall also explain and confirm how the 
21        operation of items (i) and (ii) of this subparagraph 
22        (E-5) ensures that the electric utility will continue 
23        to make prompt and uninterrupted payment under 
24        existing contractual obligations. The Agency shall 
25        provide this information to the Commission through a 
26        notice filed in the Commission docket approving the 
 
 
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1        Agency's operative Long-Term Renewable Resources 
2        Procurement Plan that includes the applicable delivery 
3        year.
4            (iv) The Agency shall suspend or reduce new 
5        contract awards for the procurement of renewable 
6        energy credits until an Agency determination is made 
7        under subparagraph (E) that additional procurements 
8        would not cause the rate impact limitation of 
9        subparagraph (E) to be exceeded. At least once 
10        annually after the notice provided for in item (iii) 
11        of this subparagraph (E-5) is made, the Agency shall 
12        analyze existing contract obligations, projected 
13        prices for indexed renewable energy credit contracts 
14        executed under item (v) of subparagraph (G) of 
15        paragraph (1) of subsection (c) of Section 1-75 of 
16        this Act, and expected collections authorized under 
17        subparagraph (E) to determine whether and to what 
18        extent the limitations of subparagraph (E) would be 
19        exceeded by additional renewable energy credit 
20        procurement contract awards.
21                (aa) If the Agency determines that additional 
22            renewable energy credit procurement contract 
23            awards could be made without exceeding the 
24            limitations of subparagraph (E), then the 
25            procurements shall be authorized at a scale 
26            determined not to exceed the limitations of 
 
 
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1            subparagraph (E) in a manner consistent with the 
2            priorities of this Section.
3                (bb) If the Agency determines that additional 
4            renewable energy credit procurement contract 
5            awards cannot be made without exceeding the 
6            limitations of subparagraph (E), then the Agency 
7            shall suspend any new contract awards for the 
8            procurement of renewable energy credits until a 
9            new rate impact determination is made under 
10            subparagraph (E).
11                (cc) Agency determinations made under this 
12            item (iv) shall be detailed and comprehensive and, 
13            if not made through the Agency's Long-Term 
14            Renewable Resources Procurement Plan, shall be 
15            filed as a compliance filing in the most recent 
16            docketed proceeding approving the Agency's 
17            Long-Term Renewable Resources Procurement Plan.
18                (dd) With respect to the procurement of 
19            renewable energy credits authorized through 
20            programs administered under subsection (b) of 
21            Section 1-56 and subparagraphs (K) through (M) of 
22            paragraph (1) of subsection (k) of Section 1-75 of 
23            this Act, the award of contracts for the 
24            procurement of renewable energy credits shall be 
25            suspended or reduced only at the conclusion of the 
26            program year in which the notice provided for 
 
 
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1            under item (iii) of this subparagraph (E-5) is 
2            made. 
3                (ee) The contract shall provide that, so long 
4            as at least one of: (i) the cost recovery 
5            mechanisms referenced in subsection (k) of Section 
6            16-108 and subsection (l) of Section 16-111.5 of 
7            the Public Utilities Act remains in full force 
8            without limitation or (ii) the utility is 
9            otherwise authorized and or entitled to full, 
10            prompt, and uninterrupted recovery of its costs 
11            through any other mechanism, then such seller 
12            shall be entitled to full, prompt, and 
13            uninterrupted payment under the applicable 
14            contract notwithstanding the application of this 
15            subparagraph (E). 
16        (F) If the limitation on the amount of renewable 
17    energy resources procured in subparagraph (E) of this 
18    paragraph (1) prevents the Agency from meeting all of the 
19    goals in this subsection (c), the Agency's long-term plan 
20    shall prioritize compliance with the requirements of this 
21    subsection (c) regarding renewable energy credits in the 
22    following order:
23            (i) renewable energy credits under existing 
24        contractual obligations as of June 1, 2021;
25            (i-5) funding for the Illinois Solar for All 
26        Program, as described in subparagraph (O) of this 
 
 
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1        paragraph (1); 
2            (ii) renewable energy credits necessary to comply 
3        with the new wind and new photovoltaic procurement 
4        requirements described in items (i) through (iii) of 
5        subparagraph (C) of this paragraph (1); and
6            (iii) renewable energy credits necessary to meet 
7        the remaining requirements of this subsection (c).
8        (G) The following provisions shall apply to the 
9    Agency's procurement of renewable energy credits under 
10    this subsection (c):
11            (i) Notwithstanding whether a long-term renewable 
12        resources procurement plan has been approved, the 
13        Agency shall conduct an initial forward procurement 
14        for renewable energy credits from new utility-scale 
15        wind projects within 160 days after June 1, 2017 (the 
16        effective date of Public Act 99-906). For the purposes 
17        of this initial forward procurement, the Agency shall 
18        solicit 15-year contracts for delivery of 1,000,000 
19        renewable energy credits delivered annually from new 
20        utility-scale wind projects to begin delivery on June 
21        1, 2019, if available, but not later than June 1, 2021, 
22        unless the project has delays in the establishment of 
23        an operating interconnection with the applicable 
24        transmission or distribution system as a result of the 
25        actions or inactions of the transmission or 
26        distribution provider, or other causes for force 
 
 
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1        majeure as outlined in the procurement contract, in 
2        which case, not later than June 1, 2022. Payments to 
3        suppliers of renewable energy credits shall commence 
4        upon delivery. Renewable energy credits procured under 
5        this initial procurement shall be included in the 
6        Agency's long-term plan and shall apply to all 
7        renewable energy goals in this subsection (c).
8            (ii) Notwithstanding whether a long-term renewable 
9        resources procurement plan has been approved, the 
10        Agency shall conduct an initial forward procurement 
11        for renewable energy credits from new utility-scale 
12        solar projects and brownfield site photovoltaic 
13        projects within one year after June 1, 2017 (the 
14        effective date of Public Act 99-906). For the purposes 
15        of this initial forward procurement, the Agency shall 
16        solicit 15-year contracts for delivery of 1,000,000 
17        renewable energy credits delivered annually from new 
18        utility-scale solar projects and brownfield site 
19        photovoltaic projects to begin delivery on June 1, 
20        2019, if available, but not later than June 1, 2021, 
21        unless the project has delays in the establishment of 
22        an operating interconnection with the applicable 
23        transmission or distribution system as a result of the 
24        actions or inactions of the transmission or 
25        distribution provider, or other causes for force 
26        majeure as outlined in the procurement contract, in 
 
 
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1        which case, not later than June 1, 2022. The Agency may 
2        structure this initial procurement in one or more 
3        discrete procurement events. Payments to suppliers of 
4        renewable energy credits shall commence upon delivery. 
5        Renewable energy credits procured under this initial 
6        procurement shall be included in the Agency's 
7        long-term plan and shall apply to all renewable energy 
8        goals in this subsection (c).
9            (iii) Notwithstanding whether the Commission has 
10        approved the periodic long-term renewable resources 
11        procurement plan revision described in Section 
12        16-111.5 of the Public Utilities Act, the Agency shall 
13        conduct at least one subsequent forward procurement 
14        for renewable energy credits from new utility-scale 
15        wind projects, new utility-scale solar projects, and 
16        new brownfield site photovoltaic projects within 240 
17        days after the effective date of this amendatory Act 
18        of the 102nd General Assembly in quantities necessary 
19        to meet the requirements of subparagraph (C) of this 
20        paragraph (1) through the delivery year beginning June 
21        1, 2021.
22            (iv) Notwithstanding whether the Commission has 
23        approved the periodic long-term renewable resources 
24        procurement plan revision described in Section 
25        16-111.5 of the Public Utilities Act, the Agency shall 
26        open capacity for each category in the Adjustable 
 
 
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1        Block program within 90 days after the effective date 
2        of this amendatory Act of the 102nd General Assembly 
3        manner:
4                (1) The Agency shall open the first block of 
5            annual capacity for the category described in item 
6            (i) of subparagraph (K) of this paragraph (1). The 
7            first block of annual capacity for item (i) shall 
8            be for at least 75 megawatts of total nameplate 
9            capacity. The price of the renewable energy credit 
10            for this block of capacity shall be 4% less than 
11            the price of the last open block in this category. 
12            Projects on a waitlist shall be awarded contracts 
13            first in the order in which they appear on the 
14            waitlist. Notwithstanding anything to the 
15            contrary, for those renewable energy credits that 
16            qualify and are procured under this subitem (1) of 
17            this item (iv), the renewable energy credit 
18            delivery contract value shall be paid in full, 
19            based on the estimated generation during the first 
20            15 years of operation, by the contracting 
21            utilities at the time that the facility producing 
22            the renewable energy credits is interconnected at 
23            the distribution system level of the utility and 
24            verified as energized and in compliance by the 
25            Program Administrator. The electric utility shall 
26            receive and retire all renewable energy credits 
 
 
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1            generated by the project for the first 15 years of 
2            operation. Renewable energy credits generated by 
3            the project thereafter shall not be transferred 
4            under the renewable energy credit delivery 
5            contract with the counterparty electric utility.
6                (2) The Agency shall open the first block of 
7            annual capacity for the category described in item 
8            (ii) of subparagraph (K) of this paragraph (1). 
9            The first block of annual capacity for item (ii) 
10            shall be for at least 75 megawatts of total 
11            nameplate capacity.
12                    (A) The price of the renewable energy 
13                credit for any project on a waitlist for this 
14                category before the opening of this block 
15                shall be 4% less than the price of the last 
16                open block in this category. Projects on the 
17                waitlist shall be awarded contracts first in 
18                the order in which they appear on the 
19                waitlist. Any projects that are less than or 
20                equal to 25 kilowatts in size on the waitlist 
21                for this capacity shall be moved to the 
22                waitlist for paragraph (1) of this item (iv). 
23                Notwithstanding anything to the contrary, 
24                projects that were on the waitlist prior to 
25                opening of this block shall not be required to 
26                be in compliance with the requirements of 
 
 
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1                subparagraph (Q) of this paragraph (1) of this 
2                subsection (c). Notwithstanding anything to 
3                the contrary, for those renewable energy 
4                credits procured from projects that were on 
5                the waitlist for this category before the 
6                opening of this block 20% of the renewable 
7                energy credit delivery contract value, based 
8                on the estimated generation during the first 
9                15 years of operation, shall be paid by the 
10                contracting utilities at the time that the 
11                facility producing the renewable energy 
12                credits is interconnected at the distribution 
13                system level of the utility and verified as 
14                energized by the Program Administrator. The 
15                remaining portion shall be paid ratably over 
16                the subsequent 4-year period. The electric 
17                utility shall receive and retire all renewable 
18                energy credits generated by the project during 
19                the first 15 years of operation. Renewable 
20                energy credits generated by the project 
21                thereafter shall not be transferred under the 
22                renewable energy credit delivery contract with 
23                the counterparty electric utility.
24                    (B) The price of renewable energy credits 
25                for any project not on the waitlist for this 
26                category before the opening of the block shall 
 
 
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1                be determined and published by the Agency. 
2                Projects not on a waitlist as of the opening 
3                of this block shall be subject to the 
4                requirements of subparagraph (Q) of this 
5                paragraph (1), as applicable. Projects not on 
6                a waitlist as of the opening of this block 
7                shall be subject to the contract provisions 
8                outlined in item (iii) of subparagraph (L) of 
9                this paragraph (1). The Agency shall strive to 
10                publish updated prices and an updated 
11                renewable energy credit delivery contract as 
12                quickly as possible. 
13                (3) For opening the first 2 blocks of annual 
14            capacity for projects participating in item (iii) 
15            of subparagraph (K) of paragraph (1) of subsection 
16            (c), projects shall be selected exclusively from 
17            those projects on the ordinal waitlists of 
18            community renewable generation projects 
19            established by the Agency based on the status of 
20            those ordinal waitlists as of December 31, 2020, 
21            and only those projects previously determined to 
22            be eligible for the Agency's April 2019 community 
23            solar project selection process.
24                The first 2 blocks of annual capacity for item 
25            (iii) shall be for 250 megawatts of total 
26            nameplate capacity, with both blocks opening 
 
 
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1            simultaneously under the schedule outlined in the 
2            paragraphs below. Projects shall be selected as 
3            follows:
4                    (A) The geographic balance of selected 
5                projects shall follow the Group classification 
6                found in the Agency's Revised Long-Term 
7                Renewable Resources Procurement Plan, with 70% 
8                of capacity allocated to projects on the Group 
9                B waitlist and 30% of capacity allocated to 
10                projects on the Group A waitlist.
11                    (B) Contract awards for waitlisted 
12                projects shall be allocated proportionate to 
13                the total nameplate capacity amount across 
14                both ordinal waitlists associated with that 
15                applicant firm or its affiliates, subject to 
16                the following conditions.
17                        (i) Each applicant firm having a 
18                    waitlisted project eligible for selection 
19                    shall receive no less than 500 kilowatts 
20                    in awarded capacity across all groups, and 
21                    no approved vendor may receive more than 
22                    20% of each Group's waitlist allocation.
23                        (ii) Each applicant firm, upon 
24                    receiving an award of program capacity 
25                    proportionate to its waitlisted capacity, 
26                    may then determine which waitlisted 
 
 
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1                    projects it chooses to be selected for a 
2                    contract award up to that capacity amount.
3                        (iii) Assuming all other program 
4                    requirements are met, applicant firms may 
5                    adjust the nameplate capacity of applicant 
6                    projects without losing waitlist 
7                    eligibility, so long as no project is 
8                    greater than 2,000 kilowatts in size.
9                        (iv) Assuming all other program 
10                    requirements are met, applicant firms may 
11                    adjust the expected production associated 
12                    with applicant projects, subject to 
13                    verification by the Program Administrator.
14                    (C) After a review of affiliate 
15                information and the current ordinal waitlists, 
16                the Agency shall announce the nameplate 
17                capacity award amounts associated with 
18                applicant firms no later than 90 days after 
19                the effective date of this amendatory Act of 
20                the 102nd General Assembly.
21                    (D) Applicant firms shall submit their 
22                portfolio of projects used to satisfy those 
23                contract awards no less than 90 days after the 
24                Agency's announcement. The total nameplate 
25                capacity of all projects used to satisfy that 
26                portfolio shall be no greater than the 
 
 
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1                Agency's nameplate capacity award amount 
2                associated with that applicant firm. An 
3                applicant firm may decline, in whole or in 
4                part, its nameplate capacity award without 
5                penalty, with such unmet capacity rolled over 
6                to the next block opening for project 
7                selection under item (iii) of subparagraph (K) 
8                of this subsection (c). Any projects not 
9                included in an applicant firm's portfolio may 
10                reapply without prejudice upon the next block 
11                reopening for project selection under item 
12                (iii) of subparagraph (K) of this subsection 
13                (c).
14                    (E) The renewable energy credit delivery 
15                contract shall be subject to the contract and 
16                payment terms outlined in item (iv) of 
17                subparagraph (L) of this subsection (c). 
18                Contract instruments used for this 
19                subparagraph shall contain the following 
20                terms:
21                        (i) Renewable energy credit prices 
22                    shall be fixed, without further adjustment 
23                    under any other provision of this Act or 
24                    for any other reason, at 10% lower than 
25                    prices applicable to the last open block 
26                    for this category, inclusive of any adders 
 
 
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1                    available for achieving a minimum of 50% 
2                    of subscribers to the project's nameplate 
3                    capacity being residential or small 
4                    commercial customers with subscriptions of 
5                    below 25 kilowatts in size;
6                        (ii) A requirement that a minimum of 
7                    50% of subscribers to the project's 
8                    nameplate capacity be residential or small 
9                    commercial customers with subscriptions of 
10                    below 25 kilowatts in size;
11                        (iii) Permission for the ability of a 
12                    contract holder to substitute projects 
13                    with other waitlisted projects without 
14                    penalty should a project receive a 
15                    non-binding estimate of costs to construct 
16                    the interconnection facilities and any 
17                    required distribution upgrades associated 
18                    with that project of greater than 30 cents 
19                    per watt AC of that project's nameplate 
20                    capacity. In developing the applicable 
21                    contract instrument, the Agency may 
22                    consider whether other circumstances 
23                    outside of the control of the applicant 
24                    firm should also warrant project 
25                    substitution rights.
26                    The Agency shall publish a finalized 
 
 
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1                updated renewable energy credit delivery 
2                contract developed consistent with these terms 
3                and conditions no less than 30 days before 
4                applicant firms must submit their portfolio of 
5                projects pursuant to item (D).
6                    (F) To be eligible for an award, the 
7                applicant firm shall certify that not less 
8                than prevailing wage, as determined pursuant 
9                to the Illinois Prevailing Wage Act, was or 
10                will be paid to employees who are engaged in 
11                construction activities associated with a 
12                selected project.
13                (4) The Agency shall open the first block of 
14            annual capacity for the category described in item 
15            (iv) of subparagraph (K) of this paragraph (1). 
16            The first block of annual capacity for item (iv) 
17            shall be for at least 50 megawatts of total 
18            nameplate capacity. Renewable energy credit prices 
19            shall be fixed, without further adjustment under 
20            any other provision of this Act or for any other 
21            reason, at the price in the last open block in the 
22            category described in item (ii) of subparagraph 
23            (K) of this paragraph (1). Pricing for future 
24            blocks of annual capacity for this category may be 
25            adjusted in the Agency's second revision to its 
26            Long-Term Renewable Resources Procurement Plan. 
 
 
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1            Projects in this category shall be subject to the 
2            contract terms outlined in item (iv) of 
3            subparagraph (L) of this paragraph (1).
4                (5) The Agency shall open the equivalent of 2 
5            years of annual capacity for the category 
6            described in item (v) of subparagraph (K) of this 
7            paragraph (1). The first block of annual capacity 
8            for item (v) shall be for at least 10 megawatts of 
9            total nameplate capacity. Notwithstanding the 
10            provisions of item (v) of subparagraph (K) of this 
11            paragraph (1), for the purpose of this initial 
12            block, the agency shall accept new project 
13            applications intended to increase the diversity of 
14            areas hosting community solar projects, the 
15            business models of projects, and the size of 
16            projects, as described by the Agency in its 
17            long-term renewable resources procurement plan 
18            that is approved as of the effective date of this 
19            amendatory Act of the 102nd General Assembly. 
20            Projects in this category shall be subject to the 
21            contract terms outlined in item (iii) of 
22            subsection (L) of this paragraph (1).
23                (6) The Agency shall open the first blocks of 
24            annual capacity for the category described in item 
25            (vi) of subparagraph (K) of this paragraph (1), 
26            with allocations of capacity within the block 
 
 
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1            generally matching the historical share of block 
2            capacity allocated between the category described 
3            in items (i) and (ii) of subparagraph (K) of this 
4            paragraph (1). The first two blocks of annual 
5            capacity for item (vi) shall be for at least 75 
6            megawatts of total nameplate capacity. The price 
7            of renewable energy credits for the blocks of 
8            capacity shall be 4% less than the price of the 
9            last open blocks in the categories described in 
10            items (i) and (ii) of subparagraph (K) of this 
11            paragraph (1). Pricing for future blocks of annual 
12            capacity for this category may be adjusted in the 
13            Agency's second revision to its Long-Term 
14            Renewable Resources Procurement Plan. Projects in 
15            this category shall be subject to the applicable 
16            contract terms outlined in items (ii) and (iii) of 
17            subparagraph (L) of this paragraph (1).
18            (v) Upon the effective date of this amendatory Act 
19        of the 102nd General Assembly, for all competitive 
20        procurements and any procurements of renewable energy 
21        credit from new utility-scale wind and new 
22        utility-scale photovoltaic projects, the Agency shall 
23        procure indexed renewable energy credits and direct 
24        respondents to offer a strike price.
25                (1) The purchase price of the indexed 
26            renewable energy credit payment shall be 
 
 
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1            calculated for each settlement period. That 
2            payment, for any settlement period, shall be equal 
3            to the difference resulting from subtracting the 
4            strike price from the index price for that 
5            settlement period. If this difference results in a 
6            negative number, the indexed REC counterparty 
7            shall owe the seller the absolute value multiplied 
8            by the quantity of energy produced in the relevant 
9            settlement period. If this difference results in a 
10            positive number, the seller shall owe the indexed 
11            REC counterparty this amount multiplied by the 
12            quantity of energy produced in the relevant 
13            settlement period.
14                (2) Parties shall cash settle every month, 
15            summing up all settlements (both positive and 
16            negative, if applicable) for the prior month.
17                (3) To ensure funding in the annual budget 
18            established under subparagraph (E) for indexed 
19            renewable energy credit procurements for each year 
20            of the term of such contracts, which must have a 
21            minimum tenure of 20 calendar years, the 
22            procurement administrator, Agency, Commission 
23            staff, and procurement monitor shall quantify the 
24            annual cost of the contract by utilizing one or 
25            more an industry-standard, third-party forward 
26            price curves curve for energy at the appropriate 
 
 
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1            hub or load zone, including the estimated 
2            magnitude and timing of the price effects related 
3            to federal carbon controls. Each forward price 
4            curve shall contain a specific value of the 
5            forecasted market price of electricity for each 
6            annual delivery year of the contract. For 
7            procurement planning purposes, the impact on the 
8            annual budget for the cost of indexed renewable 
9            energy credits for each delivery year shall be 
10            determined as the expected annual contract 
11            expenditure for that year, equaling the difference 
12            between (i) the sum across all relevant contracts 
13            of the applicable strike price multiplied by 
14            contract quantity and (ii) the sum across all 
15            relevant contracts of the forward price curve for 
16            the applicable load zone for that year multiplied 
17            by contract quantity. The contracting utility 
18            shall not assume an obligation in excess of the 
19            estimated annual cost of the contracts for indexed 
20            renewable energy credits. Forward curves shall be 
21            revised on an annual basis as updated forward 
22            price curves are released and filed with the 
23            Commission in the proceeding approving the 
24            Agency's most recent long-term renewable resources 
25            procurement plan. If the expected contract spend 
26            is higher or lower than the total quantity of 
 
 
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1            contracts multiplied by the forward price curve 
2            value for that year, the forward price curve shall 
3            be updated by the procurement administrator, in 
4            consultation with the Agency, Commission staff, 
5            and procurement monitors, using then-currently 
6            available price forecast data and additional 
7            budget dollars shall be obligated or reobligated 
8            as appropriate.
9                (4) To ensure that indexed renewable energy 
10            credit prices remain predictable and affordable, 
11            the Agency may consider the institution of a price 
12            collar on REC prices paid under indexed renewable 
13            energy credit procurements establishing floor and 
14            ceiling REC prices applicable to indexed REC 
15            contract prices. Any price collars applicable to 
16            indexed REC procurements shall be proposed by the 
17            Agency through its long-term renewable resources 
18            procurement plan. 
19            (vi) All procurements under this subparagraph (G), 
20        including the procurement of renewable energy credits 
21        from hydropower facilities, shall comply with the 
22        geographic requirements in subparagraph (I) of this 
23        paragraph (1) and shall follow the procurement 
24        processes and procedures described in this Section and 
25        Section 16-111.5 of the Public Utilities Act to the 
26        extent practicable, and these processes and procedures 
 
 
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1        may be expedited to accommodate the schedule 
2        established by this subparagraph (G). To ensure the 
3        successful development of new renewable energy 
4        projects supported through competitive procurements, 
5        for any procurements conducted under items (i), (ii), 
6        (iii), and (v) of this subparagraph (G) and any other 
7        procurement of new utility-scale wind or utility-scale 
8        solar projects that were entered into prior to January 
9        1, 2025, the Agency shall allow, upon a demonstration 
10        of need to ensure the commercial viability of a 
11        project, for a one-time, post-award renegotiation of 
12        select contract terms prior to the project's 
13        commercial operation date through bilateral 
14        negotiation between the Agency, the buyer, and a 
15        winning bidder. Contract terms subject to 
16        renegotiation may include the project map, as defined 
17        under the applicable competitive solicitation, the 
18        real estate footprint or any limitations thereof, the 
19        location of the generators, or a potential reduction 
20        in the quantity of renewable energy credits to be 
21        delivered. Provisions related to a renewable energy 
22        credit delivery shortfall and the event of default may 
23        be replaced with similar provisions approved by the 
24        Agency in subsequent years or subsequent to a 
25        successful bid. Post-award renegotiation of 
26        competitively bid renewable energy credit contracts 
 
 
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1        entered into prior to January 1, 2025 shall not be 
2        permitted to the extent such renegotiation would 
3        result in (1) the point of interconnection being 
4        within the service area of a different state, a 
5        different regional transmission organization zone, or 
6        a different regional transmission organization, (2) 
7        the generator no longer meeting the definition of the 
8        resource category for which the winning bidder was 
9        originally awarded a contract, (3) the generator no 
10        longer meeting the Agency's public interest criteria 
11        as established in the long-term renewable resources 
12        plan in effect at the time of the contract award, or 
13        (4) a change to material terms of the renewable energy 
14        credit contract unrelated to project land or footprint 
15        or the number of renewable energy credits to be 
16        delivered, including the applicable bid price or 
17        strike price. If the Agency, the buyer, and the 
18        winning bidder reach an agreement on amended terms, 
19        then, upon petition by the winning bidder or current 
20        seller, the Commission shall issue an order directing 
21        the utility counterparty to execute an amendment 
22        drafted by the Agency with the revised terms to the 
23        renewable energy credit contract, the product order, 
24        or both. The Agency shall provide the amendment to the 
25        utility within 15 business days after the Commission's 
26        order, and the utility shall execute the amendment no 
 
 
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1        more than 7 calendar days after delivery by the 
2        Agency.    
3            (vii) On and after the effective date of this 
4        amendatory Act of the 103rd General Assembly, for all 
5        procurements of renewable energy credits from 
6        hydropower facilities, the Agency shall establish 
7        contract terms designed to optimize existing 
8        hydropower facilities through modernization or 
9        retooling and establish new hydropower facilities at 
10        existing dams. Procurements made under this item (vii) 
11        shall prioritize projects located in designated 
12        environmental justice communities, as defined in 
13        subsection (b) of Section 1-56 of this Act, or in 
14        projects located in units of local government with 
15        median incomes that do not exceed 82% of the median 
16        income of the State. 
17        (H) The procurement of renewable energy resources for 
18    a given delivery year shall be reduced as described in 
19    this subparagraph (H) if an alternative retail electric 
20    supplier meets the requirements described in this 
21    subparagraph (H). 
22            (i) Within 45 days after June 1, 2017 (the 
23        effective date of Public Act 99-906), an alternative 
24        retail electric supplier or its successor shall submit 
25        an informational filing to the Illinois Commerce 
26        Commission certifying that, as of December 31, 2015, 
 
 
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1        the alternative retail electric supplier owned one or 
2        more electric generating facilities that generates 
3        renewable energy resources as defined in Section 1-10 
4        of this Act, provided that such facilities are not 
5        powered by wind or photovoltaics, and the facilities 
6        generate one renewable energy credit for each 
7        megawatthour of energy produced from the facility.
8            The informational filing shall identify each 
9        facility that was eligible to satisfy the alternative 
10        retail electric supplier's obligations under Section 
11        16-115D of the Public Utilities Act as described in 
12        this item (i).
13            (ii) For a given delivery year, the alternative 
14        retail electric supplier may elect to supply its 
15        retail customers with renewable energy credits from 
16        the facility or facilities described in item (i) of 
17        this subparagraph (H) that continue to be owned by the 
18        alternative retail electric supplier.
19            (iii) The alternative retail electric supplier 
20        shall notify the Agency and the applicable utility, no 
21        later than February 28 of the year preceding the 
22        applicable delivery year or 15 days after June 1, 2017 
23        (the effective date of Public Act 99-906), whichever 
24        is later, of its election under item (ii) of this 
25        subparagraph (H) to supply renewable energy credits to 
26        retail customers of the utility. Such election shall 
 
 
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1        identify the amount of renewable energy credits to be 
2        supplied by the alternative retail electric supplier 
3        to the utility's retail customers and the source of 
4        the renewable energy credits identified in the 
5        informational filing as described in item (i) of this 
6        subparagraph (H), subject to the following 
7        limitations:
8                For the delivery year beginning June 1, 2018, 
9            the maximum amount of renewable energy credits to 
10            be supplied by an alternative retail electric 
11            supplier under this subparagraph (H) shall be 68% 
12            multiplied by 25% multiplied by 14.5% multiplied 
13            by the amount of metered electricity 
14            (megawatt-hours) delivered by the alternative 
15            retail electric supplier to Illinois retail 
16            customers during the delivery year ending May 31, 
17            2016.
18                For delivery years beginning June 1, 2019 and 
19            each year thereafter, the maximum amount of 
20            renewable energy credits to be supplied by an 
21            alternative retail electric supplier under this 
22            subparagraph (H) shall be 68% multiplied by 50% 
23            multiplied by 16% multiplied by the amount of 
24            metered electricity (megawatt-hours) delivered by 
25            the alternative retail electric supplier to 
26            Illinois retail customers during the delivery year 
 
 
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1            ending May 31, 2016, provided that the 16% value 
2            shall increase by 1.5% each delivery year 
3            thereafter to 25% by the delivery year beginning 
4            June 1, 2025, and thereafter the 25% value shall 
5            apply to each delivery year.
6            For each delivery year, the total amount of 
7        renewable energy credits supplied by all alternative 
8        retail electric suppliers under this subparagraph (H) 
9        shall not exceed 9% of the Illinois target renewable 
10        energy credit quantity. The Illinois target renewable 
11        energy credit quantity for the delivery year beginning 
12        June 1, 2018 is 14.5% multiplied by the total amount of 
13        metered electricity (megawatt-hours) delivered in the 
14        delivery year immediately preceding that delivery 
15        year, provided that the 14.5% shall increase by 1.5% 
16        each delivery year thereafter to 25% by the delivery 
17        year beginning June 1, 2025, and thereafter the 25% 
18        value shall apply to each delivery year.
19            If the requirements set forth in items (i) through 
20        (iii) of this subparagraph (H) are met, the charges 
21        that would otherwise be applicable to the retail 
22        customers of the alternative retail electric supplier 
23        under paragraph (6) of this subsection (c) for the 
24        applicable delivery year shall be reduced by the ratio 
25        of the quantity of renewable energy credits supplied 
26        by the alternative retail electric supplier compared 
 
 
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1        to that supplier's target renewable energy credit 
2        quantity. The supplier's target renewable energy 
3        credit quantity for the delivery year beginning June 
4        1, 2018 is 14.5% multiplied by the total amount of 
5        metered electricity (megawatt-hours) delivered by the 
6        alternative retail supplier in that delivery year, 
7        provided that the 14.5% shall increase by 1.5% each 
8        delivery year thereafter to 25% by the delivery year 
9        beginning June 1, 2025, and thereafter the 25% value 
10        shall apply to each delivery year. 
11            On or before April 1 of each year, the Agency shall 
12        annually publish a report on its website that 
13        identifies the aggregate amount of renewable energy 
14        credits supplied by alternative retail electric 
15        suppliers under this subparagraph (H). 
16        (I) The Agency shall design its long-term renewable 
17    energy procurement plan to maximize the State's interest 
18    in the health, safety, and welfare of its residents, 
19    including but not limited to minimizing sulfur dioxide, 
20    nitrogen oxide, particulate matter and other pollution 
21    that adversely affects public health in this State, 
22    increasing fuel and resource diversity in this State, 
23    enhancing the reliability and resiliency of the 
24    electricity distribution system in this State, meeting 
25    goals to limit carbon dioxide emissions under federal or 
26    State law, and contributing to a cleaner and healthier 
 
 
10400SB0025ham003- 234 -LRB104 07069 AAS 29208 a

1    environment for the citizens of this State. In order to 
2    further these legislative purposes, renewable energy 
3    credits shall be eligible to be counted toward the 
4    renewable energy requirements of this subsection (c) if 
5    they are generated from facilities located in this State. 
6    The Agency may qualify renewable energy credits from 
7    facilities located in states adjacent to Illinois or 
8    renewable energy credits associated with the electricity 
9    generated by a utility-scale wind energy facility or 
10    utility-scale photovoltaic facility and transmitted by a 
11    qualifying direct current project described in subsection 
12    (b-5) of Section 8-406 of the Public Utilities Act to a 
13    delivery point on the electric transmission grid located 
14    in this State or a state adjacent to Illinois, if the 
15    generator demonstrates and the Agency determines that the 
16    operation of such facility or facilities will help promote 
17    the State's interest in the health, safety, and welfare of 
18    its residents based on the public interest criteria 
19    described above. For the purposes of this Section, 
20    renewable resources that are delivered via a high voltage 
21    direct current converter station located in Illinois shall 
22    be deemed generated in Illinois at the time and location 
23    the energy is converted to alternating current by the high 
24    voltage direct current converter station if the high 
25    voltage direct current transmission line: (i) after the 
26    effective date of this amendatory Act of the 102nd General 
 
 
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1    Assembly, was constructed with a project labor agreement; 
2    (ii) is capable of transmitting electricity at 525kv; 
3    (iii) has an Illinois converter station located and 
4    interconnected in the region of the PJM Interconnection, 
5    LLC; (iv) does not operate as a public utility; and (v) if 
6    the high voltage direct current transmission line was 
7    energized after June 1, 2023. To ensure that the public 
8    interest criteria are applied to the procurement and given 
9    full effect, the Agency's long-term procurement plan shall 
10    describe in detail how each public interest factor shall 
11    be considered and weighted for facilities located in 
12    states adjacent to Illinois.
13        (J) In order to promote the competitive development of 
14    renewable energy resources in furtherance of the State's 
15    interest in the health, safety, and welfare of its 
16    residents, renewable energy credits shall not be eligible 
17    to be counted toward the renewable energy requirements of 
18    this subsection (c) if they are sourced from a generating 
19    unit whose costs were being recovered through rates 
20    regulated by this State or any other state or states on or 
21    after January 1, 2017. Each contract executed to purchase 
22    renewable energy credits under this subsection (c) shall 
23    provide for the contract's termination if the costs of the 
24    generating unit supplying the renewable energy credits 
25    subsequently begin to be recovered through rates regulated 
26    by this State or any other state or states; and each 
 
 
10400SB0025ham003- 236 -LRB104 07069 AAS 29208 a

1    contract shall further provide that, in that event, the 
2    supplier of the credits must return 110% of all payments 
3    received under the contract. Amounts returned under the 
4    requirements of this subparagraph (J) shall be retained by 
5    the utility and all of these amounts shall be used for the 
6    procurement of additional renewable energy credits from 
7    new wind or new photovoltaic resources as defined in this 
8    subsection (c). The long-term plan shall provide that 
9    these renewable energy credits shall be procured in the 
10    next procurement event.
11        Notwithstanding the limitations of this subparagraph 
12    (J), renewable energy credits sourced from generating 
13    units that are constructed, purchased, owned, or leased by 
14    an electric utility as part of an approved project, 
15    program, or pilot under Section 1-56 of this Act shall be 
16    eligible to be counted toward the renewable energy 
17    requirements of this subsection (c), regardless of how the 
18    costs of these units are recovered. As long as a 
19    generating unit or an identifiable portion of a generating 
20    unit has not had and does not have its costs recovered 
21    through rates regulated by this State or any other state, 
22    HVDC renewable energy credits associated with that 
23    generating unit or identifiable portion thereof shall be 
24    eligible to be counted toward the renewable energy 
25    requirements of this subsection (c). 
26        (K) The long-term renewable resources procurement plan 
 
 
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1    developed by the Agency in accordance with subparagraph 
2    (A) of this paragraph (1) shall include an Adjustable 
3    Block program for the procurement of renewable energy 
4    credits from new photovoltaic projects that are 
5    distributed renewable energy generation devices or new 
6    photovoltaic community renewable generation projects. The 
7    Adjustable Block program shall be generally designed to 
8    provide for the steady, predictable, and sustainable 
9    growth of new solar photovoltaic development in Illinois. 
10    To this end, the Adjustable Block program shall provide a 
11    transparent annual schedule of prices and quantities to 
12    enable the photovoltaic market to scale up and for 
13    renewable energy credit prices to adjust at a predictable 
14    rate over time. The prices set by the Adjustable Block 
15    program can be reflected as a set value or as the product 
16    of a formula.
17        The Adjustable Block program shall include for each 
18    category of eligible projects for each delivery year: a 
19    single block of nameplate capacity, a price for renewable 
20    energy credits within that block, and the terms and 
21    conditions for securing a spot on a waitlist once the 
22    block is fully committed or reserved. Except as outlined 
23    below, the waitlist of projects in a given year will carry 
24    over to apply to the subsequent year when another block is 
25    opened. Only projects energized on or after June 1, 2017 
26    shall be eligible for the Adjustable Block program. For 
 
 
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1    each category for each delivery year the Agency shall 
2    determine the amount of generation capacity in each block, 
3    and the purchase price for each block, provided that the 
4    purchase price provided and the total amount of generation 
5    in all blocks for all categories shall be sufficient to 
6    meet the goals in this subsection (c). The Agency shall 
7    strive to issue a single block sized to provide for 
8    stability and market growth. The Agency shall establish 
9    program eligibility requirements that ensure that projects 
10    that enter the program are sufficiently mature to indicate 
11    a demonstrable path to completion. The Agency may 
12    periodically review its prior decisions establishing the 
13    amount of generation capacity in each block, and the 
14    purchase price for each block, and may propose, on an 
15    expedited basis, changes to these previously set values, 
16    including but not limited to redistributing these amounts 
17    and the available funds as necessary and appropriate, 
18    subject to Commission approval as part of the periodic 
19    plan revision process described in Section 16-111.5 of the 
20    Public Utilities Act. The Agency may define different 
21    block sizes, purchase prices, or other distinct terms and 
22    conditions for projects located in different utility 
23    service territories if the Agency deems it necessary to 
24    meet the goals in this subsection (c).
25        The Adjustable Block program shall include the 
26    following categories in at least the following amounts:
 
 
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1            (i) At least 20% from distributed renewable energy 
2        generation devices with a nameplate capacity of no 
3        more than 25 kilowatts.
4            (ii) At least 20% from distributed renewable 
5        energy generation devices with a nameplate capacity of 
6        more than 25 kilowatts and no more than 10,000 5,000    
7        kilowatts. The Agency may create sub-categories within 
8        this category to account for the differences between 
9        projects for small commercial customers, large 
10        commercial customers, and public or non-profit 
11        customers. A project shall not be colocated with one 
12        or more other distributed renewable energy generation 
13        projects if the aggregate nameplate capacity of the 
14        projects exceeds 10,000 kilowatts AC. Notwithstanding 
15        any other provision of this Section, if 2 or more 
16        projects are developed, owned, or controlled by or 
17        originate from the same developer or an affiliated 
18        developer and the projects serve affiliated loads, the 
19        projects shall be colocated if the projects are 
20        located on adjacent parcels. If 2 or more projects are 
21        developed, owned, or controlled by or originate from 
22        the same developer and the projects serve unaffiliated 
23        loads, the projects may be colocated if documentation 
24        indicates affiliated management and ownership in the 
25        pre-development, development, construction, and 
26        management of the projects and the projects are 
 
 
10400SB0025ham003- 240 -LRB104 07069 AAS 29208 a

1        located on a single or adjacent parcels. 
2        Notwithstanding any subsequent transfer, assignment, 
3        or conveyance of ownership or development rights to 
4        separate legal entities, the Agency shall consider, in 
5        its determination of whether projects are affiliated, 
6        evidence that the projects were pre-developed by the 
7        same legal entity or an affiliated entity. If the 
8        Agency determines the projects are affiliated, the 
9        projects shall be treated as colocated for purposes of 
10        aggregate nameplate capacity limitations and renewable 
11        energy credit pricing adjustments. The Agency shall 
12        make exceptions on a case-by-case basis if it is 
13        demonstrated that projects on one parcel or projects 
14        on adjacent parcels are unaffiliated. For purposes of 
15        determining colocation, an approved vendor who submits 
16        an application for a distributed renewable energy 
17        generation project shall be required to submit an 
18        affidavit attesting that the project is not affiliated 
19        with any other distributed renewable energy generation 
20        project such that, if the 2 projects were deemed 
21        colocated, the projects would exceed the 10,000 
22        kilowatts nameplate capacity limitation. The receipt 
23        of an affidavit shall not restrict the Agency's 
24        ability to investigate and determine whether the 
25        project is, in fact, colocated.
26            For purposes of this item (ii):
 
 
10400SB0025ham003- 241 -LRB104 07069 AAS 29208 a

1            "Affiliate" has the meaning given to that term in 
2        subitem (3) of item (iii) of this subparagraph (K).
3            "Colocated" means 2 or more distributed renewable 
4        energy generation projects that are located on a 
5        single parcel, except for projects where the owner of 
6        the applicable retail electric account is confirmed to 
7        be unaffiliated and the projects serve distinct 
8        electrical loads.
9            "Control" has the meaning given to that term in 
10        subitem (3) of item (iii) of this subparagraph (K).
11            (iii) At least 30% from photovoltaic community 
12        renewable generation projects. Capacity for this 
13        category for the first 2 delivery years after the 
14        effective date of this amendatory Act of the 102nd 
15        General Assembly shall be allocated to waitlist 
16        projects as provided in paragraph (3) of item (iv) of 
17        subparagraph (G). Starting in the third delivery year 
18        after the effective date of this amendatory Act of the 
19        102nd General Assembly or earlier if the Agency 
20        determines there is additional capacity needed for to 
21        meet previous delivery year requirements, the 
22        following shall apply:
23                (1) the Agency shall select projects on a 
24            first-come, first-serve basis, however the Agency 
25            may suggest additional methods to prioritize 
26            projects that are submitted at the same time;
 
 
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1                (2) projects shall have subscriptions of 25 kW 
2            or less for at least 50% of the facility's 
3            nameplate capacity and the Agency shall price the 
4            renewable energy credits with that as a factor;
5                (3) projects shall not be colocated with one 
6            or more other community renewable generation 
7            projects such that the aggregate nameplate 
8            capacity exceeds 10,000 kilowatts. The total 
9            nameplate capacity of colocated projects shall be 
10            the sum of the nameplate capacities of the 
11            individual projects. For purposes of this subitem 
12            (3), separate legal formation of approved vendors, 
13            owners, or developers shall not preclude a finding 
14            of affiliation by the Agency. Evidence of 
15            affiliation may include, but is not limited to, 
16            shared personnel, common contractual or financing 
17            arrangements, a shared interconnection agreement, 
18            distinct interconnection agreements obtained by 
19            the same pre-development entity that are 
20            subsequently sold to distinct legal entities, 
21            familial relationships, or any demonstrable 
22            pattern of coordinated action in the 
23            pre-development, development, construction, or 
24            management of community renewable generation 
25            projects.
26                The Agency shall determine affiliation based 
 
 
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1            on evidence that projects either (i) share a 
2            common origin on a parcel that has been subdivided 
3            in the 5 years before the date of application or 
4            (ii) were pre-developed before the beginning of 
5            construction by the same legal entity or an 
6            affiliated legal entity. The determination shall 
7            be made notwithstanding any subsequent transfer, 
8            assignment, or conveyance of ownership or 
9            development rights to separate legal entities. If 
10            the Agency determines the projects are affiliated, 
11            the projects shall be treated as colocated for the 
12            purposes of aggregate nameplate capacity 
13            limitations and renewable energy credit pricing 
14            adjustments. The Agency shall make exceptions to 
15            this subitem (3) on a case-by-case basis if it is 
16            demonstrated that projects on one parcel or 
17            projects on adjacent parcels are unaffiliated.
18                A parcel shall not be divided into multiple 
19            parcels within the 5 years before the submission 
20            of a project application. If a parcel is divided 
21            within the preceding 5 years, a colocation 
22            determination shall be made based on the 
23            boundaries of the previous undivided parcel.
24                For purposes of determining colocation, an 
25            approved vendor who submits an application for a 
26            community renewable generation project shall be 
 
 
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1            required to submit an affidavit attesting that (i) 
2            the parcel on which the project is sited has not 
3            been subdivided within the 5 years preceding the 
4            project application and (ii) the project is not 
5            affiliated with any other community renewable 
6            energy project in a manner that would cause the 2 
7            projects, if deemed colocated, to exceed the 
8            10,000 kilowatt nameplate capacity limitation. The 
9            receipt of an affidavit shall not restrict the 
10            Agency's ability to investigate and determine 
11            whether the project is colocated.
12                Multiple community solar projects sited on 
13            distinct structures located on a single parcel 
14            shall be considered colocated and must demonstrate 
15            that the projects are unaffiliated in order to not 
16            be considered colocated. Each colocated project 
17            shall receive the renewable energy credit price 
18            corresponding to the total, aggregated nameplate 
19            capacity of the colocated systems, as determined 
20            at the time the second project's application is 
21            submitted to the Agency. If the second colocated 
22            project has been constructed and placed in service 
23            prior to application, and was placed in service 
24            more than 2 years after Commission approval of the 
25            original project, the colocation pricing 
26            adjustment shall not apply, and each project shall 
 
 
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1            receive the standalone renewable energy credit 
2            price for its individual capacity.    
3                For purposes of this subitem (3):
4                "Affiliate" means any other entity that, 
5            directly or indirectly through one or more 
6            intermediaries, is controlled by or is under 
7            common control of the primary entity or a third 
8            entity. "Affiliate" includes family members for 
9            the purposes of colocation between projects. 
10            "Affiliate" does not include entities that have 
11            shared sales or revenue-sharing arrangements or 
12            common debt and equity financing arrangements.
13                "Colocated" means 2 or more community 
14            renewable generation projects located on a single 
15            parcel or adjacent parcels, unless it is 
16            demonstrated that the projects are developed by 
17            unaffiliated entities.
18                "Control" means the possession, directly or 
19            indirectly, of the power to direct the management 
20            and policies of an entity , as defined in the 
21            Agency's first revised long-term renewable 
22            resources procurement plan approved by the 
23            Commission on February 18, 2020, such that the 
24            aggregate nameplate capacity exceeds 5,000 
25            kilowatts; and
26                (4) projects greater than 2 MW may not apply 
 
 
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1            until after the approval of the Agency's revised 
2            Long-Term Renewable Resources Procurement Plan 
3            after the effective date of this amendatory Act of 
4            the 102nd General Assembly. 
5            (iv) At least 15% from distributed renewable 
6        generation devices or photovoltaic community renewable 
7        generation projects installed on public school land. 
8        The Agency may create subcategories within this 
9        category to account for the differences between 
10        project size or location. Projects located within 
11        environmental justice communities or within 
12        Organizational Units that fall within Tier 1 or Tier 2 
13        shall be given priority. Each of the Agency's periodic 
14        updates to its long-term renewable resources 
15        procurement plan to incorporate the procurement 
16        described in this subparagraph (iv) shall also include 
17        the proposed quantities or blocks, pricing, and 
18        contract terms applicable to the procurement as 
19        indicated herein. In each such update and procurement, 
20        the Agency shall set the renewable energy credit price 
21        and establish payment terms for the renewable energy 
22        credits procured pursuant to this subparagraph (iv) 
23        that make it feasible and affordable for public 
24        schools to install photovoltaic distributed renewable 
25        energy devices on their premises, including, but not 
26        limited to, those public schools subject to the 
 
 
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1        prioritization provisions of this subparagraph. For 
2        the purposes of this item (iv):
3            "Environmental Justice Community" shall have the 
4        same meaning set forth in the Agency's long-term 
5        renewable resources procurement plan;
6            "Organization Unit", "Tier 1" and "Tier 2" shall 
7        have the meanings set for in Section 18-8.15 of the 
8        School Code;
9            "Public schools" shall have the meaning set forth 
10        in Section 1-3 of the School Code and includes public 
11        institutions of higher education, as defined in the 
12        Board of Higher Education Act.
13            (v) At least 5% from community-driven community 
14        solar projects intended to provide more direct and 
15        tangible connection and benefits to the communities 
16        which they serve or in which they operate and, 
17        additionally, to increase the variety of community 
18        solar locations, models, and options in Illinois. As 
19        part of its long-term renewable resources procurement 
20        plan, the Agency shall develop selection criteria for 
21        projects participating in this category. Nothing in 
22        this Section shall preclude the Agency from creating a 
23        selection process that maximizes community ownership 
24        and community benefits in selecting projects to 
25        receive renewable energy credits. Selection criteria 
26        shall include:
 
 
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1                (1) community ownership or community 
2            wealth-building;
3                (2) additional direct and indirect community 
4            benefit, beyond project participation as a 
5            subscriber, including, but not limited to, 
6            economic, environmental, social, cultural, and 
7            physical benefits;
8                (3) meaningful involvement in project 
9            organization and development by community members 
10            or nonprofit organizations or public entities 
11            located in or serving the community;
12                (4) engagement in project operations and 
13            management by nonprofit organizations, public 
14            entities, or community members; and
15                (5) whether a project is developed in response 
16            to a site-specific RFP developed by community 
17            members or a nonprofit organization or public 
18            entity located in or serving the community.
19            Selection criteria may also prioritize projects 
20        that:
21                (1) are developed in collaboration with or to 
22            provide complementary opportunities for the Clean 
23            Jobs Workforce Network Program, the Illinois 
24            Climate Works Preapprenticeship Program, the 
25            Returning Residents Clean Jobs Training Program, 
26            the Clean Energy Contractor Incubator Program, or 
 
 
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1            the Clean Energy Primes Contractor Accelerator 
2            Program;
3                (2) increase the diversity of locations of 
4            community solar projects in Illinois, including by 
5            locating in urban areas and population centers;
6                (3) are located in Equity Investment Eligible 
7            Communities;
8                (4) are not greenfield projects;
9                (5) serve only local subscribers;
10                (6) have a nameplate capacity that does not 
11            exceed 500 kW;
12                (7) are developed by an equity eligible 
13            contractor; or
14                (8) otherwise meaningfully advance the goals 
15            of providing more direct and tangible connection 
16            and benefits to the communities which they serve 
17            or in which they operate and increasing the 
18            variety of community solar locations, models, and 
19            options in Illinois.
20            For the purposes of this item (v):
21            "Community" means a social unit in which people 
22        come together regularly to effect change; a social 
23        unit in which participants are marked by a cooperative 
24        spirit, a common purpose, or shared interests or 
25        characteristics; or a space understood by its 
26        residents to be delineated through geographic 
 
 
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1        boundaries or landmarks.
2            "Community benefit" means a range of services and 
3        activities that provide affirmative, economic, 
4        environmental, social, cultural, or physical value to 
5        a community; or a mechanism that enables economic 
6        development, high-quality employment, and education 
7        opportunities for local workers and residents, or 
8        formal monitoring and oversight structures such that 
9        community members may ensure that those services and 
10        activities respond to local knowledge and needs.
11            "Community ownership" means an arrangement in 
12        which an electric generating facility is, or over time 
13        will be, in significant part, owned collectively by 
14        members of the community to which an electric 
15        generating facility provides benefits; members of that 
16        community participate in decisions regarding the 
17        governance, operation, maintenance, and upgrades of 
18        and to that facility; and members of that community 
19        benefit from regular use of that facility.
20            Terms and guidance within these criteria that are 
21        not defined in this item (v) shall be defined by the 
22        Agency, with stakeholder input, during the development 
23        of the Agency's long-term renewable resources 
24        procurement plan. The Agency shall develop regular 
25        opportunities for projects to submit applications for 
26        projects under this category, and develop selection 
 
 
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1        criteria that gives preference to projects that better 
2        meet individual criteria as well as projects that 
3        address a higher number of criteria.
4            (vi) At least 10% from distributed renewable 
5        energy generation devices, which includes distributed 
6        renewable energy devices with a nameplate capacity 
7        under 5,000 kilowatts or photovoltaic community 
8        renewable generation projects, from applicants that 
9        are equity eligible contractors. The Agency may create 
10        subcategories within this category to account for the 
11        differences between project size and type. The Agency 
12        shall propose to increase the percentage in this item 
13        (vi) over time to 40% based on factors, including, but 
14        not limited to, the number of equity eligible 
15        contractors and capacity used in this item (vi) in 
16        previous delivery years.
17            The Agency shall propose a payment structure for 
18        contracts executed pursuant to this paragraph under 
19        which, upon a demonstration of qualification or need 
20        under criteria established by the Agency that is 
21        focused on supporting small and emerging businesses 
22        and businesses that most acutely face barriers to the 
23        access of capital, applicant firms are advanced 
24        capital disbursed after contract execution but before 
25        the contracted project's energization. The amount or 
26        percentage of capital advanced prior to project 
 
 
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1        energization shall be sufficient to both cover any 
2        increase in development costs resulting from 
3        prevailing wage requirements or project-labor 
4        agreements, and designed to overcome barriers in 
5        access to capital faced by equity eligible 
6        contractors. The amount or percentage of advanced 
7        capital may vary by subcategory within this category 
8        and by an applicant's demonstration of need, with such 
9        levels to be established through the Long-Term 
10        Renewable Resources Procurement Plan authorized under 
11        subparagraph (A) of paragraph (1) of subsection (c) of 
12        this Section and any application requirements or 
13        evaluation criteria developed pursuant to the Plan.
14            Contracts developed featuring capital advanced 
15        prior to a project's energization shall feature 
16        provisions to ensure both the successful development 
17        of applicant projects and the delivery of the 
18        renewable energy credits for the full term of the 
19        contract, including ongoing collateral requirements 
20        and other provisions deemed necessary by the Agency, 
21        and may include energization timelines longer than for 
22        comparable project types. The percentage or amount of 
23        capital advanced prior to project energization shall 
24        not operate to increase the overall contract value, 
25        however contracts executed under this subparagraph may 
26        feature renewable energy credit prices higher than 
 
 
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1        those offered to similar projects participating in 
2        other categories. Capital advanced prior to 
3        energization shall serve to reduce the ratable 
4        payments made after energization under items (ii) and 
5        (iii) of subparagraph (L) or payments made for each 
6        renewable energy credit delivery under item (iv) of 
7        subparagraph (L).
8            For projects developed under this item (vi), the 
9        Agency shall take steps to encourage higher portions 
10        of contract value to be provided to equity eligible 
11        contractors and to support equity eligible persons who 
12        participate in this Program and who exercise control 
13        and actively manage their businesses and their 
14        businesses' contractual projects. These steps may 
15        include, but are not limited to, differentiated REC 
16        prices, exceptions or exemptions, and other mechanisms 
17        and requirements for nonnominal contract value to be 
18        provided to equity eligible contractors and equity 
19        eligible persons as a prerequisite to Program 
20        participation. Any steps taken shall aim to encourage 
21        and grow the meaningful participation of equity 
22        eligible contractors in this State's clean energy 
23        economy. All entities participating under this item 
24        (vi) shall comply with the minimum equity standard set 
25        forth under Section 1-75.    
26            (vii) The remaining capacity shall be allocated by 
 
 
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1        the Agency in order to respond to market demand. The 
2        Agency shall allocate any discretionary capacity prior 
3        to the beginning of each delivery year. 
4            (viii) The Agency, through its long-term renewable 
5        resources procurement plan, may implement solutions to 
6        maintain stable and consistent REC offerings allocated 
7        to systems described in item (i) of this subparagraph 
8        (K) to avoid gaps in availability during a delivery 
9        year, including, but not limited to, creating a 
10        floating block of REC capacity in a given delivery 
11        year.    
12        To the extent there is uncontracted capacity from any 
13    block in any of categories (i) through (vi) at the end of a 
14    delivery year, the Agency shall redistribute that capacity 
15    to one or more other categories giving priority to 
16    categories with projects on a waitlist. The redistributed 
17    capacity shall be added to the annual capacity in the 
18    subsequent delivery year, and the price for renewable 
19    energy credits shall be the price for the new delivery 
20    year. Redistributed capacity shall not be considered 
21    redistributed when determining whether the goals in this 
22    subsection (K) have been met. 
23        Notwithstanding anything to the contrary, as the 
24    Agency increases the capacity in item (vi) to 40% over 
25    time, the Agency may reduce the capacity of items (i) 
26    through (v) proportionate to the capacity of the 
 
 
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1    categories of projects in item (vi), to achieve a balance 
2    of project types. 
3        The Adjustable Block program shall be designed to 
4    ensure that renewable energy credits are procured from 
5    projects in diverse locations and are not concentrated in 
6    a few regional areas. 
7        (L) Notwithstanding provisions for advancing capital 
8    prior to project energization found in item (vi) of 
9    subparagraph (K), the procurement of photovoltaic 
10    renewable energy credits under items (i) through (vi) of 
11    subparagraph (K) of this paragraph (1) shall otherwise be 
12    subject to the following contract and payment terms:
13            (i) (Blank). 
14            (ii) Unless otherwise provided for in the Agency's 
15        approved long-term plan, for For those renewable 
16        energy credits that qualify and are procured under 
17        item (i) of subparagraph (K) of this paragraph (1), 
18        and any similar category projects that are procured 
19        under item (vi) of subparagraph (K) of this paragraph 
20        (1) that qualify and are procured under item (vi), the 
21        contract length shall be 15 years. Beginning on the 
22        effective date of this amendatory Act of the 104th 
23        General Assembly, and including the remainder of 
24        program year 2026-2027, 50% of the renewable energy 
25        credit delivery contract value, based on the estimated 
26        generation during the first 15 years of operation, 
 
 
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1        shall be paid The renewable energy credit delivery 
2        contract value shall be paid in full, based on the 
3        estimated generation during the first 15 years of 
4        operation, by the contracting utilities at the time 
5        that the facility producing the renewable energy 
6        credits is interconnected at the distribution system 
7        level of the utility and verified as energized and 
8        compliant by the Program Administrator. The remaining 
9        portion of the renewable energy credit delivery 
10        contract value shall be paid ratably over the 
11        subsequent 6-year period. Relative to a contract 
12        structure under which the full renewable energy credit 
13        delivery contract value shall be paid in full at the 
14        time of interconnection and verification of 
15        energization, the Agency shall consider the impact of 
16        deferred payments across the subsequent payment period 
17        when establishing renewable energy credit prices. The 
18        electric utility shall receive and retire all 
19        renewable energy credits generated by the project for 
20        the first 15 years of operation. Renewable energy 
21        credits generated by the project thereafter shall not 
22        be transferred under the renewable energy credit 
23        delivery contract with the counterparty electric 
24        utility. 
25            (iii) Unless otherwise provided for in the 
26        Agency's approved long-term plan, for For those 
 
 
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1        renewable energy credits that qualify and are procured 
2        under item (ii) and (v) of subparagraph (K) of this 
3        paragraph (1) and any like projects similar category    
4        that qualify and are procured under items (iv) and    
5        item (vi), the contract length shall be 15 years. 15% 
6        of the renewable energy credit delivery contract 
7        value, based on the estimated generation during the 
8        first 15 years of operation, shall be paid by the 
9        contracting utilities at the time that the facility 
10        producing the renewable energy credits is 
11        interconnected at the distribution system level of the 
12        utility and verified as energized and compliant by the 
13        Program Administrator. The remaining portion shall be 
14        paid ratably over the subsequent 6-year period. The 
15        electric utility shall receive and retire all 
16        renewable energy credits generated by the project for 
17        the first 15 years of operation. Renewable energy 
18        credits generated by the project thereafter shall not 
19        be transferred under the renewable energy credit 
20        delivery contract with the counterparty electric 
21        utility. 
22            (iv) Unless otherwise provided for in the Agency's 
23        approved long-term plan, for For those renewable 
24        energy credits that qualify and are procured under 
25        item items (iii) and (iv) of subparagraph (K) of this 
26        paragraph (1), and any like projects that qualify and 
 
 
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1        are procured under items (iv) and item (vi), the 
2        renewable energy credit delivery contract length shall 
3        be 20 years and shall be paid over the delivery term, 
4        not to exceed during each delivery year the contract 
5        price multiplied by the estimated annual renewable 
6        energy credit generation amount. If generation of 
7        renewable energy credits during a delivery year 
8        exceeds the estimated annual generation amount, the 
9        excess renewable energy credits shall be carried 
10        forward to future delivery years and shall not expire 
11        during the delivery term. If generation of renewable 
12        energy credits during a delivery year, including 
13        carried forward excess renewable energy credits, if 
14        any, is less than the estimated annual generation 
15        amount, payments during such delivery year will not 
16        exceed the quantity generated plus the quantity 
17        carried forward multiplied by the contract price. The 
18        electric utility shall receive all renewable energy 
19        credits generated by the project during the first 20 
20        years of operation and retire all renewable energy 
21        credits paid for under this item (iv) and return at the 
22        end of the delivery term all renewable energy credits 
23        that were not paid for. Renewable energy credits 
24        generated by the project thereafter shall not be 
25        transferred under the renewable energy credit delivery 
26        contract with the counterparty electric utility. 
 
 
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1        Notwithstanding the preceding, for those projects 
2        participating under item (iii) of subparagraph (K), 
3        the contract price for a delivery year shall be based 
4        on subscription levels as measured on the higher of 
5        the first business day of the delivery year or the 
6        first business day 6 months after the first business 
7        day of the delivery year. Subscription of 90% of 
8        nameplate capacity or greater shall be deemed to be 
9        fully subscribed for the purposes of this item (iv). 
10        For projects receiving a 20-year delivery contract, 
11        REC prices shall be adjusted downward for consistency 
12        with the incentive levels previously determined to be 
13        necessary to support projects under 15-year delivery 
14        contracts, taking into consideration any additional 
15        new requirements placed on the projects, including, 
16        but not limited to, labor standards. 
17            (v) Each contract shall include provisions to 
18        ensure the delivery of the estimated quantity of 
19        renewable energy credits and ongoing collateral 
20        requirements and other provisions deemed appropriate 
21        by the Agency. 
22            (vi) The utility shall be the counterparty to the 
23        contracts executed under this subparagraph (L) that 
24        are approved by the Commission under the process 
25        described in Section 16-111.5 of the Public Utilities 
26        Act. No contract shall be executed for an amount that 
 
 
10400SB0025ham003- 260 -LRB104 07069 AAS 29208 a

1        is less than one renewable energy credit per year.
2            (vii) If, at any time, approved applications for 
3        the Adjustable Block program exceed funds collected by 
4        the electric utility or would cause the Agency to 
5        exceed the limitation described in subparagraph (E) of 
6        this paragraph (1) on the amount of renewable energy 
7        resources that may be procured, then the Agency may 
8        consider future uncommitted funds to be reserved for 
9        these contracts on a first-come, first-served basis.
10            (viii) Nothing in this Section shall require the 
11        utility to advance any payment or pay any amounts that 
12        exceed the actual amount of revenues anticipated to be 
13        collected by the utility under paragraph (6) of this 
14        subsection (c) and subsection (k) of Section 16-108 of 
15        the Public Utilities Act inclusive of eligible funds 
16        collected in prior years and alternative compliance 
17        payments for use by the utility. 
18            (ix) Notwithstanding other requirements of this 
19        subparagraph (L), no modification shall be required to 
20        Adjustable Block program contracts if they were 
21        already executed prior to the establishment, approval, 
22        and implementation of new contract forms as a result 
23        of this amendatory Act of the 102nd General Assembly.
24            (x) Contracts may be assignable, but only to 
25        entities first deemed by the Agency to have met 
26        program terms and requirements applicable to direct 
 
 
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1        program participation. In developing contracts for the 
2        delivery of renewable energy credits, the Agency shall 
3        be permitted to establish fees applicable to each 
4        contract assignment. 
5        (M) The Agency shall be authorized to retain one or 
6    more experts or expert consulting firms to develop, 
7    administer, implement, operate, and evaluate the 
8    Adjustable Block program described in subparagraph (K) of 
9    this paragraph (1), as well as the Geothermal Homes and 
10    Businesses Program described in subparagraph (S) of this 
11    paragraph (1), and the Agency shall retain the consultant 
12    or consultants in the same manner, to the extent 
13    practicable, as the Agency retains others to administer 
14    provisions of this Act, including, but not limited to, the 
15    procurement administrator. The selection of experts and 
16    expert consulting firms and the procurement process 
17    described in this subparagraph (M) are exempt from the 
18    requirements of Section 20-10 of the Illinois Procurement 
19    Code, under Section 20-10 of that Code. The Agency shall 
20    strive to minimize administrative expenses in the 
21    implementation of the Adjustable Block program.
22        The Program Administrator may charge application fees 
23    to participating firms to cover the cost of program 
24    administration. Any application fee amounts shall 
25    initially be determined through the long-term renewable 
26    resources procurement plan, and modifications to any 
 
 
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1    application fee that deviate more than 25% from the 
2    Commission's approved value must be approved by the 
3    Commission as a long-term plan revision under Section 
4    16-111.5 of the Public Utilities Act. The Agency shall 
5    consider stakeholder feedback when making adjustments to 
6    application fees and shall notify stakeholders in advance 
7    of any planned changes. 
8        In addition to covering the costs of program 
9    administration, the Agency, in conjunction with its 
10    Program Administrator, may also use the proceeds of such 
11    fees charged to participating firms to support public 
12    education and ongoing regional and national coordination 
13    with nonprofit organizations, public bodies, and others 
14    engaged in the implementation of renewable energy 
15    incentive programs or similar initiatives. This work may 
16    include developing papers and reports, hosting regional 
17    and national conferences, and other work deemed necessary 
18    by the Agency to position the State of Illinois as a 
19    national leader in renewable energy incentive program 
20    development and administration. 
21        The Agency and its consultant or consultants shall 
22    monitor block activity, share program activity with 
23    stakeholders and conduct quarterly meetings to discuss 
24    program activity and market conditions. If necessary, the 
25    Agency may make prospective administrative adjustments to 
26    the Adjustable Block program and the Geothermal Homes and 
 
 
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1    Businesses Program design, such as making adjustments to 
2    purchase prices as necessary to achieve the goals of this 
3    subsection (c). Program modifications to any block price 
4    that do not deviate from the Commission's approved value 
5    by more than 10% shall take effect immediately and are not 
6    subject to Commission review and approval. Program 
7    modifications to any block price that deviate more than 
8    10% from the Commission's approved value must be approved 
9    by the Commission as a long-term plan amendment under 
10    Section 16-111.5 of the Public Utilities Act. The Agency 
11    shall consider stakeholder feedback when making 
12    adjustments to the Adjustable Block and the Geothermal 
13    Homes and Businesses Program design and shall notify 
14    stakeholders in advance of any planned changes.
15        The Agency and its program administrators for both the 
16    Adjustable Block program, and the Illinois Solar for All 
17    Program, and the Geothermal Homes and Businesses Program    
18    consistent with the requirements of this subsection (c) 
19    and subsection (b) of Section 1-56 of this Act, shall 
20    propose the Adjustable Block program terms, conditions, 
21    and requirements, including the prices to be paid for 
22    renewable energy credits, where applicable, and 
23    requirements applicable to participating entities and 
24    project applications, through the development, review, and 
25    approval of the Agency's long-term renewable resources 
26    procurement plan described in this subsection (c) and 
 
 
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1    paragraph (5) of subsection (b) of Section 16-111.5 of the 
2    Public Utilities Act. Terms, conditions, and requirements 
3    for program participation shall include the following:
4            (i) The Agency shall establish a registration 
5        process for entities seeking to qualify for 
6        program-administered incentive funding and establish 
7        baseline qualifications for vendor approval. The 
8        Agency shall also establish program requirements and 
9        minimum contract terms for vendors and others involved 
10        in the marketing, sale, installation, and financing of 
11        distributed generation systems and community solar 
12        subscriptions to prevent misleading marketing and 
13        abusive practices and to otherwise protect customers.    
14        The Agency must maintain a list of approved entities 
15        on each program's website, and may revoke a vendor's 
16        ability to receive program-administered incentive 
17        funding status upon a determination that the vendor 
18        failed to comply with contract terms, the law, or 
19        other program requirements.
20            (ii) The Agency shall establish program 
21        requirements and minimum contract terms to ensure 
22        projects are properly installed and produce their 
23        expected amounts of energy. Program requirements may 
24        include on-site inspections and photo documentation of 
25        projects under construction. The Agency may require 
26        repairs, alterations, or additions to remedy any 
 
 
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1        material deficiencies discovered. Vendors who have a 
2        disproportionately high number of deficient systems 
3        may lose their eligibility to continue to receive 
4        State-administered incentive funding through Agency 
5        programs and procurements.
6            (iii) To discourage deceptive marketing or other 
7        bad faith business practices, the Agency may require 
8        direct program participants, including agents 
9        operating on their behalf, to provide standardized 
10        disclosures to a customer prior to that customer's 
11        execution of a contract for the development of a 
12        distributed generation system, or a subscription to a 
13        community solar project, or the development of a 
14        geothermal heating and cooling system.
15            (iv) The Agency shall establish one or multiple 
16        Consumer Complaints Centers to accept complaints 
17        regarding businesses that participate in, or otherwise 
18        benefit from, State-administered incentive funding 
19        through Agency-administered programs. The Agency shall 
20        maintain a public database of complaints with any 
21        confidential or particularly sensitive information 
22        redacted from public entries.
23            (v) Through a filing in the proceeding for the 
24        approval of its long-term renewable energy resources 
25        procurement plan, the Agency shall provide an annual 
26        written report to the Illinois Commerce Commission 
 
 
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1        documenting the frequency and nature of complaints and 
2        any enforcement actions taken in response to those 
3        complaints.
4            (vi) The Agency shall schedule regular meetings 
5        with representatives of the Office of the Attorney 
6        General, the Illinois Commerce Commission, consumer 
7        protection groups, and other interested stakeholders 
8        to share relevant information about consumer 
9        protection, project compliance, and complaints 
10        received.
11            (vii) To the extent that complaints received 
12        implicate the jurisdiction of the Office of the 
13        Attorney General, the Illinois Commerce Commission, or 
14        local, State, or federal law enforcement, the Agency 
15        shall also refer complaints to those entities as 
16        appropriate. 
17            (viii) The Agency shall establish a registration 
18        process for entities that provide financing for 
19        consumers for the purchase of distributed renewable 
20        generation devices. The Agency may establish baseline 
21        qualifications for financier approval, including 
22        defining the circumstances under which financing 
23        parties may be subject to registration. The Agency 
24        shall also establish program requirements for entities 
25        that provide financing for the purchase of distributed 
26        renewable generation devices, which may include 
 
 
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1        marketing and disclosure requirements, other 
2        requirements as further defined by the Agency through 
3        its long-term plan, and any consumer protection 
4        requirements developed or modified thereto. The Agency 
5        shall maintain a list of approved financiers on each 
6        program's website and may revoke a financier's 
7        approval in a program upon a determination that the 
8        financier failed to comply with contract terms, the 
9        law, or other program requirements. The Agency may 
10        establish program requirements that prohibit 
11        distributed renewable generation devices intending to 
12        apply for program-administered incentive funding from 
13        receiving program funding the consumer's purchase if 
14        the device was financed by an entity whose approval 
15        status in the program has been revoked.
16            (ix) The Agency may propose that vendors, as part 
17        of the application and annual recertification process, 
18        present the Agency or its designee with a security 
19        bond equal to an amount determined to be reasonable by 
20        the Agency. The bond shall be for the benefit of 
21        customers harmed by the vendor's violation of Agency 
22        requirements or other applicable laws or regulations. 
23        The Agency may determine that it is reasonable to have 
24        no bond requirement for some categories of vendors or 
25        enhanced bond requirements for vendors that the Agency 
26        has deemed to pose more acute risks.
 
 
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1            (x) For distributed renewable generation devices, 
2        the Agency may, in its discretion, establish 
3        provisions that restrict, prohibit, or create 
4        additional requirements for distributed renewable 
5        generation device sales or financing offers through 
6        which the customer is promised the pass-through of a 
7        portion or all of the payments received by the 
8        approved vendor for the delivery of renewable energy 
9        credits only after the receipt of such payment by the 
10        approved vendor. The requirements may include the use 
11        of an escrow process developed by the Agency through 
12        which renewable energy credit payments are made to an 
13        escrow agent who then disburses the promised amount to 
14        the customer and the remainder to the vendor. The 
15        requirements in this item (x) shall in no way prohibit 
16        the upfront discounting of the purchase price, lease 
17        payment, or power purchase agreement rate based on the 
18        anticipated receipt of renewable energy credit 
19        contract payments by the approved vendor.
20            (xi) To the extent that distributed renewable 
21        generation device sales or financing offers through 
22        which the customer is promised the pass-through of a 
23        portion or all of the payments received by the vendor 
24        for the delivery of renewable energy credits after the 
25        receipt of such payment by the vendor are permitted, 
26        the following requirements shall apply in a time and 
 
 
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1        manner determined by the Agency:
2                (I) the vendor shall submit proof of customer 
3            payments to the Agency as the Agency deems 
4            necessary; and
5                (II) the vendor shall represent and warrant on 
6            a form developed by the Agency that the vendor is 
7            not insolvent, has not voluntarily filed for 
8            bankruptcy, and has not been subject to or 
9            threatened with involuntary insolvency.
10            (xii) To ensure that customers receive full and 
11        uninterrupted benefits and services promised by 
12        vendors, the Agency may propose additional solutions 
13        through its long-term renewable resources procurement 
14        plan described in this subsection (c) and paragraph 
15        (5) of subsection (b) of Section 16-111.5 of the 
16        Public Utilities Act. The solutions may allow for 
17        collections made pursuant to subsection (k) of Section 
18        16-108 of the Public Utilities Act to support the 
19        programs and procurements outlined in paragraph (1) of 
20        subsection (c) of this Section to be leveraged to (1) 
21        ensure that a vendor's promised payments are received 
22        by customers, (2) incentivize vendors to establish 
23        service agreements with customers whose original 
24        vendor has become nonresponsive, (3) ensure that 
25        customers receive restitution for financial harm 
26        proven to be caused by a program vendor or its 
 
 
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1        designee, or (4) otherwise ensure that customers do 
2        not suffer loss or harm through activities supported 
3        by the Adjustable Block program and the Illinois Solar 
4        for All Program.    
5        (N) The Agency shall establish the terms, conditions, 
6    and program requirements for photovoltaic community 
7    renewable generation projects with a goal to expand access 
8    to a broader group of energy consumers, to ensure robust 
9    participation opportunities for residential and small 
10    commercial customers and those who cannot install 
11    renewable energy on their own properties. Subject to 
12    reasonable limitations, any plan approved by the 
13    Commission shall allow subscriptions to community 
14    renewable generation projects to be portable and 
15    transferable. For purposes of this subparagraph (N), 
16    "portable" means that subscriptions may be retained by the 
17    subscriber even if the subscriber relocates or changes its 
18    address within the same utility service territory; and 
19    "transferable" means that a subscriber may assign or sell 
20    subscriptions to another person within the same utility 
21    service territory.
22        Through the development of its long-term renewable 
23    resources procurement plan, the Agency may consider 
24    whether community renewable generation projects utilizing 
25    technologies other than photovoltaics should be supported 
26    through State-administered incentive funding, and may 
 
 
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1    issue requests for information to gauge market demand. 
2        Electric utilities shall provide a monetary credit to 
3    a subscriber's subsequent bill for service for the 
4    proportional output of a community renewable generation 
5    project attributable to that subscriber as specified in 
6    Section 16-107.5 of the Public Utilities Act.
7        The Agency shall purchase renewable energy credits 
8    from subscribed shares of photovoltaic community renewable 
9    generation projects through the Adjustable Block program 
10    described in subparagraph (K) of this paragraph (1) or 
11    through the Illinois Solar for All Program described in 
12    Section 1-56 of this Act. The electric utility shall 
13    purchase any unsubscribed energy from community renewable 
14    generation projects that are Qualifying Facilities ("QF") 
15    under the electric utility's tariff for purchasing the 
16    output from QFs under Public Utilities Regulatory Policies 
17    Act of 1978. 
18        The owners of and any subscribers to a community 
19    renewable generation project shall not be considered 
20    public utilities or alternative retail electricity 
21    suppliers under the Public Utilities Act solely as a 
22    result of their interest in or subscription to a community 
23    renewable generation project and shall not be required to 
24    become an alternative retail electric supplier by 
25    participating in a community renewable generation project 
26    with a public utility.
 
 
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1        (O) For the delivery year beginning June 1, 2018, the 
2    long-term renewable resources procurement plan required by 
3    this subsection (c) shall provide for the Agency to 
4    procure contracts to continue offering the Illinois Solar 
5    for All Program described in subsection (b) of Section 
6    1-56 of this Act, and the contracts approved by the 
7    Commission shall be executed by the utilities that are 
8    subject to this subsection (c). The long-term renewable 
9    resources procurement plan shall allocate up to 
10    $50,000,000 per delivery year to fund the programs, and 
11    the plan shall determine the amount of funding to be 
12    apportioned to the programs identified in subsection (b) 
13    of Section 1-56 of this Act; provided that for the 
14    delivery years beginning June 1, 2021, June 1, 2022, and 
15    June 1, 2023, the long-term renewable resources 
16    procurement plan may average the annual budgets over a 
17    3-year period to account for program ramp-up. For the 
18    delivery years beginning June 1, 2021, June 1, 2024, June 
19    1, 2027, and June 1, 2030 and additional $10,000,000 shall 
20    be provided to the Department of Commerce and Economic 
21    Opportunity to implement the workforce development 
22    programs and reporting as outlined in Section 16-108.12 of 
23    the Public Utilities Act. In making the determinations 
24    required under this subparagraph (O), the Commission shall 
25    consider the experience and performance under the programs 
26    and any evaluation reports. The Commission shall also 
 
 
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1    provide for an independent evaluation of those programs on 
2    a periodic basis that are funded under this subparagraph 
3    (O).
4        (P) All programs and procurements under this 
5    subsection (c) shall be designed to encourage 
6    participating projects to use a diverse and equitable 
7    workforce and a diverse set of contractors, including 
8    minority-owned businesses, disadvantaged businesses, 
9    trade unions, graduates of any workforce training programs 
10    administered under this Act, and small businesses.
11        The Agency shall develop a method to optimize 
12    procurement of renewable energy credits from proposed 
13    utility-scale projects that are located in communities 
14    eligible to receive Energy Transition Community Grants 
15    pursuant to Section 10-20 of the Energy Community 
16    Reinvestment Act. If this requirement conflicts with other 
17    provisions of law or the Agency determines that full 
18    compliance with the requirements of this subparagraph (P) 
19    would be unreasonably costly or administratively 
20    impractical, the Agency is to propose alternative 
21    approaches to achieve development of renewable energy 
22    resources in communities eligible to receive Energy 
23    Transition Community Grants pursuant to Section 10-20 of 
24    the Energy Community Reinvestment Act or seek an exemption 
25    from this requirement from the Commission. 
26        (Q) Each facility listed in subitems (i) through (ix) 
 
 
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1    of item (1) of this subparagraph (Q) for which a renewable 
2    energy credit delivery contract is signed after the 
3    effective date of this amendatory Act of the 102nd General 
4    Assembly is subject to the following requirements through 
5    the Agency's long-term renewable resources procurement 
6    plan:
7            (1) Each facility shall be subject to the 
8        prevailing wage requirements included in the 
9        Prevailing Wage Act. The Agency shall require 
10        verification that all construction performed on the 
11        facility by the renewable energy credit delivery 
12        contract holder, its contractors, or its 
13        subcontractors relating to construction of the 
14        facility is performed by construction employees 
15        receiving an amount for that work equal to or greater 
16        than the general prevailing rate, as that term is 
17        defined in Section 2 3 of the Prevailing Wage Act. For 
18        purposes of this item (1), "house of worship" means 
19        property that is both (1) used exclusively by a 
20        religious society or body of persons as a place for 
21        religious exercise or religious worship and (2) 
22        recognized as exempt from taxation pursuant to Section 
23        15-40 of the Property Tax Code. This item (1) shall 
24        apply to any the following: 
25                (i) all new utility-scale wind projects;
26                (ii) all new utility-scale photovoltaic 
 
 
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1            projects and repowered wind projects;
2                (iii) all new brownfield photovoltaic 
3            projects;
4                (iv) all new photovoltaic community renewable 
5            energy facilities that qualify for item (iii) of 
6            subparagraph (K) of this paragraph (1);
7                (v) all new community driven community 
8            photovoltaic projects that qualify for item (v) of 
9            subparagraph (K) of this paragraph (1);
10                (vi) all new photovoltaic projects on public 
11            school land that qualify for item (iv) of 
12            subparagraph (K) of this paragraph (1);
13                (vii) all new photovoltaic distributed 
14            renewable energy generation devices that (1) 
15            qualify for item (i) of subparagraph (K) of this 
16            paragraph (1); (2) are not projects that serve 
17            single-family or multi-family residential 
18            buildings; and (3) are not houses of worship where 
19            the aggregate capacity including colocated    
20            collocated projects would not exceed 100 
21            kilowatts;
22                (viii) all new photovoltaic distributed 
23            renewable energy generation devices that (1) 
24            qualify for item (ii) of subparagraph (K) of this 
25            paragraph (1); (2) are not projects that serve 
26            single-family or multi-family residential 
 
 
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1            buildings; and (3) are not houses of worship where 
2            the aggregate capacity including colocated    
3            collocated projects would not exceed 100 
4            kilowatts;
5                (ix) all new, modernized, or retooled 
6            hydropower facilities. 
7            (2) Renewable energy credits procured from new 
8        utility-scale wind projects, new utility-scale solar 
9        projects, new brownfield solar projects, repowered 
10        wind projects, and retooled hydropower facilities 
11        pursuant to Agency procurement events occurring after 
12        the effective date of this amendatory Act of the 102nd 
13        General Assembly and photovoltaic community renewable 
14        distributed generation projects where the aggregate 
15        capacity, including colocated projects, exceeds 3,000 
16        kilowatts pursuant to Agency procurement events 
17        occurring after the effective date of this amendatory 
18        Act of the 104th General Assembly must be from 
19        facilities built by general contractors that must 
20        enter into a project labor agreement, as defined by 
21        this Act, prior to construction. The project labor 
22        agreement shall be filed with the Director in 
23        accordance with procedures established by the Agency 
24        through its long-term renewable resources procurement 
25        plan. Any information submitted to the Agency in this 
26        item (2) shall be considered commercially sensitive 
 
 
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1        information. At a minimum, the project labor agreement 
2        must provide the names, addresses, and occupations of 
3        the owner of the plant and the individuals 
4        representing the labor organization employees 
5        participating in the project labor agreement 
6        consistent with the Project Labor Agreements Act. The 
7        agreement must also specify the terms and conditions 
8        as defined by this Act.
9            (2.5) Energy storage credits procured from battery 
10        storage projects pursuant to Agency procurement events 
11        and additional energy storage resources procured in 
12        accordance with subparagraph (B) of paragraph (3) of 
13        subsection (d-20) of this Section pursuant to Agency 
14        procurement events occurring after the effective date 
15        of this amendatory Act of the 104th General Assembly 
16        must be from facilities built by general contractors 
17        that must enter into a project labor agreement prior 
18        to construction. The project labor agreement shall be 
19        filed with the Director in accordance with procedures 
20        established by the Agency through its long-term 
21        renewable resources procurement plan. Any information 
22        submitted to the Agency pursuant to this item (2.5) 
23        shall be considered commercially sensitive 
24        information. At a minimum, the project labor agreement 
25        must provide the names, addresses, and occupations of 
26        the owner of the plant and the individuals 
 
 
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1        representing the labor organization employees 
2        participating in the project labor agreement 
3        consistent with the Project Labor Agreements Act. The 
4        agreement must also specify the terms and conditions, 
5        as defined by this Act.    
6            (3) It is the intent of this Section to ensure that 
7        economic development occurs across Illinois 
8        communities, that emerging businesses may grow, and 
9        that there is improved access to the clean energy 
10        economy by persons who have greater economic burdens 
11        to success. The Agency shall take into consideration 
12        the unique cost of compliance of this subparagraph (Q) 
13        that might be borne by equity eligible contractors, 
14        shall include such costs when determining the price of 
15        renewable energy credits in the Adjustable Block 
16        program and the Geothermal Homes and Businesses 
17        Program, and shall take such costs into consideration 
18        in a nondiscriminatory manner when comparing bids for 
19        competitive procurements. The Agency shall consider 
20        costs associated with compliance whether in the 
21        development, financing, or construction of projects. 
22        The Agency shall periodically review the assumptions 
23        in these costs and may adjust prices, in compliance 
24        with subparagraph (M) of this paragraph (1).
25        (R) In its long-term renewable resources procurement 
26    plan, the Agency shall establish a self-direct renewable 
 
 
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1    portfolio standard compliance program for eligible 
2    self-direct customers that purchase renewable energy 
3    credits from utility-scale wind and solar projects through 
4    long-term agreements for purchase of renewable energy 
5    credits as described in this Section. Such long-term 
6    agreements may include the purchase of energy or other 
7    products on a physical or financial basis and may involve 
8    an alternative retail electric supplier as defined in 
9    Section 16-102 of the Public Utilities Act. This program 
10    shall take effect in the delivery year commencing June 1, 
11    2023.
12            (1) For the purposes of this subparagraph:
13            "Eligible self-direct customer" means any retail 
14        customers of an electric utility that serves 3,000,000 
15        or more retail customers in the State and whose total 
16        highest 30-minute demand was more than 10,000 
17        kilowatts, or any retail customers of an electric 
18        utility that serves less than 3,000,000 retail 
19        customers but more than 500,000 retail customers in 
20        the State and whose total highest 15-minute demand was 
21        more than 10,000 kilowatts.
22            "Retail customer" has the meaning set forth in 
23        Section 16-102 of the Public Utilities Act and 
24        multiple retail customer accounts under the same 
25        corporate parent may aggregate their account demands 
26        to meet the 10,000 kilowatt threshold. The criteria 
 
 
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1        for determining whether this subparagraph is 
2        applicable to a retail customer shall be based on the 
3        12 consecutive billing periods prior to the start of 
4        the year in which the application is filed.
5            (2) For renewable energy credits to count toward 
6        the self-direct renewable portfolio standard 
7        compliance program, they must:
8                (i) qualify as renewable energy credits as 
9            defined in Section 1-10 of this Act;
10                (ii) be sourced from one or more renewable 
11            energy generating facilities that comply with the 
12            geographic requirements as set forth in 
13            subparagraph (I) of paragraph (1) of subsection 
14            (c) as interpreted through the Agency's long-term 
15            renewable resources procurement plan, or, where 
16            applicable, the geographic requirements that 
17            governed utility-scale renewable energy credits at 
18            the time the eligible self-direct customer entered 
19            into the applicable renewable energy credit 
20            purchase agreement;
21                (iii) be procured through long-term contracts 
22            with term lengths of at least 10 years either 
23            directly with the renewable energy generating 
24            facility or through a bundled power purchase 
25            agreement, a virtual power purchase agreement, an 
26            agreement between the renewable generating 
 
 
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1            facility, an alternative retail electric supplier, 
2            and the customer, or such other structure as is 
3            permissible under this subparagraph (R);
4                (iv) be equivalent in volume to at least 40% 
5            of the eligible self-direct customer's usage, 
6            determined annually by the eligible self-direct 
7            customer's usage during the previous delivery 
8            year, measured to the nearest megawatt-hour;
9                (v) be retired by or on behalf of the large 
10            energy customer;
11                (vi) be sourced from new utility-scale wind 
12            projects or new utility-scale solar projects; and
13                (vii) if the contracts for renewable energy 
14            credits are entered into after the effective date 
15            of this amendatory Act of the 102nd General 
16            Assembly, the new utility-scale wind projects or 
17            new utility-scale solar projects must comply with 
18            the requirements established in subparagraphs (P) 
19            and (Q) of paragraph (1) of this subsection (c) 
20            and subsection (c-10).
21            (3) The self-direct renewable portfolio standard 
22        compliance program shall be designed to allow eligible 
23        self-direct customers to procure new renewable energy 
24        credits from new utility-scale wind projects or new 
25        utility-scale photovoltaic projects. The Agency shall 
26        annually determine the amount of utility-scale 
 
 
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1        renewable energy credits it will include each year 
2        from the self-direct renewable portfolio standard 
3        compliance program, subject to receiving qualifying 
4        applications. In making this determination, the Agency 
5        shall evaluate publicly available analyses and studies 
6        of the potential market size for utility-scale 
7        renewable energy long-term purchase agreements by 
8        commercial and industrial energy customers and make 
9        that report publicly available. If demand for 
10        participation in the self-direct renewable portfolio 
11        standard compliance program exceeds availability, the 
12        Agency shall ensure participation is evenly split 
13        between commercial and industrial users to the extent 
14        there is sufficient demand from both customer classes. 
15        Each renewable energy credit procured pursuant to this 
16        subparagraph (R) by a self-direct customer shall 
17        reduce the total volume of renewable energy credits 
18        the Agency is otherwise required to procure from new 
19        utility-scale projects pursuant to subparagraph (C) of 
20        paragraph (1) of this subsection (c) on behalf of 
21        contracting utilities where the eligible self-direct 
22        customer is located. The self-direct customer shall 
23        file an annual compliance report with the Agency 
24        pursuant to terms established by the Agency through 
25        its long-term renewable resources procurement plan to 
26        be eligible for participation in this program. 
 
 
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1        Customers must provide the Agency with their most 
2        recent electricity billing statements or other 
3        information deemed necessary by the Agency to 
4        demonstrate they are an eligible self-direct customer.
5            (4) The Commission shall approve a reduction in 
6        the volumetric charges collected pursuant to Section 
7        16-108 of the Public Utilities Act for approved 
8        eligible self-direct customers equivalent to the 
9        anticipated cost of renewable energy credit deliveries 
10        under contracts for new utility-scale wind and new 
11        utility-scale solar entered for each delivery year 
12        after the large energy customer begins retiring 
13        eligible new utility-scale utility scale renewable 
14        energy credits for self-compliance. The self-direct 
15        credit amount shall be determined annually and is 
16        equal to the estimated portion of the cost authorized 
17        by subparagraph (E) of paragraph (1) of this 
18        subsection (c) that supported the annual procurement 
19        of utility-scale renewable energy credits in the prior 
20        delivery year using a methodology described in the 
21        long-term renewable resources procurement plan, 
22        expressed on a per kilowatthour basis, and does not 
23        include (i) costs associated with any contracts 
24        entered into before the delivery year in which the 
25        customer files the initial compliance report to be 
26        eligible for participation in the self-direct program, 
 
 
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1        and (ii) costs associated with procuring renewable 
2        energy credits through existing and future contracts 
3        through the Adjustable Block Program, subsection (c-5) 
4        of this Section 1-75, and the Solar for All Program. 
5        The Agency shall assist the Commission in determining 
6        the current and future costs. The Agency must 
7        determine the self-direct credit amount for new and 
8        existing eligible self-direct customers and submit 
9        this to the Commission in an annual compliance filing. 
10        The Commission must approve the self-direct credit 
11        amount by June 1, 2023 and June 1 of each delivery year 
12        thereafter.
13            (5) Customers described in this subparagraph (R) 
14        shall apply, on a form developed by the Agency, to the 
15        Agency to be designated as a self-direct eligible 
16        customer. Once the Agency determines that a 
17        self-direct customer is eligible for participation in 
18        the program, the self-direct customer will remain 
19        eligible until the end of the term of the contract. 
20        Thereafter, application may be made not less than 12 
21        months before the filing date of the long-term 
22        renewable resources procurement plan described in this 
23        Act. At a minimum, such application shall contain the 
24        following:
25                (i) the customer's certification that, at the 
26            time of the customer's application, the customer 
 
 
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1            qualifies to be a self-direct eligible customer, 
2            including documents demonstrating that 
3            qualification;
4                (ii) the customer's certification that the 
5            customer has entered into or will enter into by 
6            the beginning of the applicable procurement year, 
7            one or more bilateral contracts for new wind 
8            projects or new photovoltaic projects, including 
9            supporting documentation;
10                (iii) certification that the contract or 
11            contracts for new renewable energy resources are 
12            long-term contracts with term lengths of at least 
13            10 years, including supporting documentation;
14                (iv) certification of the quantities of 
15            renewable energy credits that the customer will 
16            purchase each year under such contract or 
17            contracts, including supporting documentation;
18                (v) proof that the contract is sufficient to 
19            produce renewable energy credits to be equivalent 
20            in volume to at least 40% of the large energy 
21            customer's usage from the previous delivery year, 
22            measured to the nearest megawatt-hour; and
23                (vi) certification that the customer intends 
24            to maintain the contract for the duration of the 
25            length of the contract.
26            (6) If a customer receives the self-direct credit 
 
 
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1        but fails to properly procure and retire renewable 
2        energy credits as required under this subparagraph 
3        (R), the Commission, on petition from the Agency and 
4        after notice and hearing, may direct such customer's 
5        utility to recover the cost of the wrongfully received 
6        self-direct credits plus interest through an adder to 
7        charges assessed pursuant to Section 16-108 of the 
8        Public Utilities Act. Self-direct customers who 
9        knowingly fail to properly procure and retire 
10        renewable energy credits and do not notify the Agency 
11        are ineligible for continued participation in the 
12        self-direct renewable portfolio standard compliance 
13        program.
14        (S) Beginning with the long-term renewable resources 
15    procurement plan covering program and procurement activity 
16    for the delivery year beginning on June 1, 2028, any 
17    long-term renewable resources procurement plan developed 
18    by the Agency in accordance with subparagraph (A) of this 
19    paragraph (1) shall include a Geothermal Homes and 
20    Businesses Program for the procurement of geothermal 
21    renewable energy credits from new geothermal heating and 
22    cooling systems. The long-term renewable resources 
23    procurement plan shall allocate up to $10,000,000 per 
24    delivery year to fund the Program as described in this 
25    subparagraph (S). The Program shall be designed to 
26    stimulate the steady, predictable, and sustainable growth 
 
 
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1    of new geothermal heating and cooling system deployment in 
2    this State and meet gaps in the marketplace. To this end, 
3    the Geothermal Homes and Businesses Program shall provide 
4    a transparent annual schedule of prices and quantities to 
5    enable the geothermal heating and cooling market to scale 
6    up and renewable energy credit prices to adjust at a 
7    predictable rate over time. The prices set by the 
8    Geothermal Homes and Businesses Program may be reflected 
9    as a set value or as the product of a formula.
10                (i) The Geothermal Homes and Businesses Program 
11        shall allocate blocks of renewable energy credits as 
12        follows:
13                (1) The Agency may create categories for the 
14            Program based on structure features and use cases, 
15            including categories based on the nature and size 
16            of the Program's projects, customers, communities 
17            in which a project is located, and other 
18            attributes, defined at the discretion of the 
19            Agency through its long-term plan.    
20                (2) The Agency shall propose a single annual 
21            block for each Program delivery year for each 
22            category it creates through the delivery year 
23            beginning on June 1, 2035. The Program shall 
24            include the following for eligible projects for 
25            each delivery year: (I) a block of geothermal 
26            renewable energy credit volumes; (II) a price for 
 
 
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1            renewable energy credits from geothermal heating 
2            and cooling systems within the identified block; 
3            and (III) the terms and conditions for securing a 
4            spot on a waitlist once the block is fully 
5            committed or reserved. The Agency may periodically 
6            review its prior decisions establishing the amount 
7            of geothermal renewable energy credit volumes in 
8            each annual block and the purchase price for each 
9            block and may propose, on an expedited basis, 
10            changes to the previously set values, including, 
11            but not limited to, redistributing the amounts and 
12            the available funds as necessary and appropriate, 
13            subject to Commission approval. The Agency may 
14            define different block sizes, purchase prices, or 
15            other distinct terms and conditions for projects 
16            located in different utility service territories 
17            if the Agency deems it necessary.
18                (3) The Agency may develop an intra-year and 
19            year-to-year waitlist and block reservation policy 
20            that balances market certainty, program 
21            availability, and expedient project deployment.
22                (4) For the program year beginning on June 1, 
23            2028, at least 33% of each annual block shall be 
24            available to be reserved for systems that are 
25            residential, as defined by the Agency. The Agency 
26            shall endeavor to ensure at least 40% of each 
 
 
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1            annual block is available to be reserved by 
2            systems located in Equity Investment Eligible 
3            Communities. At least 10% of all annual blocks 
4            shall be available to be reserved by systems from 
5            applicants that are equity eligible contractors, 
6            and the Agency shall propose to increase the 
7            percentage of systems from applicants that are 
8            equity eligible contractors over time to 40% based 
9            on factors that include, but are not limited to, 
10            the number of equity eligible contractors and the 
11            volume used under this clause (4) in previous 
12            delivery years. For long-term renewable resources 
13            procurement plans developed thereafter, the Agency 
14            may propose adjustments to the minimum percentages 
15            based on developer interest, market interest and 
16            availability, and other factors.
17                (5) The Agency shall establish Program 
18            eligibility requirements that ensure that systems 
19            that enter the Program are sufficiently mature 
20            enough to indicate a demonstrable path to 
21            completion and other terms, conditions, and 
22            requirements for the program, including vendor 
23            registration and approval, sales and marketing 
24            requirements, and other consumer protection 
25            requirements as the Agency deems necessary.
26                (6) The Program shall be designed to ensure 
 
 
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1            that geothermal renewable energy credits are 
2            procured from projects in diverse locations and 
3            are not procured from projects that are 
4            concentrated in a few regional areas.
5                (7) The Agency, through its long-term 
6            renewable resources procurement plan, may 
7            implement solutions to maintain stable and 
8            consistent REC offerings to avoid gaps in 
9            availability during a delivery year, including, 
10            but not limited to, creating a floating block of 
11            REC capacity in a given delivery year.
12            (ii) Energy derived from a geothermal heating and 
13        cooling system shall be eligible for inclusion in 
14        meeting the requirements of the Program. Eligible 
15        renewable energy credits from geothermal heating and 
16        cooling systems shall be created by calculating the 
17        difference between the energy load used by the 
18        geothermal heating and cooling system and the energy 
19        load used by a less efficient baseline system for the 
20        equivalent space heating and cooling or water heating 
21        load required by the building. Geothermal renewable 
22        energy credits shall be expressed in megawatt-hour 
23        units. To make this calculation, the Agency (1) shall 
24        identify an appropriate formula supported by a 
25        geothermal industry trade organization, a national 
26        laboratory, or another data-backed and verifiable 
 
 
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1        methodology, (2) may propose adjustments to any 
2        formulas for its proposed renewable energy credit 
3        calculation methodology, and (3) may reflect 
4        calculation methodologies already in use for other 
5        State renewable portfolio standards, if applicable and 
6        appropriate. The Agency shall determine the form and 
7        manner in which the renewable energy credits are 
8        verified and retired, in accordance with national best 
9        practices.
10            Geothermal renewable energy credits retired by 
11        obligated utilities for compliance with the Program 
12        are only valid for compliance if those geothermal 
13        renewable energy credits have not been previously 
14        retired by another entity that is not the obligated 
15        utility on any tracking system, carbon registry, or 
16        other accounting mechanism at any time. Additionally, 
17        geothermal renewable energy credits retired by 
18        obligated utilities for compliance with the Program 
19        shall only be valid for compliance if those geothermal 
20        renewable energy credits have not been used to 
21        substantiate a public emissions or energy usage claim 
22        by any other another entity that is not the obligated 
23        utility, of any type and at any time, whether or not 
24        the geothermal renewable energy credits were actually 
25        retired on a tracking system, registry, or other 
26        accounting mechanism at the time of the public 
 
 
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1        emissions-based claim. Geothermal renewable energy 
2        credits generated for compliance with the Program 
3        shall be valid only if retired once, and claimed once, 
4        by the obligated utility.
5            In order to promote the competitive development of 
6        geothermal heating and cooling systems in furtherance 
7        of this State's interest in the health, safety, and 
8        welfare of its residents, renewable energy credits 
9        from geothermal heating and cooling systems shall not 
10        be eligible for purchase and retirement under this Act 
11        if the credits are sourced from a geothermal heating 
12        and cooling system for which costs are being recovered 
13        on or after the effective date of this amendatory Act 
14        of the 104th General Assembly through rates regulated 
15        by this State or any other state.
16            (iii) The Agency shall establish Program 
17        requirements and minimum contract terms to ensure that 
18        projects are properly installed and that projects 
19        operate to the level of expected benefits. The 
20        contract terms shall include, but are not limited to, 
21        the following:
22                (1) The capital that is not advanced shall be 
23            disbursed upon the delivery of renewable energy 
24            credits from geothermal heating and cooling 
25            systems as per contract fulfillment over the 
26            delivery term, not to exceed, during each delivery 
 
 
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1            year, the contract price multiplied by the 
2            estimated annual renewable energy credit 
3            generation amount.
4                (2) For renewable energy credits that qualify 
5            and are procured under the Program, the delivery 
6            contract length shall be 15 years.
7                (3) If generation of renewable energy credits 
8            from geothermal heating and cooling systems during 
9            a delivery year exceeds the estimated annual 
10            generation amount, the excess of such renewable 
11            energy credits shall be carried forward to future 
12            delivery years and shall not expire during the 
13            delivery term. If the renewable energy credit 
14            generation during a delivery year, including any 
15            carried forward excess renewable energy credits, 
16            is less than the estimated annual generation 
17            amount, payments during the delivery year shall 
18            not exceed the quantity generated plus the 
19            quantity carried forward multiplied by the 
20            contract price. The electric utility shall receive 
21            all renewable energy credits generated by the 
22            project during the first 15 years of operation, 
23            and retire all renewable energy credits paid for 
24            under this clause (3) and return at the end of the 
25            delivery term all geothermal renewable energy 
26            credits that were not paid for. Renewable energy 
 
 
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1            credits generated by the project thereafter shall 
2            not be transferred under the renewable energy 
3            credit delivery contract with the counterparty 
4            electric utility.
5                (4) For renewable energy contracts for any 
6            type of community, shared, or similar geothermal 
7            heating and cooling system that operates using a 
8            subscription model and for which subscriptions are 
9            a basis for contractual payments, subscription of 
10            90% of total renewable energy credit volumes or 
11            greater shall be deemed to be fully subscribed.
12                (5) Beginning with the long-term renewable 
13            resources procurement plan covering the delivery 
14            year beginning on June 1, 2030, the Agency may 
15            propose a payment structure for Program contracts 
16            upon a demonstration of qualification or need 
17            under criteria established by the Agency that is 
18            focused on supporting the small and emerging 
19            businesses and the businesses that most acutely 
20            face barriers to capital access. Successful 
21            applicant firms shall have advanced capital 
22            disbursed before renewable energy credits are 
23            first generated. The maximum amount or percentage 
24            of capital advanced shall be included in the 
25            long-term renewable resources procurement plan, 
26            and any amount actually advanced shall be designed 
 
 
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1            to overcome the barriers in access to capital that 
2            are faced by an applicant through that applicant's 
3            demonstration of need. The amount or percentage of 
4            advanced capital may vary by year, or inter-year, 
5            by structure category, block, and other factors as 
6            deemed applicable by the Agency and by an 
7            applicant's demonstration of need. Contracts 
8            featuring capital advanced prior to system 
9            operation shall feature provisions to ensure both 
10            the successful development of applicant projects 
11            and the delivery of renewable energy credits for 
12            the full term of the contract, including ongoing 
13            collateral requirements and other provisions 
14            deemed necessary by the Agency. The percentage or 
15            amount of capital advanced prior to system 
16            operation shall not increase the overall contract 
17            value.
18                (6) Each contract shall include provisions to 
19            ensure the delivery of the estimated quantity of 
20            geothermal renewable energy credits, including a 
21            requirement of performance assurance in an amount 
22            deemed appropriate by the Agency.
23                (7) An obligated utility shall be the 
24            counterparty to the contracts executed under this 
25            subparagraph (S) that are approved by the 
26            Commission. No contract shall be executed for an 
 
 
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1            amount that is less than one geothermal renewable 
2            energy credit per year.
3                (8) Nothing in this subparagraph (S) shall 
4            require the utility to advance any payment or pay 
5            any amounts that exceed the actual amount of 
6            revenues anticipated to be collected by the 
7            utility inclusive of eligible funds collected in 
8            prior years and alternative compliance payments 
9            for use by the utility.
10                (9) Contracts may be assignable, but only to 
11            entities first deemed by the Agency to have met 
12            Program terms and requirements applicable to 
13            direct Program participation. In developing 
14            contracts for the delivery of renewable energy 
15            credits from geothermal heating and cooling 
16            systems, the Agency may establish fees applicable 
17            to each contract assignment.
18                (10) If, at any time, approved applications 
19            for the Program exceed funds collected by the 
20            electric utility or would cause the Agency to 
21            exceed the limitation on the amount of renewable 
22            energy resources that may be procured, then the 
23            Agency may consider future uncommitted funds to be 
24            reserved for these contracts on a first-come, 
25            first-served basis.
26            (iv) In order to advance priority access to the 
 
 
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1        clean energy economy for businesses and workers from 
2        communities that have been excluded from economic 
3        opportunities in the energy sector, been subject to 
4        disproportionate levels of pollution, and 
5        disproportionately experienced negative public health 
6        outcomes, the Agency shall apply its equity 
7        accountability system and minimum equity standards 
8        established under subsections (c-10), (c-15), (c-20), 
9        (c-25), and (c-30) to geothermal heating and cooling 
10        system renewable energy credit procurement and 
11        programs and may include any proposed modifications to 
12        the equity accountability system and minimum equity 
13        standards that may be warranted with respect to 
14        geothermal heating and cooling systems in its plan 
15        submission to the Commission under Section 16-111.5 of 
16        the Public Utilities Act.
17            (v) Projects shall be developed in compliance with 
18        the prevailing wage and project labor agreement 
19        requirements, as applicable, for renewable energy 
20        projects in subparagraph (Q) of paragraph (1) of 
21        subsection (c). Renewable energy credits for any 
22        single geothermal heating and cooling project that is 
23        142 tons or larger and is procured under this Program 
24        after the effective date of this amendatory Act of the 
25        104th General Assembly shall only be eligible if the 
26        associated project was built by general contractors 
 
 
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1        who entered into a project labor agreement prior to 
2        construction. The project labor agreement shall be 
3        filed with the Director in accordance with procedures 
4        established by the Agency through its long-term 
5        renewable resources procurement plan. The project 
6        labor agreement shall provide the names, addresses, 
7        and occupations of the owner of the plant and the 
8        individuals representing the labor organization 
9        employees that participate in the project labor 
10        agreement. The project labor agreement shall also 
11        specify terms and conditions as provided in this Act.
12            (vi) The Agency shall strive to minimize 
13        administrative expenses in the implementation of the 
14        Program. The Agency may use any existing program 
15        administrator and any applicable subcontractors to 
16        develop, administer, implement, operate, and evaluate 
17        the Program.    
18        (T) Renewable energy credits procured under Agency 
19    procurements or programs for community solar projects with 
20    more than 3 megawatts in nameplate capacity must be 
21    procured from facilities built by general contractors 
22    that, prior to construction, enter into a project labor 
23    agreement, as defined by this Act, subject to the 
24    following requirements and limitations:
25            (i) The project labor agreement shall be filed 
26        with the Director in accordance with procedures 
 
 
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1        established by the Agency through its long-term 
2        renewable resources procurement plan. Any information 
3        submitted to the Agency under this item (i) shall be 
4        considered commercially sensitive information.
5            (ii) At a minimum, the project labor agreement 
6        must provide the names, addresses, and occupations of 
7        the owner of the project and any individuals 
8        representing the labor organization of the employees 
9        participating in the project labor agreement 
10        consistent with the Project Labor Agreements Act. The 
11        project labor agreement must also meet the terms and 
12        conditions, as set forth in this Act.
13            (iii) It is the intent of this Section to ensure 
14        that economic development occurs across communities in 
15        this State, that emerging businesses may grow, and 
16        that there is improved access to the clean energy 
17        economy by persons who have greater economic burdens 
18        to success. The Agency shall take into consideration 
19        the unique cost of compliance of this subparagraph (T) 
20        that may be borne by equity eligible contractors and 
21        shall include those costs when determining the price 
22        of renewable energy credits in the Adjustable Block 
23        program. The Agency shall consider costs associated 
24        with compliance, including in the development, 
25        financing, or construction of projects. The Agency 
26        shall periodically review the assumptions in these 
 
 
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1        costs and may adjust prices in compliance with 
2        subparagraph (M) of this paragraph (1).    
3        (2) (Blank).
4        (3) (Blank). 
5        (4) The electric utility shall retire all renewable 
6    energy credits used to comply with the standard.
7        (5) Beginning with the 2010 delivery year and ending 
8    June 1, 2017, an electric utility subject to this 
9    subsection (c) shall apply the lesser of the maximum 
10    alternative compliance payment rate or the most recent 
11    estimated alternative compliance payment rate for its 
12    service territory for the corresponding compliance period, 
13    established pursuant to subsection (d) of Section 16-115D 
14    of the Public Utilities Act to its retail customers that 
15    take service pursuant to the electric utility's hourly 
16    pricing tariff or tariffs. The electric utility shall 
17    retain all amounts collected as a result of the 
18    application of the alternative compliance payment rate or 
19    rates to such customers, and, beginning in 2011, the 
20    utility shall include in the information provided under 
21    item (1) of subsection (d) of Section 16-111.5 of the 
22    Public Utilities Act the amounts collected under the 
23    alternative compliance payment rate or rates for the prior 
24    year ending May 31. Notwithstanding any limitation on the 
25    procurement of renewable energy resources imposed by item 
26    (2) of this subsection (c), the Agency shall increase its 
 
 
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1    spending on the purchase of renewable energy resources to 
2    be procured by the electric utility for the next plan year 
3    by an amount equal to the amounts collected by the utility 
4    under the alternative compliance payment rate or rates in 
5    the prior year ending May 31.
6        (6) The electric utility shall be entitled to recover 
7    all of its costs associated with the procurement of 
8    renewable energy credits under plans approved under this 
9    Section and Section 16-111.5 of the Public Utilities Act. 
10    These costs shall include associated reasonable expenses 
11    for implementing the procurement programs, including, but 
12    not limited to, the costs of administering and evaluating 
13    the Adjustable Block program and the Geothermal Homes and 
14    Businesses Program, through an automatic adjustment clause 
15    tariff in accordance with subsection (k) of Section 16-108 
16    of the Public Utilities Act.
17        (7) Renewable energy credits procured from new 
18    photovoltaic projects or new distributed renewable energy 
19    generation devices under this Section after June 1, 2017 
20    (the effective date of Public Act 99-906) must be procured 
21    from devices installed by a qualified person in compliance 
22    with the requirements of Section 16-128A of the Public 
23    Utilities Act and any rules or regulations adopted 
24    thereunder.
25        In meeting the renewable energy requirements of this 
26    subsection (c), to the extent feasible and consistent with 
 
 
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1    State and federal law, the renewable energy credit 
2    procurements, Adjustable Block solar program, and 
3    community renewable generation program shall provide 
4    employment opportunities for all segments of the 
5    population and workforce, including minority-owned and 
6    female-owned business enterprises, and shall not, 
7    consistent with State and federal law, discriminate based 
8    on race or socioeconomic status.
9    (c-5) Procurement of renewable energy credits from new 
10renewable energy facilities installed at or adjacent to the 
11sites of electric generating facilities that burn or burned 
12coal as their primary fuel source.
13        (1) In addition to the procurement of renewable energy 
14    credits pursuant to long-term renewable resources 
15    procurement plans in accordance with subsection (c) of 
16    this Section and Section 16-111.5 of the Public Utilities 
17    Act, the Agency shall conduct procurement events in 
18    accordance with this subsection (c-5) for the procurement 
19    by electric utilities that served more than 300,000 retail 
20    customers in this State as of January 1, 2019 of renewable 
21    energy credits from new renewable energy facilities to be 
22    installed at or adjacent to the sites of electric 
23    generating facilities that, as of January 1, 2016, burned 
24    coal as their primary fuel source and meet the other 
25    criteria specified in this subsection (c-5). For purposes 
26    of this subsection (c-5), "new renewable energy facility" 
 
 
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1    means a new utility-scale solar project as defined in this 
2    Section 1-75. The renewable energy credits procured 
3    pursuant to this subsection (c-5) may be included or 
4    counted for purposes of compliance with the amounts of 
5    renewable energy credits required to be procured pursuant 
6    to subsection (c) of this Section to the extent that there 
7    are otherwise shortfalls in compliance with such 
8    requirements. The procurement of renewable energy credits 
9    by electric utilities pursuant to this subsection (c-5) 
10    shall be funded solely by revenues collected from the Coal 
11    to Solar and Energy Storage Initiative Charge provided for 
12    in this subsection (c-5) and subsection (i-5) of Section 
13    16-108 of the Public Utilities Act, shall not be funded by 
14    revenues collected through any of the other funding 
15    mechanisms provided for in subsection (c) of this Section, 
16    and shall not be subject to the limitation imposed by 
17    subsection (c) on charges to retail customers for costs to 
18    procure renewable energy resources pursuant to subsection 
19    (c), and shall not be subject to any other requirements or 
20    limitations of subsection (c).
21        (2) The Agency shall conduct 2 procurement events to 
22    select owners of electric generating facilities meeting 
23    the eligibility criteria specified in this subsection 
24    (c-5) to enter into long-term contracts to sell renewable 
25    energy credits to electric utilities serving more than 
26    300,000 retail customers in this State as of January 1, 
 
 
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1    2019. The first procurement event shall be conducted no 
2    later than March 31, 2022, unless the Agency elects to 
3    delay it, until no later than May 1, 2022, due to its 
4    overall volume of work, and shall be to select owners of 
5    electric generating facilities located in this State and 
6    south of federal Interstate Highway 80 that meet the 
7    eligibility criteria specified in this subsection (c-5). 
8    The second procurement event shall be conducted no sooner 
9    than September 30, 2022 and no later than October 31, 2022 
10    and shall be to select owners of electric generating 
11    facilities located anywhere in this State that meet the 
12    eligibility criteria specified in this subsection (c-5). 
13    The Agency shall establish and announce a time period, 
14    which shall begin no later than 30 days prior to the 
15    scheduled date for the procurement event, during which 
16    applicants may submit applications to be selected as 
17    suppliers of renewable energy credits pursuant to this 
18    subsection (c-5). The eligibility criteria for selection 
19    as a supplier of renewable energy credits pursuant to this 
20    subsection (c-5) shall be as follows:
21            (A) The applicant owns an electric generating 
22        facility located in this State that: (i) as of January 
23        1, 2016, burned coal as its primary fuel to generate 
24        electricity; and (ii) has, or had prior to retirement, 
25        an electric generating capacity of at least 150 
26        megawatts. The electric generating facility can be 
 
 
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1        either: (i) retired as of the date of the procurement 
2        event; or (ii) still operating as of the date of the 
3        procurement event.
4            (B) The applicant is not (i) an electric 
5        cooperative as defined in Section 3-119 of the Public 
6        Utilities Act, or (ii) an entity described in 
7        subsection (b)(1) of Section 3-105 of the Public 
8        Utilities Act, or an association or consortium of or 
9        an entity owned by entities described in (i) or (ii); 
10        and the coal-fueled electric generating facility was 
11        at one time owned, in whole or in part, by a public 
12        utility as defined in Section 3-105 of the Public 
13        Utilities Act.
14            (C) If participating in the first procurement 
15        event, the applicant proposes and commits to construct 
16        and operate, at the site, and if necessary for 
17        sufficient space on property adjacent to the existing 
18        property, at which the electric generating facility 
19        identified in paragraph (A) is located: (i) a new 
20        renewable energy facility of at least 20 megawatts but 
21        no more than 100 megawatts of electric generating 
22        capacity, and (ii) an energy storage facility having a 
23        storage capacity equal to at least 2 megawatts and at 
24        most 10 megawatts. If participating in the second 
25        procurement event, the applicant proposes and commits 
26        to construct and operate, at the site, and if 
 
 
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1        necessary for sufficient space on property adjacent to 
2        the existing property, at which the electric 
3        generating facility identified in paragraph (A) is 
4        located: (i) a new renewable energy facility of at 
5        least 5 megawatts but no more than 20 megawatts of 
6        electric generating capacity, and (ii) an energy 
7        storage facility having a storage capacity equal to at 
8        least 0.5 megawatts and at most one megawatt.
9            (D) The applicant agrees that the new renewable 
10        energy facility and the energy storage facility will 
11        be constructed or installed by a qualified entity or 
12        entities in compliance with the requirements of 
13        subsection (g) of Section 16-128A of the Public 
14        Utilities Act and any rules adopted thereunder.
15            (E) The applicant agrees that personnel operating 
16        the new renewable energy facility and the energy 
17        storage facility will have the requisite skills, 
18        knowledge, training, experience, and competence, which 
19        may be demonstrated by completion or current 
20        participation and ultimate completion by employees of 
21        an accredited or otherwise recognized apprenticeship 
22        program for the employee's particular craft, trade, or 
23        skill, including through training and education 
24        courses and opportunities offered by the owner to 
25        employees of the coal-fueled electric generating 
26        facility or by previous employment experience 
 
 
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1        performing the employee's particular work skill or 
2        function.
3            (F) The applicant commits that not less than the 
4        prevailing wage, as determined pursuant to the 
5        Prevailing Wage Act, will be paid to the applicant's 
6        employees engaged in construction activities 
7        associated with the new renewable energy facility and 
8        the new energy storage facility and to the employees 
9        of applicant's contractors engaged in construction 
10        activities associated with the new renewable energy 
11        facility and the new energy storage facility, and 
12        that, on or before the commercial operation date of 
13        the new renewable energy facility, the applicant shall 
14        file a report with the Agency certifying that the 
15        requirements of this subparagraph (F) have been met.
16            (G) The applicant commits that if selected, it 
17        will negotiate a project labor agreement for the 
18        construction of the new renewable energy facility and 
19        associated energy storage facility that includes 
20        provisions requiring the parties to the agreement to 
21        work together to establish diversity threshold 
22        requirements and to ensure best efforts to meet 
23        diversity targets, improve diversity at the applicable 
24        job site, create diverse apprenticeship opportunities, 
25        and create opportunities to employ former coal-fired 
26        power plant workers.
 
 
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1            (H) The applicant commits to enter into a contract 
2        or contracts for the applicable duration to provide 
3        specified numbers of renewable energy credits each 
4        year from the new renewable energy facility to 
5        electric utilities that served more than 300,000 
6        retail customers in this State as of January 1, 2019, 
7        at a price of $30 per renewable energy credit. The 
8        price per renewable energy credit shall be fixed at 
9        $30 for the applicable duration and the renewable 
10        energy credits shall not be indexed renewable energy 
11        credits as provided for in item (v) of subparagraph 
12        (G) of paragraph (1) of subsection (c) of Section 1-75 
13        of this Act. The applicable duration of each contract 
14        shall be 20 years, unless the applicant is physically 
15        interconnected to the PJM Interconnection, LLC 
16        transmission grid and had a generating capacity of at 
17        least 1,200 megawatts as of January 1, 2021, in which 
18        case the applicable duration of the contract shall be 
19        15 years.
20            (I) The applicant's application is certified by an 
21        officer of the applicant and by an officer of the 
22        applicant's ultimate parent company, if any.
23        (3) An applicant may submit applications to contract 
24    to supply renewable energy credits from more than one new 
25    renewable energy facility to be constructed at or adjacent 
26    to one or more qualifying electric generating facilities 
 
 
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1    owned by the applicant. The Agency may select new 
2    renewable energy facilities to be located at or adjacent 
3    to the sites of more than one qualifying electric 
4    generation facility owned by an applicant to contract with 
5    electric utilities to supply renewable energy credits from 
6    such facilities.
7        (4) The Agency shall assess fees to each applicant to 
8    recover the Agency's costs incurred in receiving and 
9    evaluating applications, conducting the procurement event, 
10    developing contracts for sale, delivery and purchase of 
11    renewable energy credits, and monitoring the 
12    administration of such contracts, as provided for in this 
13    subsection (c-5), including fees paid to a procurement 
14    administrator retained by the Agency for one or more of 
15    these purposes.
16        (5) The Agency shall select the applicants and the new 
17    renewable energy facilities to contract with electric 
18    utilities to supply renewable energy credits in accordance 
19    with this subsection (c-5). In the first procurement 
20    event, the Agency shall select applicants and new 
21    renewable energy facilities to supply renewable energy 
22    credits, at a price of $30 per renewable energy credit, 
23    aggregating to no less than 400,000 renewable energy 
24    credits per year for the applicable duration, assuming 
25    sufficient qualifying applications to supply, in the 
26    aggregate, at least that amount of renewable energy 
 
 
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1    credits per year; and not more than 580,000 renewable 
2    energy credits per year for the applicable duration. In 
3    the second procurement event, the Agency shall select 
4    applicants and new renewable energy facilities to supply 
5    renewable energy credits, at a price of $30 per renewable 
6    energy credit, aggregating to no more than 625,000 
7    renewable energy credits per year less the amount of 
8    renewable energy credits each year contracted for as a 
9    result of the first procurement event, for the applicable 
10    durations. The number of renewable energy credits to be 
11    procured as specified in this paragraph (5) shall not be 
12    reduced based on renewable energy credits procured in the 
13    self-direct renewable energy credit compliance program 
14    established pursuant to subparagraph (R) of paragraph (1) 
15    of subsection (c) of Section 1-75.
16        (6) The obligation to purchase renewable energy 
17    credits from the applicants and their new renewable energy 
18    facilities selected by the Agency shall be allocated to 
19    the electric utilities based on their respective 
20    percentages of kilowatthours delivered to delivery 
21    services customers to the aggregate kilowatthour 
22    deliveries by the electric utilities to delivery services 
23    customers for the year ended December 31, 2021. In order 
24    to achieve these allocation percentages between or among 
25    the electric utilities, the Agency shall require each 
26    applicant that is selected in the procurement event to 
 
 
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1    enter into a contract with each electric utility for the 
2    sale and purchase of renewable energy credits from each 
3    new renewable energy facility to be constructed and 
4    operated by the applicant, with the sale and purchase 
5    obligations under the contracts to aggregate to the total 
6    number of renewable energy credits per year to be supplied 
7    by the applicant from the new renewable energy facility.
8        (7) The Agency shall submit its proposed selection of 
9    applicants, new renewable energy facilities to be 
10    constructed, and renewable energy credit amounts for each 
11    procurement event to the Commission for approval. The 
12    Commission shall, within 2 business days after receipt of 
13    the Agency's proposed selections, approve the proposed 
14    selections if it determines that the applicants and the 
15    new renewable energy facilities to be constructed meet the 
16    selection criteria set forth in this subsection (c-5) and 
17    that the Agency seeks approval for contracts of applicable 
18    durations aggregating to no more than the maximum amount 
19    of renewable energy credits per year authorized by this 
20    subsection (c-5) for the procurement event, at a price of 
21    $30 per renewable energy credit.
22        (8) The Agency, in conjunction with its procurement 
23    administrator if one is retained, the electric utilities, 
24    and potential applicants for contracts to produce and 
25    supply renewable energy credits pursuant to this 
26    subsection (c-5), shall develop a standard form contract 
 
 
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1    for the sale, delivery and purchase of renewable energy 
2    credits pursuant to this subsection (c-5). Each contract 
3    resulting from the first procurement event shall allow for 
4    a commercial operation date for the new renewable energy 
5    facility of either June 1, 2023 or June 1, 2024, with such 
6    dates subject to adjustment as provided in this paragraph. 
7    Each contract resulting from the second procurement event 
8    shall provide for a commercial operation date on June 1 
9    next occurring up to 48 months after execution of the 
10    contract. Each contract shall provide that the owner shall 
11    receive payments for renewable energy credits for the 
12    applicable durations beginning with the commercial 
13    operation date of the new renewable energy facility. The 
14    form contract shall provide for adjustments to the 
15    commercial operation and payment start dates as needed due 
16    to any delays in completing the procurement and 
17    contracting processes, in finalizing interconnection 
18    agreements and installing interconnection facilities, and 
19    in obtaining other necessary governmental permits and 
20    approvals. The form contract shall be, to the maximum 
21    extent possible, consistent with standard electric 
22    industry contracts for sale, delivery, and purchase of 
23    renewable energy credits while taking into account the 
24    specific requirements of this subsection (c-5). The form 
25    contract shall provide for over-delivery and 
26    under-delivery of renewable energy credits within 
 
 
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1    reasonable ranges during each 12-month period and penalty, 
2    default, and enforcement provisions for failure of the 
3    selling party to deliver renewable energy credits as 
4    specified in the contract and to comply with the 
5    requirements of this subsection (c-5). The standard form 
6    contract shall specify that all renewable energy credits 
7    delivered to the electric utility pursuant to the contract 
8    shall be retired. The Agency shall make the proposed 
9    contracts available for a reasonable period for comment by 
10    potential applicants, and shall publish the final form 
11    contract at least 30 days before the date of the first 
12    procurement event.
13        (9) Coal to Solar and Energy Storage Initiative 
14    Charge.
15            (A) By no later than July 1, 2022, each electric 
16        utility that served more than 300,000 retail customers 
17        in this State as of January 1, 2019 shall file a tariff 
18        with the Commission for the billing and collection of 
19        a Coal to Solar and Energy Storage Initiative Charge 
20        in accordance with subsection (i-5) of Section 16-108 
21        of the Public Utilities Act, with such tariff to be 
22        effective, following review and approval or 
23        modification by the Commission, beginning January 1, 
24        2023. The tariff shall provide for the calculation and 
25        setting of the electric utility's Coal to Solar and 
26        Energy Storage Initiative Charge to collect revenues 
 
 
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1        estimated to be sufficient, in the aggregate, (i) to 
2        enable the electric utility to pay for the renewable 
3        energy credits it has contracted to purchase in the 
4        delivery year beginning June 1, 2023 and each delivery 
5        year thereafter from new renewable energy facilities 
6        located at the sites of qualifying electric generating 
7        facilities, and (ii) to fund the grant payments to be 
8        made in each delivery year by the Department of 
9        Commerce and Economic Opportunity, or any successor 
10        department or agency, which shall be referred to in 
11        this subsection (c-5) as the Department, pursuant to 
12        paragraph (10) of this subsection (c-5). The electric 
13        utility's tariff shall provide for the billing and 
14        collection of the Coal to Solar and Energy Storage 
15        Initiative Charge on each kilowatthour of electricity 
16        delivered to its delivery services customers within 
17        its service territory and shall provide for an annual 
18        reconciliation of revenues collected with actual 
19        costs, in accordance with subsection (i-5) of Section 
20        16-108 of the Public Utilities Act.
21            (B) Each electric utility shall remit on a monthly 
22        basis to the State Treasurer, for deposit in the Coal 
23        to Solar and Energy Storage Initiative Fund provided 
24        for in this subsection (c-5), the electric utility's 
25        collections of the Coal to Solar and Energy Storage 
26        Initiative Charge in the amount estimated to be needed 
 
 
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1        by the Department for grant payments pursuant to grant 
2        contracts entered into by the Department pursuant to 
3        paragraph (10) of this subsection (c-5).
4        (10) Coal to Solar and Energy Storage Initiative Fund.
5            (A) The Coal to Solar and Energy Storage 
6        Initiative Fund is established as a special fund in 
7        the State treasury. The Coal to Solar and Energy 
8        Storage Initiative Fund is authorized to receive, by 
9        statutory deposit, that portion specified in item (B) 
10        of paragraph (9) of this subsection (c-5) of moneys 
11        collected by electric utilities through imposition of 
12        the Coal to Solar and Energy Storage Initiative Charge 
13        required by this subsection (c-5). The Coal to Solar 
14        and Energy Storage Initiative Fund shall be 
15        administered by the Department to provide grants to 
16        support the installation and operation of energy 
17        storage facilities at the sites of qualifying electric 
18        generating facilities meeting the criteria specified 
19        in this paragraph (10).
20            (B) The Coal to Solar and Energy Storage 
21        Initiative Fund shall not be subject to sweeps, 
22        administrative charges, or chargebacks, including, but 
23        not limited to, those authorized under Section 8h of 
24        the State Finance Act, that would in any way result in 
25        the transfer of those funds from the Coal to Solar and 
26        Energy Storage Initiative Fund to any other fund of 
 
 
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1        this State or in having any such funds utilized for any 
2        purpose other than the express purposes set forth in 
3        this paragraph (10).
4            (C) The Department shall utilize up to 
5        $280,500,000 in the Coal to Solar and Energy Storage 
6        Initiative Fund for grants, assuming sufficient 
7        qualifying applicants, to support installation of 
8        energy storage facilities at the sites of up to 3 
9        qualifying electric generating facilities located in 
10        the Midcontinent Independent System Operator, Inc., 
11        region in Illinois and the sites of up to 2 qualifying 
12        electric generating facilities located in the PJM 
13        Interconnection, LLC region in Illinois that meet the 
14        criteria set forth in this subparagraph (C). The 
15        criteria for receipt of a grant pursuant to this 
16        subparagraph (C) are as follows:
17                (1) the electric generating facility at the 
18            site has, or had prior to retirement, an electric 
19            generating capacity of at least 150 megawatts;
20                (2) the electric generating facility burns (or 
21            burned prior to retirement) coal as its primary 
22            source of fuel;
23                (3) if the electric generating facility is 
24            retired, it was retired subsequent to January 1, 
25            2016;
26                (4) the owner of the electric generating 
 
 
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1            facility has not been selected by the Agency 
2            pursuant to this subsection (c-5) of this Section 
3            to enter into a contract to sell renewable energy 
4            credits to one or more electric utilities from a 
5            new renewable energy facility located or to be 
6            located at or adjacent to the site at which the 
7            electric generating facility is located;
8                (5) the electric generating facility located 
9            at the site was at one time owned, in whole or in 
10            part, by a public utility as defined in Section 
11            3-105 of the Public Utilities Act;
12                (6) the electric generating facility at the 
13            site is not owned by (i) an electric cooperative 
14            as defined in Section 3-119 of the Public 
15            Utilities Act, or (ii) an entity described in 
16            subsection (b)(1) of Section 3-105 of the Public 
17            Utilities Act, or an association or consortium of 
18            or an entity owned by entities described in items 
19            (i) or (ii);
20                (7) the proposed energy storage facility at 
21            the site will have energy storage capacity of at 
22            least 37 megawatts;
23                (8) the owner commits to place the energy 
24            storage facility into commercial operation on 
25            either June 1, 2023, June 1, 2024, or June 1, 2025, 
26            with such date subject to adjustment as needed due 
 
 
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1            to any delays in completing the grant contracting 
2            process, in finalizing interconnection agreements 
3            and in installing interconnection facilities, and 
4            in obtaining necessary governmental permits and 
5            approvals;
6                (9) the owner agrees that the new energy 
7            storage facility will be constructed or installed 
8            by a qualified entity or entities consistent with 
9            the requirements of subsection (g) of Section 
10            16-128A of the Public Utilities Act and any rules 
11            adopted under that Section;
12                (10) the owner agrees that personnel operating 
13            the energy storage facility will have the 
14            requisite skills, knowledge, training, experience, 
15            and competence, which may be demonstrated by 
16            completion or current participation and ultimate 
17            completion by employees of an accredited or 
18            otherwise recognized apprenticeship program for 
19            the employee's particular craft, trade, or skill, 
20            including through training and education courses 
21            and opportunities offered by the owner to 
22            employees of the coal-fueled electric generating 
23            facility or by previous employment experience 
24            performing the employee's particular work skill or 
25            function;
26                (11) the owner commits that not less than the 
 
 
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1            prevailing wage, as determined pursuant to the 
2            Prevailing Wage Act, will be paid to the owner's 
3            employees engaged in construction activities 
4            associated with the new energy storage facility 
5            and to the employees of the owner's contractors 
6            engaged in construction activities associated with 
7            the new energy storage facility, and that, on or 
8            before the commercial operation date of the new 
9            energy storage facility, the owner shall file a 
10            report with the Department certifying that the 
11            requirements of this subparagraph (11) have been 
12            met; and
13                (12) the owner commits that if selected to 
14            receive a grant, it will negotiate a project labor 
15            agreement for the construction of the new energy 
16            storage facility that includes provisions 
17            requiring the parties to the agreement to work 
18            together to establish diversity threshold 
19            requirements and to ensure best efforts to meet 
20            diversity targets, improve diversity at the 
21            applicable job site, create diverse apprenticeship 
22            opportunities, and create opportunities to employ 
23            former coal-fired power plant workers.
24            The Department shall accept applications for this 
25        grant program until March 31, 2022 and shall announce 
26        the award of grants no later than June 1, 2022. The 
 
 
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1        Department shall make the grant payments to a 
2        recipient in equal annual amounts for 10 years 
3        following the date the energy storage facility is 
4        placed into commercial operation. The annual grant 
5        payments to a qualifying energy storage facility shall 
6        be $110,000 per megawatt of energy storage capacity, 
7        with total annual grant payments pursuant to this 
8        subparagraph (C) for qualifying energy storage 
9        facilities not to exceed $28,050,000 in any year.
10            (D) Grants of funding for energy storage 
11        facilities pursuant to subparagraph (C) of this 
12        paragraph (10), from the Coal to Solar and Energy 
13        Storage Initiative Fund, shall be memorialized in 
14        grant contracts between the Department and the 
15        recipient. The grant contracts shall specify the date 
16        or dates in each year on which the annual grant 
17        payments shall be paid.
18            (E) All disbursements from the Coal to Solar and 
19        Energy Storage Initiative Fund shall be made only upon 
20        warrants of the Comptroller drawn upon the Treasurer 
21        as custodian of the Fund upon vouchers signed by the 
22        Director of the Department or by the person or persons 
23        designated by the Director of the Department for that 
24        purpose. The Comptroller is authorized to draw the 
25        warrants upon vouchers so signed. The Treasurer shall 
26        accept all written warrants so signed and shall be 
 
 
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1        released from liability for all payments made on those 
2        warrants.
3        (11) Diversity, equity, and inclusion plans.
4            (A) Each applicant selected in a procurement event 
5        to contract to supply renewable energy credits in 
6        accordance with this subsection (c-5) and each owner 
7        selected by the Department to receive a grant or 
8        grants to support the construction and operation of a 
9        new energy storage facility or facilities in 
10        accordance with this subsection (c-5) shall, within 60 
11        days following the Commission's approval of the 
12        applicant to contract to supply renewable energy 
13        credits or within 60 days following execution of a 
14        grant contract with the Department, as applicable, 
15        submit to the Commission a diversity, equity, and 
16        inclusion plan setting forth the applicant's or 
17        owner's numeric goals for the diversity composition of 
18        its supplier entities for the new renewable energy 
19        facility or new energy storage facility, as 
20        applicable, which shall be referred to for purposes of 
21        this paragraph (11) as the project, and the 
22        applicant's or owner's action plan and schedule for 
23        achieving those goals.
24            (B) For purposes of this paragraph (11), diversity 
25        composition shall be based on the percentage, which 
26        shall be a minimum of 25%, of eligible expenditures 
 
 
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1        for contract awards for materials and services (which 
2        shall be defined in the plan) to business enterprises 
3        owned by minority persons, women, or persons with 
4        disabilities as defined in Section 2 of the Business 
5        Enterprise for Minorities, Women, and Persons with 
6        Disabilities Act, to LGBTQ business enterprises, to 
7        veteran-owned business enterprises, and to business 
8        enterprises located in environmental justice 
9        communities. The diversity composition goals of the 
10        plan may include eligible expenditures in areas for 
11        vendor or supplier opportunities in addition to 
12        development and construction of the project, and may 
13        exclude from eligible expenditures materials and 
14        services with limited market availability, limited 
15        production and availability from suppliers in the 
16        United States, such as solar panels and storage 
17        batteries, and material and services that are subject 
18        to critical energy infrastructure or cybersecurity 
19        requirements or restrictions. The plan may provide 
20        that the diversity composition goals may be met 
21        through Tier 1 Direct or Tier 2 subcontracting 
22        expenditures or a combination thereof for the project.
23            (C) The plan shall provide for, but not be limited 
24        to: (i) internal initiatives, including multi-tier 
25        initiatives, by the applicant or owner, or by its 
26        engineering, procurement and construction contractor 
 
 
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1        if one is used for the project, which for purposes of 
2        this paragraph (11) shall be referred to as the EPC 
3        contractor, to enable diverse businesses to be 
4        considered fairly for selection to provide materials 
5        and services; (ii) requirements for the applicant or 
6        owner or its EPC contractor to proactively solicit and 
7        utilize diverse businesses to provide materials and 
8        services; and (iii) requirements for the applicant or 
9        owner or its EPC contractor to hire a diverse 
10        workforce for the project. The plan shall include a 
11        description of the applicant's or owner's diversity 
12        recruiting efforts both for the project and for other 
13        areas of the applicant's or owner's business 
14        operations. The plan shall provide for the imposition 
15        of financial penalties on the applicant's or owner's 
16        EPC contractor for failure to exercise best efforts to 
17        comply with and execute the EPC contractor's diversity 
18        obligations under the plan. The plan may provide for 
19        the applicant or owner to set aside a portion of the 
20        work on the project to serve as an incubation program 
21        for qualified businesses, as specified in the plan, 
22        owned by minority persons, women, persons with 
23        disabilities, LGBTQ persons, and veterans, and 
24        businesses located in environmental justice 
25        communities, seeking to enter the renewable energy 
26        industry.
 
 
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1            (D) The applicant or owner may submit a revised or 
2        updated plan to the Commission from time to time as 
3        circumstances warrant. The applicant or owner shall 
4        file annual reports with the Commission detailing the 
5        applicant's or owner's progress in implementing its 
6        plan and achieving its goals and any modifications the 
7        applicant or owner has made to its plan to better 
8        achieve its diversity, equity and inclusion goals. The 
9        applicant or owner shall file a final report on the 
10        fifth June 1 following the commercial operation date 
11        of the new renewable energy resource or new energy 
12        storage facility, but the applicant or owner shall 
13        thereafter continue to be subject to applicable 
14        reporting requirements of Section 5-117 of the Public 
15        Utilities Act. 
16    (c-10) Equity accountability system. It is the purpose of 
17this subsection (c-10) to create an equity accountability 
18system, which includes the minimum equity standards for all 
19renewable energy procurements, the equity category of the 
20Adjustable Block Program, and the equity prioritization for 
21noncompetitive procurements, that is successful in advancing 
22priority access to the clean energy economy for businesses and 
23workers from communities that have been excluded from economic 
24opportunities in the energy sector, have been subject to 
25disproportionate levels of pollution, and have 
26disproportionately experienced negative public health 
 
 
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1outcomes. Further, it is the purpose of this subsection to 
2ensure that this equity accountability system is successful in 
3advancing equity across Illinois by providing access to the 
4clean energy economy for businesses and workers from 
5communities that have been historically excluded from economic 
6opportunities in the energy sector, have been subject to 
7disproportionate levels of pollution, and have 
8disproportionately experienced negative public health 
9outcomes.
10        (1) Minimum equity standards. The Agency shall create 
11    programs with the purpose of increasing access to and 
12    development of equity eligible contractors, who are prime 
13    contractors and subcontractors, across all of the programs 
14    it manages. All applications for renewable energy credit 
15    procurements shall comply with specific minimum equity 
16    commitments. Starting in the delivery year immediately 
17    following the next long-term renewable resources 
18    procurement plan, at least 10% of the project workforce 
19    for each entity participating in a procurement program 
20    outlined in this subsection (c-10) must be done by equity 
21    eligible persons or equity eligible contractors. The 
22    Agency shall increase the minimum percentage each delivery 
23    year thereafter by increments that ensure a statewide 
24    average of 30% of the project workforce for each entity 
25    participating in a procurement program is done by equity 
26    eligible persons or equity eligible contractors by 2030. 
 
 
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1    The Agency shall propose a schedule of percentage 
2    increases to the minimum equity standards in its draft 
3    revised renewable energy resources procurement plan 
4    submitted to the Commission for approval pursuant to 
5    paragraph (5) of subsection (b) of Section 16-111.5 of the 
6    Public Utilities Act. In determining these annual 
7    increases, the Agency shall have the discretion to 
8    establish different minimum equity standards for different 
9    types of procurements and different regions of the State 
10    if the Agency finds that doing so will further the 
11    purposes of this subsection (c-10). The proposed schedule 
12    of annual increases shall be revisited and updated on an 
13    annual basis. Revisions shall be developed with 
14    stakeholder input, including from equity eligible persons, 
15    equity eligible contractors, clean energy industry 
16    representatives, and community-based organizations that 
17    work with such persons and contractors.
18            (A) At the start of each delivery year, the Agency 
19        shall require a compliance plan from each entity 
20        participating in a procurement program of subsection 
21        (c) of this Section, and entities opting to comply 
22        with the minimum equity standard through the Illinois 
23        Solar for All Program under Section 1-56 of this Act,    
24        that demonstrates how they will achieve compliance 
25        with the minimum equity standard percentage for work 
26        completed in that delivery year. If an entity applies 
 
 
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1        for its approved vendor or designee status between 
2        delivery years, the Agency shall require a compliance 
3        plan at the time of application.
4            (B) Halfway through each delivery year, the Agency 
5        shall require each entity participating in a 
6        procurement program to confirm that it will achieve 
7        compliance in that delivery year, when applicable. The 
8        Agency may offer corrective action plans to entities 
9        that are not on track to achieve compliance.
10            (C) At the end of each delivery year, each entity 
11        participating and completing work in that delivery 
12        year in a procurement program of subsection (c) shall 
13        submit a report to the Agency that demonstrates how it 
14        achieved compliance with the minimum equity standards 
15        percentage for that delivery year.
16            (D) The Agency shall prohibit participation in 
17        procurement programs by an approved vendor or 
18        designee, as applicable, or entities with which an 
19        approved vendor or designee, as applicable, shares a 
20        common parent company if an approved vendor or 
21        designee, as applicable, failed to meet the minimum 
22        equity standards for the prior delivery year. Waivers 
23        approved for lack of equity eligible persons or equity 
24        eligible contractors in a geographic area of a project 
25        shall not count against the approved vendor or 
26        designee. The Agency shall offer a corrective action 
 
 
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1        plan for any such entities to assist them in obtaining 
2        compliance and shall allow continued access to 
3        procurement programs upon an approved vendor or 
4        designee demonstrating compliance.
5            (E) The Agency shall pursue efficiencies achieved 
6        by combining with other approved vendor or designee 
7        reporting.
8        (2) Equity accountability system within the Adjustable 
9    Block program. The equity category described in item (vi) 
10    of subparagraph (K) of subsection (c) is only available to 
11    applicants that are equity eligible contractors.
12        (3) Equity accountability system within competitive 
13    procurements. Through its long-term renewable resources 
14    procurement plan, the Agency shall develop requirements 
15    for ensuring that competitive procurement processes, 
16    including utility-scale solar, utility-scale wind, and 
17    brownfield site photovoltaic projects, advance the equity 
18    goals of this subsection (c-10). Subject to Commission 
19    approval, the Agency shall develop bid application 
20    requirements and a bid evaluation methodology for ensuring 
21    that utilization of equity eligible contractors, whether 
22    as bidders or as participants on project development, is 
23    optimized, including requiring that winning or successful 
24    applicants for utility-scale projects are or will partner 
25    with equity eligible contractors and giving preference to 
26    bids through which a higher portion of contract value 
 
 
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1    flows to equity eligible contractors. To the extent 
2    practicable, entities participating in competitive 
3    procurements shall also be required to meet all the equity 
4    accountability requirements for approved vendors and their 
5    designees under this subsection (c-10). In developing 
6    these requirements, the Agency shall also consider whether 
7    equity goals can be further advanced through additional 
8    measures.
9        (4) In the first revision to the long-term renewable 
10    energy resources procurement plan and each revision 
11    thereafter, the Agency shall include the following:
12            (A) The current status and number of equity 
13        eligible contractors listed in the Energy Workforce 
14        Equity Database designed in subsection (c-25), 
15        including the number of equity eligible contractors 
16        with current certifications as issued by the Agency.
17            (B) A mechanism for measuring, tracking, and 
18        reporting project workforce at the approved vendor or 
19        designee level, as applicable, which shall include a 
20        measurement methodology and records to be made 
21        available for audit by the Agency or the Program 
22        Administrator.
23            (C) A program for approved vendors, designees, 
24        eligible persons, and equity eligible contractors to 
25        receive trainings, guidance, and other support from 
26        the Agency or its designee regarding the equity 
 
 
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1        category outlined in item (vi) of subparagraph (K) of 
2        paragraph (1) of subsection (c) and in meeting the 
3        minimum equity standards of this subsection (c-10).
4            (D) A process for certifying equity eligible 
5        contractors and equity eligible persons. The 
6        certification process shall coordinate with the Energy 
7        Workforce Equity Database set forth in subsection 
8        (c-25).
9            (E) An application for waiver of the minimum 
10        equity standards of this subsection, which the Agency 
11        shall have the discretion to grant in rare 
12        circumstances. The Agency may grant such a waiver 
13        where the applicant provides evidence of significant 
14        efforts toward meeting the minimum equity commitment, 
15        including: use of the Energy Workforce Equity 
16        Database; efforts to hire or contract with entities 
17        that hire eligible persons; and efforts to establish 
18        contracting relationships with eligible contractors. 
19        The Agency shall support applicants in understanding 
20        the Energy Workforce Equity Database and other 
21        resources for pursuing compliance of the minimum 
22        equity standards. Waivers shall be project-specific, 
23        unless the Agency deems it necessary to grant a waiver 
24        across a portfolio of projects, and in effect for no 
25        longer than one year. Any waiver extension or 
26        subsequent waiver request from an applicant shall be 
 
 
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1        subject to the requirements of this Section and shall 
2        specify efforts made to reach compliance. When 
3        considering whether to grant a waiver, and to what 
4        extent, the Agency shall consider the degree to which 
5        similarly situated applicants have been able to meet 
6        these minimum equity commitments. For repeated waiver 
7        requests for specific lack of eligible persons or 
8        eligible contractors available, the Agency shall make 
9        recommendations to target recruitment to add such 
10        eligible persons or eligible contractors to the 
11        database.
12        (5) The Agency shall collect information about work on 
13    projects or portfolios of projects subject to these 
14    minimum equity standards to ensure compliance with this 
15    subsection (c-10). Reporting in furtherance of this 
16    requirement may be combined with other annual reporting 
17    requirements. Such reporting shall include proof of 
18    certification of each equity eligible contractor or equity 
19    eligible person during the applicable time period.
20        As part of the reporting requirement under this 
21    subparagraph (5), the Agency shall collect and report 
22    information about the use of equity eligible contractors 
23    and equity eligible persons, as well as Minimum Equity 
24    Standard compliance and waiver usage on the Adjustable 
25    Block program and utility-scale projects subject to 
26    project labor agreements. The Agency shall note any 
 
 
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1    instances of the projects being unable to meet or 
2    requiring a waiver to meet Minimum Equity Standard 
3    requirements and the location of those projects.
4        On an annual basis, the Agency shall submit a written 
5    summary of its findings on an annual basis to the General 
6    Assembly and the Governor and shall make the report and 
7    summary available on the Agency's website.
8        (6) The Agency shall keep confidential all information 
9    and communication that provides private or personal 
10    information.
11        (7) Modifications to the equity accountability system. 
12    As part of the update of the long-term renewable resources 
13    procurement plan to be initiated in 2023, or sooner if the 
14    Agency deems necessary, the Agency shall determine the 
15    extent to which the equity accountability system described 
16    in this subsection (c-10) has advanced the goals of this 
17    amendatory Act of the 102nd General Assembly, including 
18    through the inclusion of equity eligible persons and 
19    equity eligible contractors in renewable energy credit 
20    projects. If the Agency finds that the equity 
21    accountability system has failed to meet those goals to 
22    its fullest potential, the Agency may revise the following 
23    criteria for future Agency procurements: (A) the 
24    percentage of project workforce, or other appropriate 
25    workforce measure, certified as equity eligible persons or 
26    equity eligible contractors; (B) definitions for equity 
 
 
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1    investment eligible persons and equity investment eligible 
2    community; and (C) such other modifications necessary to 
3    advance the goals of this amendatory Act of the 102nd 
4    General Assembly effectively. Such revised criteria may 
5    also establish distinct equity accountability systems for 
6    different types of procurements or different regions of 
7    the State if the Agency finds that doing so will further 
8    the purposes of such programs. Revisions shall be 
9    developed with stakeholder input, including from equity 
10    eligible persons, equity eligible contractors, and 
11    community-based organizations that work with such persons 
12    and contractors.
13    (c-15) Racial discrimination elimination powers and 
14process.
15        (1) Purpose. It is the purpose of this subsection to 
16    empower the Agency and other State actors to remedy racial 
17    discrimination in Illinois' clean energy economy as 
18    effectively and expediently as possible, including through 
19    the use of race-conscious remedies, such as race-conscious 
20    contracting and hiring goals, as consistent with State and 
21    federal law.
22        (2) Racial disparity and discrimination review 
23    process.
24            (A) Within one year after awarding contracts using 
25        the equity actions processes established in this 
26        Section, the Agency shall publish a report evaluating 
 
 
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1        the effectiveness of the equity actions point criteria 
2        of this Section in increasing participation of equity 
3        eligible persons and equity eligible contractors. The 
4        report shall disaggregate participating workers and 
5        contractors by race and ethnicity. The report shall be 
6        forwarded to the Governor, the General Assembly, and 
7        the Illinois Commerce Commission and be made available 
8        to the public.
9            (B) As soon as is practicable thereafter, the 
10        Agency, in consultation with the Department of 
11        Commerce and Economic Opportunity, Department of 
12        Labor, and other agencies that may be relevant, shall 
13        commission and publish a disparity and availability 
14        study that measures the presence and impact of 
15        discrimination on minority businesses and workers in 
16        Illinois' clean energy economy. The Agency may hire 
17        consultants and experts to conduct the disparity and 
18        availability study, with the retention of those 
19        consultants and experts exempt from the requirements 
20        of Section 20-10 of the Illinois Procurement Code. The 
21        Illinois Power Agency shall forward a copy of its 
22        findings and recommendations to the Governor, the 
23        General Assembly, and the Illinois Commerce 
24        Commission. If the disparity and availability study 
25        establishes a strong basis in evidence that there is 
26        discrimination in Illinois' clean energy economy, the 
 
 
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1        Agency, Department of Commerce and Economic 
2        Opportunity, Department of Labor, Department of 
3        Corrections, and other appropriate agencies shall take 
4        appropriate remedial actions, including race-conscious 
5        remedial actions as consistent with State and federal 
6        law, to effectively remedy this discrimination. Such 
7        remedies may include modification of the equity 
8        accountability system as described in subsection 
9        (c-10).
10    (c-20) Program data collection.
11        (1) Purpose. Data collection, data analysis, and 
12    reporting are critical to ensure that the benefits of the 
13    clean energy economy provided to Illinois residents and 
14    businesses are equitably distributed across the State. The 
15    Agency shall collect data from program applicants in order 
16    to track and improve equitable distribution of benefits 
17    across Illinois communities for all procurements the 
18    Agency conducts. The Agency shall use this data to, among 
19    other things, measure any potential impact of racial 
20    discrimination on the distribution of benefits and provide 
21    information necessary to correct any discrimination 
22    through methods consistent with State and federal law.
23        (2) Agency collection of program data. The Agency 
24    shall collect demographic and geographic data for each 
25    entity awarded contracts under any Agency-administered 
26    program.
 
 
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1        (3) Required information to be collected. The Agency 
2    shall collect the following information from applicants 
3    and program participants where applicable:
4            (A) demographic information, including racial or 
5        ethnic identity for real persons employed, contracted, 
6        or subcontracted through the program and owners of 
7        businesses or entities that apply to receive renewable 
8        energy credits from the Agency;
9            (B) geographic location of the residency of real 
10        persons employed, contracted, or subcontracted through 
11        the program and geographic location of the 
12        headquarters of the business or entity that applies to 
13        receive renewable energy credits from the Agency; and
14            (C) any other information the Agency determines is 
15        necessary for the purpose of achieving the purpose of 
16        this subsection.
17        (4) Publication of collected information. The Agency 
18    shall publish, at least annually, information on the 
19    demographics of program participants on an aggregate 
20    basis.
21        (5) Nothing in this subsection shall be interpreted to 
22    limit the authority of the Agency, or other agency or 
23    department of the State, to require or collect demographic 
24    information from applicants of other State programs.
25    (c-25) Energy Workforce Equity Database.
26        (1) The Agency, in consultation with the Department of 
 
 
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1    Commerce and Economic Opportunity, shall create an Energy 
2    Workforce Equity Database, and may contract with a third 
3    party to do so ("database program administrator"). If the 
4    Department decides to contract with a third party, that 
5    third party shall be exempt from the requirements of 
6    Section 20-10 of the Illinois Procurement Code. The Energy 
7    Workforce Equity Database shall be a searchable database 
8    of suppliers, vendors, and subcontractors for clean energy 
9    industries that is:
10            (A) publicly accessible;
11            (B) easy for people to find and use;
12            (C) organized by company specialty or field;
13            (D) region-specific; and
14            (E) populated with information including, but not 
15        limited to, contacts for suppliers, vendors, or 
16        subcontractors who are minority and women-owned 
17        business enterprise certified or who participate or 
18        have participated in any of the programs described in 
19        this Act.
20        (2) The Agency shall create an easily accessible, 
21    public facing online tool using the database information 
22    that includes, at a minimum, the following:
23            (A) a map of environmental justice and equity 
24        investment eligible communities;
25            (B) job postings and recruiting opportunities;
26            (C) a means by which recruiting clean energy 
 
 
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1        companies can find and interact with current or former 
2        participants of clean energy workforce training 
3        programs;
4            (D) information on workforce training service 
5        providers and training opportunities available to 
6        prospective workers;
7            (E) renewable energy company diversity reporting;
8            (F) a list of equity eligible contractors with 
9        their contact information, types of work performed, 
10        and locations worked in;
11            (G) reporting on outcomes of the programs 
12        described in the workforce programs of the Energy 
13        Transition Act, including information such as, but not 
14        limited to, retention rate, graduation rate, and 
15        placement rates of trainees; and
16            (H) information about the Jobs and Environmental 
17        Justice Grant Program, the Clean Energy Jobs and 
18        Justice Fund, and other sources of capital.
19        (3) The Agency shall ensure the database is regularly 
20    updated to ensure information is current and shall 
21    coordinate with the Department of Commerce and Economic 
22    Opportunity to ensure that it includes information on 
23    individuals and entities that are or have participated in 
24    the Clean Jobs Workforce Network Program, Clean Energy 
25    Contractor Incubator Program, Returning Residents Clean 
26    Jobs Training Program, or Clean Energy Primes Contractor 
 
 
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1    Accelerator Program.
2    (c-30) Enforcement of minimum equity standards. All 
3entities seeking renewable energy credits must submit an 
4annual report to demonstrate compliance with each of the 
5equity commitments required under subsection (c-10). If the 
6Agency concludes the entity has not met or maintained its 
7minimum equity standards required under the applicable 
8subparagraphs under subsection (c-10), the Agency shall deny 
9the entity's ability to participate in procurement programs in 
10subsection (c), including by withholding approved vendor or 
11designee status. The Agency may require the entity to enter 
12into a corrective action plan. An entity that is not 
13recertified for failing to meet required equity actions in 
14subparagraph (c-10) may reapply once they have a corrective 
15action plan and achieve compliance with the minimum equity 
16standards.
17    (d) Clean coal portfolio standard.
18        (1) The procurement plans shall include electricity 
19    generated using clean coal. Each utility shall enter into 
20    one or more sourcing agreements with the initial clean 
21    coal facility, as provided in paragraph (3) of this 
22    subsection (d), covering electricity generated by the 
23    initial clean coal facility representing at least 5% of 
24    each utility's total supply to serve the load of eligible 
25    retail customers in 2015 and each year thereafter, as 
26    described in paragraph (3) of this subsection (d), subject 
 
 
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1    to the limits specified in paragraph (2) of this 
2    subsection (d). It is the goal of the State that by January 
3    1, 2025, 25% of the electricity used in the State shall be 
4    generated by cost-effective clean coal facilities. For 
5    purposes of this subsection (d), "cost-effective" means 
6    that the expenditures pursuant to such sourcing agreements 
7    do not cause the limit stated in paragraph (2) of this 
8    subsection (d) to be exceeded and do not exceed cost-based 
9    benchmarks, which shall be developed to assess all 
10    expenditures pursuant to such sourcing agreements covering 
11    electricity generated by clean coal facilities, other than 
12    the initial clean coal facility, by the procurement 
13    administrator, in consultation with the Commission staff, 
14    Agency staff, and the procurement monitor and shall be 
15    subject to Commission review and approval.
16        A utility party to a sourcing agreement shall 
17    immediately retire any emission credits that it receives 
18    in connection with the electricity covered by such 
19    agreement.
20        Utilities shall maintain adequate records documenting 
21    the purchases under the sourcing agreement to comply with 
22    this subsection (d) and shall file an accounting with the 
23    load forecast that must be filed with the Agency by July 15 
24    of each year, in accordance with subsection (d) of Section 
25    16-111.5 of the Public Utilities Act.
26        A utility shall be deemed to have complied with the 
 
 
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1    clean coal portfolio standard specified in this subsection 
2    (d) if the utility enters into a sourcing agreement as 
3    required by this subsection (d). 
4        (2) For purposes of this subsection (d), the required 
5    execution of sourcing agreements with the initial clean 
6    coal facility for a particular year shall be measured as a 
7    percentage of the actual amount of electricity 
8    (megawatt-hours) supplied by the electric utility to 
9    eligible retail customers in the planning year ending 
10    immediately prior to the agreement's execution. For 
11    purposes of this subsection (d), the amount paid per 
12    kilowatthour means the total amount paid for electric 
13    service expressed on a per kilowatthour basis. For 
14    purposes of this subsection (d), the total amount paid for 
15    electric service includes without limitation amounts paid 
16    for supply, transmission, distribution, surcharges and 
17    add-on taxes.
18        Notwithstanding the requirements of this subsection 
19    (d), the total amount paid under sourcing agreements with 
20    clean coal facilities pursuant to the procurement plan for 
21    any given year shall be reduced by an amount necessary to 
22    limit the annual estimated average net increase due to the 
23    costs of these resources included in the amounts paid by 
24    eligible retail customers in connection with electric 
25    service to:
26            (A) in 2010, no more than 0.5% of the amount paid 
 
 
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1        per kilowatthour by those customers during the year 
2        ending May 31, 2009;
3            (B) in 2011, the greater of an additional 0.5% of 
4        the amount paid per kilowatthour by those customers 
5        during the year ending May 31, 2010 or 1% of the amount 
6        paid per kilowatthour by those customers during the 
7        year ending May 31, 2009;
8            (C) in 2012, the greater of an additional 0.5% of 
9        the amount paid per kilowatthour by those customers 
10        during the year ending May 31, 2011 or 1.5% of the 
11        amount paid per kilowatthour by those customers during 
12        the year ending May 31, 2009;
13            (D) in 2013, the greater of an additional 0.5% of 
14        the amount paid per kilowatthour by those customers 
15        during the year ending May 31, 2012 or 2% of the amount 
16        paid per kilowatthour by those customers during the 
17        year ending May 31, 2009; and
18            (E) thereafter, the total amount paid under 
19        sourcing agreements with clean coal facilities 
20        pursuant to the procurement plan for any single year 
21        shall be reduced by an amount necessary to limit the 
22        estimated average net increase due to the cost of 
23        these resources included in the amounts paid by 
24        eligible retail customers in connection with electric 
25        service to no more than the greater of (i) 2.015% of 
26        the amount paid per kilowatthour by those customers 
 
 
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1        during the year ending May 31, 2009 or (ii) the 
2        incremental amount per kilowatthour paid for these 
3        resources in 2013. These requirements may be altered 
4        only as provided by statute.
5        No later than June 30, 2015, the Commission shall 
6    review the limitation on the total amount paid under 
7    sourcing agreements, if any, with clean coal facilities 
8    pursuant to this subsection (d) and report to the General 
9    Assembly its findings as to whether that limitation unduly 
10    constrains the amount of electricity generated by 
11    cost-effective clean coal facilities that is covered by 
12    sourcing agreements.
13        (3) Initial clean coal facility. In order to promote 
14    development of clean coal facilities in Illinois, each 
15    electric utility subject to this Section shall execute a 
16    sourcing agreement to source electricity from a proposed 
17    clean coal facility in Illinois (the "initial clean coal 
18    facility") that will have a nameplate capacity of at least 
19    500 MW when commercial operation commences, that has a 
20    final Clean Air Act permit on June 1, 2009 (the effective 
21    date of Public Act 95-1027), and that will meet the 
22    definition of clean coal facility in Section 1-10 of this 
23    Act when commercial operation commences. The sourcing 
24    agreements with this initial clean coal facility shall be 
25    subject to both approval of the initial clean coal 
26    facility by the General Assembly and satisfaction of the 
 
 
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1    requirements of paragraph (4) of this subsection (d) and 
2    shall be executed within 90 days after any such approval 
3    by the General Assembly. The Agency and the Commission 
4    shall have authority to inspect all books and records 
5    associated with the initial clean coal facility during the 
6    term of such a sourcing agreement. A utility's sourcing 
7    agreement for electricity produced by the initial clean 
8    coal facility shall include:
9            (A) a formula contractual price (the "contract 
10        price") approved pursuant to paragraph (4) of this 
11        subsection (d), which shall:
12                (i) be determined using a cost of service 
13            methodology employing either a level or deferred 
14            capital recovery component, based on a capital 
15            structure consisting of 45% equity and 55% debt, 
16            and a return on equity as may be approved by the 
17            Federal Energy Regulatory Commission, which in any 
18            case may not exceed the lower of 11.5% or the rate 
19            of return approved by the General Assembly 
20            pursuant to paragraph (4) of this subsection (d); 
21            and
22                (ii) provide that all miscellaneous net 
23            revenue, including but not limited to net revenue 
24            from the sale of emission allowances, if any, 
25            substitute natural gas, if any, grants or other 
26            support provided by the State of Illinois or the 
 
 
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1            United States Government, firm transmission 
2            rights, if any, by-products produced by the 
3            facility, energy or capacity derived from the 
4            facility and not covered by a sourcing agreement 
5            pursuant to paragraph (3) of this subsection (d) 
6            or item (5) of subsection (d) of Section 16-115 of 
7            the Public Utilities Act, whether generated from 
8            the synthesis gas derived from coal, from SNG, or 
9            from natural gas, shall be credited against the 
10            revenue requirement for this initial clean coal 
11            facility;
12            (B) power purchase provisions, which shall: 
13                (i) provide that the utility party to such 
14            sourcing agreement shall pay the contract price 
15            for electricity delivered under such sourcing 
16            agreement; 
17                (ii) require delivery of electricity to the 
18            regional transmission organization market of the 
19            utility that is party to such sourcing agreement;
20                (iii) require the utility party to such 
21            sourcing agreement to buy from the initial clean 
22            coal facility in each hour an amount of energy 
23            equal to all clean coal energy made available from 
24            the initial clean coal facility during such hour 
25            times a fraction, the numerator of which is such 
26            utility's retail market sales of electricity 
 
 
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1            (expressed in kilowatthours sold) in the State 
2            during the prior calendar month and the 
3            denominator of which is the total retail market 
4            sales of electricity (expressed in kilowatthours 
5            sold) in the State by utilities during such prior 
6            month and the sales of electricity (expressed in 
7            kilowatthours sold) in the State by alternative 
8            retail electric suppliers during such prior month 
9            that are subject to the requirements of this 
10            subsection (d) and paragraph (5) of subsection (d) 
11            of Section 16-115 of the Public Utilities Act, 
12            provided that the amount purchased by the utility 
13            in any year will be limited by paragraph (2) of 
14            this subsection (d); and
15                (iv) be considered pre-existing contracts in 
16            such utility's procurement plans for eligible 
17            retail customers;
18            (C) contract for differences provisions, which 
19        shall:
20                (i) require the utility party to such sourcing 
21            agreement to contract with the initial clean coal 
22            facility in each hour with respect to an amount of 
23            energy equal to all clean coal energy made 
24            available from the initial clean coal facility 
25            during such hour times a fraction, the numerator 
26            of which is such utility's retail market sales of 
 
 
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1            electricity (expressed in kilowatthours sold) in 
2            the utility's service territory in the State 
3            during the prior calendar month and the 
4            denominator of which is the total retail market 
5            sales of electricity (expressed in kilowatthours 
6            sold) in the State by utilities during such prior 
7            month and the sales of electricity (expressed in 
8            kilowatthours sold) in the State by alternative 
9            retail electric suppliers during such prior month 
10            that are subject to the requirements of this 
11            subsection (d) and paragraph (5) of subsection (d) 
12            of Section 16-115 of the Public Utilities Act, 
13            provided that the amount paid by the utility in 
14            any year will be limited by paragraph (2) of this 
15            subsection (d);
16                (ii) provide that the utility's payment 
17            obligation in respect of the quantity of 
18            electricity determined pursuant to the preceding 
19            clause (i) shall be limited to an amount equal to 
20            (1) the difference between the contract price 
21            determined pursuant to subparagraph (A) of 
22            paragraph (3) of this subsection (d) and the 
23            day-ahead price for electricity delivered to the 
24            regional transmission organization market of the 
25            utility that is party to such sourcing agreement 
26            (or any successor delivery point at which such 
 
 
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1            utility's supply obligations are financially 
2            settled on an hourly basis) (the "reference 
3            price") on the day preceding the day on which the 
4            electricity is delivered to the initial clean coal 
5            facility busbar, multiplied by (2) the quantity of 
6            electricity determined pursuant to the preceding 
7            clause (i); and
8                (iii) not require the utility to take physical 
9            delivery of the electricity produced by the 
10            facility;
11            (D) general provisions, which shall:
12                (i) specify a term of no more than 30 years, 
13            commencing on the commercial operation date of the 
14            facility;
15                (ii) provide that utilities shall maintain 
16            adequate records documenting purchases under the 
17            sourcing agreements entered into to comply with 
18            this subsection (d) and shall file an accounting 
19            with the load forecast that must be filed with the 
20            Agency by July 15 of each year, in accordance with 
21            subsection (d) of Section 16-111.5 of the Public 
22            Utilities Act; 
23                (iii) provide that all costs associated with 
24            the initial clean coal facility will be 
25            periodically reported to the Federal Energy 
26            Regulatory Commission and to purchasers in 
 
 
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1            accordance with applicable laws governing 
2            cost-based wholesale power contracts;
3                (iv) permit the Illinois Power Agency to 
4            assume ownership of the initial clean coal 
5            facility, without monetary consideration and 
6            otherwise on reasonable terms acceptable to the 
7            Agency, if the Agency so requests no less than 3 
8            years prior to the end of the stated contract 
9            term;
10                (v) require the owner of the initial clean 
11            coal facility to provide documentation to the 
12            Commission each year, starting in the facility's 
13            first year of commercial operation, accurately 
14            reporting the quantity of carbon emissions from 
15            the facility that have been captured and 
16            sequestered and report any quantities of carbon 
17            released from the site or sites at which carbon 
18            emissions were sequestered in prior years, based 
19            on continuous monitoring of such sites. If, in any 
20            year after the first year of commercial operation, 
21            the owner of the facility fails to demonstrate 
22            that the initial clean coal facility captured and 
23            sequestered at least 50% of the total carbon 
24            emissions that the facility would otherwise emit 
25            or that sequestration of emissions from prior 
26            years has failed, resulting in the release of 
 
 
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1            carbon dioxide into the atmosphere, the owner of 
2            the facility must offset excess emissions. Any 
3            such carbon offsets must be permanent, additional, 
4            verifiable, real, located within the State of 
5            Illinois, and legally and practicably enforceable. 
6            The cost of such offsets for the facility that are 
7            not recoverable shall not exceed $15 million in 
8            any given year. No costs of any such purchases of 
9            carbon offsets may be recovered from a utility or 
10            its customers. All carbon offsets purchased for 
11            this purpose and any carbon emission credits 
12            associated with sequestration of carbon from the 
13            facility must be permanently retired. The initial 
14            clean coal facility shall not forfeit its 
15            designation as a clean coal facility if the 
16            facility fails to fully comply with the applicable 
17            carbon sequestration requirements in any given 
18            year, provided the requisite offsets are 
19            purchased. However, the Attorney General, on 
20            behalf of the People of the State of Illinois, may 
21            specifically enforce the facility's sequestration 
22            requirement and the other terms of this contract 
23            provision. Compliance with the sequestration 
24            requirements and offset purchase requirements 
25            specified in paragraph (3) of this subsection (d) 
26            shall be reviewed annually by an independent 
 
 
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1            expert retained by the owner of the initial clean 
2            coal facility, with the advance written approval 
3            of the Attorney General. The Commission may, in 
4            the course of the review specified in item (vii), 
5            reduce the allowable return on equity for the 
6            facility if the facility willfully fails to comply 
7            with the carbon capture and sequestration 
8            requirements set forth in this item (v);
9                (vi) include limits on, and accordingly 
10            provide for modification of, the amount the 
11            utility is required to source under the sourcing 
12            agreement consistent with paragraph (2) of this 
13            subsection (d);
14                (vii) require Commission review: (1) to 
15            determine the justness, reasonableness, and 
16            prudence of the inputs to the formula referenced 
17            in subparagraphs (A)(i) through (A)(iii) of 
18            paragraph (3) of this subsection (d), prior to an 
19            adjustment in those inputs including, without 
20            limitation, the capital structure and return on 
21            equity, fuel costs, and other operations and 
22            maintenance costs and (2) to approve the costs to 
23            be passed through to customers under the sourcing 
24            agreement by which the utility satisfies its 
25            statutory obligations. Commission review shall 
26            occur no less than every 3 years, regardless of 
 
 
10400SB0025ham003- 352 -LRB104 07069 AAS 29208 a

1            whether any adjustments have been proposed, and 
2            shall be completed within 9 months; 
3                (viii) limit the utility's obligation to such 
4            amount as the utility is allowed to recover 
5            through tariffs filed with the Commission, 
6            provided that neither the clean coal facility nor 
7            the utility waives any right to assert federal 
8            pre-emption or any other argument in response to a 
9            purported disallowance of recovery costs;
10                (ix) limit the utility's or alternative retail 
11            electric supplier's obligation to incur any 
12            liability until such time as the facility is in 
13            commercial operation and generating power and 
14            energy and such power and energy is being 
15            delivered to the facility busbar;
16                (x) provide that the owner or owners of the 
17            initial clean coal facility, which is the 
18            counterparty to such sourcing agreement, shall 
19            have the right from time to time to elect whether 
20            the obligations of the utility party thereto shall 
21            be governed by the power purchase provisions or 
22            the contract for differences provisions;
23                (xi) append documentation showing that the 
24            formula rate and contract, insofar as they relate 
25            to the power purchase provisions, have been 
26            approved by the Federal Energy Regulatory 
 
 
10400SB0025ham003- 353 -LRB104 07069 AAS 29208 a

1            Commission pursuant to Section 205 of the Federal 
2            Power Act;
3                (xii) provide that any changes to the terms of 
4            the contract, insofar as such changes relate to 
5            the power purchase provisions, are subject to 
6            review under the public interest standard applied 
7            by the Federal Energy Regulatory Commission 
8            pursuant to Sections 205 and 206 of the Federal 
9            Power Act; and
10                (xiii) conform with customary lender 
11            requirements in power purchase agreements used as 
12            the basis for financing non-utility generators. 
13        (4) Effective date of sourcing agreements with the 
14    initial clean coal facility. Any proposed sourcing 
15    agreement with the initial clean coal facility shall not 
16    become effective unless the following reports are prepared 
17    and submitted and authorizations and approvals obtained:
18            (i) Facility cost report. The owner of the initial 
19        clean coal facility shall submit to the Commission, 
20        the Agency, and the General Assembly a front-end 
21        engineering and design study, a facility cost report, 
22        method of financing (including but not limited to 
23        structure and associated costs), and an operating and 
24        maintenance cost quote for the facility (collectively 
25        "facility cost report"), which shall be prepared in 
26        accordance with the requirements of this paragraph (4) 
 
 
10400SB0025ham003- 354 -LRB104 07069 AAS 29208 a

1        of subsection (d) of this Section, and shall provide 
2        the Commission and the Agency access to the work 
3        papers, relied upon documents, and any other backup 
4        documentation related to the facility cost report.
5            (ii) Commission report. Within 6 months following 
6        receipt of the facility cost report, the Commission, 
7        in consultation with the Agency, shall submit a report 
8        to the General Assembly setting forth its analysis of 
9        the facility cost report. Such report shall include, 
10        but not be limited to, a comparison of the costs 
11        associated with electricity generated by the initial 
12        clean coal facility to the costs associated with 
13        electricity generated by other types of generation 
14        facilities, an analysis of the rate impacts on 
15        residential and small business customers over the life 
16        of the sourcing agreements, and an analysis of the 
17        likelihood that the initial clean coal facility will 
18        commence commercial operation by and be delivering 
19        power to the facility's busbar by 2016. To assist in 
20        the preparation of its report, the Commission, in 
21        consultation with the Agency, may hire one or more 
22        experts or consultants, the costs of which shall be 
23        paid for by the owner of the initial clean coal 
24        facility. The Commission and Agency may begin the 
25        process of selecting such experts or consultants prior 
26        to receipt of the facility cost report.
 
 
10400SB0025ham003- 355 -LRB104 07069 AAS 29208 a

1            (iii) General Assembly approval. The proposed 
2        sourcing agreements shall not take effect unless, 
3        based on the facility cost report and the Commission's 
4        report, the General Assembly enacts authorizing 
5        legislation approving (A) the projected price, stated 
6        in cents per kilowatthour, to be charged for 
7        electricity generated by the initial clean coal 
8        facility, (B) the projected impact on residential and 
9        small business customers' bills over the life of the 
10        sourcing agreements, and (C) the maximum allowable 
11        return on equity for the project; and
12            (iv) Commission review. If the General Assembly 
13        enacts authorizing legislation pursuant to 
14        subparagraph (iii) approving a sourcing agreement, the 
15        Commission shall, within 90 days of such enactment, 
16        complete a review of such sourcing agreement. During 
17        such time period, the Commission shall implement any 
18        directive of the General Assembly, resolve any 
19        disputes between the parties to the sourcing agreement 
20        concerning the terms of such agreement, approve the 
21        form of such agreement, and issue an order finding 
22        that the sourcing agreement is prudent and reasonable.
23        The facility cost report shall be prepared as follows: 
24            (A) The facility cost report shall be prepared by 
25        duly licensed engineering and construction firms 
26        detailing the estimated capital costs payable to one 
 
 
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1        or more contractors or suppliers for the engineering, 
2        procurement and construction of the components 
3        comprising the initial clean coal facility and the 
4        estimated costs of operation and maintenance of the 
5        facility. The facility cost report shall include:
6                (i) an estimate of the capital cost of the 
7            core plant based on one or more front end 
8            engineering and design studies for the 
9            gasification island and related facilities. The 
10            core plant shall include all civil, structural, 
11            mechanical, electrical, control, and safety 
12            systems.
13                (ii) an estimate of the capital cost of the 
14            balance of the plant, including any capital costs 
15            associated with sequestration of carbon dioxide 
16            emissions and all interconnects and interfaces 
17            required to operate the facility, such as 
18            transmission of electricity, construction or 
19            backfeed power supply, pipelines to transport 
20            substitute natural gas or carbon dioxide, potable 
21            water supply, natural gas supply, water supply, 
22            water discharge, landfill, access roads, and coal 
23            delivery.
24            The quoted construction costs shall be expressed 
25        in nominal dollars as of the date that the quote is 
26        prepared and shall include capitalized financing costs 
 
 
10400SB0025ham003- 357 -LRB104 07069 AAS 29208 a

1        during construction, taxes, insurance, and other 
2        owner's costs, and an assumed escalation in materials 
3        and labor beyond the date as of which the construction 
4        cost quote is expressed.
5            (B) The front end engineering and design study for 
6        the gasification island and the cost study for the 
7        balance of plant shall include sufficient design work 
8        to permit quantification of major categories of 
9        materials, commodities and labor hours, and receipt of 
10        quotes from vendors of major equipment required to 
11        construct and operate the clean coal facility.
12            (C) The facility cost report shall also include an 
13        operating and maintenance cost quote that will provide 
14        the estimated cost of delivered fuel, personnel, 
15        maintenance contracts, chemicals, catalysts, 
16        consumables, spares, and other fixed and variable 
17        operations and maintenance costs. The delivered fuel 
18        cost estimate will be provided by a recognized third 
19        party expert or experts in the fuel and transportation 
20        industries. The balance of the operating and 
21        maintenance cost quote, excluding delivered fuel 
22        costs, will be developed based on the inputs provided 
23        by duly licensed engineering and construction firms 
24        performing the construction cost quote, potential 
25        vendors under long-term service agreements and plant 
26        operating agreements, or recognized third party plant 
 
 
10400SB0025ham003- 358 -LRB104 07069 AAS 29208 a

1        operator or operators.
2            The operating and maintenance cost quote 
3        (including the cost of the front end engineering and 
4        design study) shall be expressed in nominal dollars as 
5        of the date that the quote is prepared and shall 
6        include taxes, insurance, and other owner's costs, and 
7        an assumed escalation in materials and labor beyond 
8        the date as of which the operating and maintenance 
9        cost quote is expressed.
10            (D) The facility cost report shall also include an 
11        analysis of the initial clean coal facility's ability 
12        to deliver power and energy into the applicable 
13        regional transmission organization markets and an 
14        analysis of the expected capacity factor for the 
15        initial clean coal facility. 
16            (E) Amounts paid to third parties unrelated to the 
17        owner or owners of the initial clean coal facility to 
18        prepare the core plant construction cost quote, 
19        including the front end engineering and design study, 
20        and the operating and maintenance cost quote will be 
21        reimbursed through Coal Development Bonds.
22        (5) Re-powering and retrofitting coal-fired power 
23    plants previously owned by Illinois utilities to qualify 
24    as clean coal facilities. During the 2009 procurement 
25    planning process and thereafter, the Agency and the 
26    Commission shall consider sourcing agreements covering 
 
 
10400SB0025ham003- 359 -LRB104 07069 AAS 29208 a

1    electricity generated by power plants that were previously 
2    owned by Illinois utilities and that have been or will be 
3    converted into clean coal facilities, as defined by 
4    Section 1-10 of this Act. Pursuant to such procurement 
5    planning process, the owners of such facilities may 
6    propose to the Agency sourcing agreements with utilities 
7    and alternative retail electric suppliers required to 
8    comply with subsection (d) of this Section and item (5) of 
9    subsection (d) of Section 16-115 of the Public Utilities 
10    Act, covering electricity generated by such facilities. In 
11    the case of sourcing agreements that are power purchase 
12    agreements, the contract price for electricity sales shall 
13    be established on a cost of service basis. In the case of 
14    sourcing agreements that are contracts for differences, 
15    the contract price from which the reference price is 
16    subtracted shall be established on a cost of service 
17    basis. The Agency and the Commission may approve any such 
18    utility sourcing agreements that do not exceed cost-based 
19    benchmarks developed by the procurement administrator, in 
20    consultation with the Commission staff, Agency staff and 
21    the procurement monitor, subject to Commission review and 
22    approval. The Commission shall have authority to inspect 
23    all books and records associated with these clean coal 
24    facilities during the term of any such contract.
25        (6) Costs incurred under this subsection (d) or 
26    pursuant to a contract entered into under this subsection 
 
 
10400SB0025ham003- 360 -LRB104 07069 AAS 29208 a

1    (d) shall be deemed prudently incurred and reasonable in 
2    amount and the electric utility shall be entitled to full 
3    cost recovery pursuant to the tariffs filed with the 
4    Commission. 
5    (d-5) Zero emission standard.
6        (1) Beginning with the delivery year commencing on 
7    June 1, 2017, the Agency shall, for electric utilities 
8    that serve at least 100,000 retail customers in this 
9    State, procure contracts with zero emission facilities 
10    that are reasonably capable of generating cost-effective 
11    zero emission credits in an amount approximately equal to 
12    16% of the actual amount of electricity delivered by each 
13    electric utility to retail customers in the State during 
14    calendar year 2014. For an electric utility serving fewer 
15    than 100,000 retail customers in this State that 
16    requested, under Section 16-111.5 of the Public Utilities 
17    Act, that the Agency procure power and energy for all or a 
18    portion of the utility's Illinois load for the delivery 
19    year commencing June 1, 2016, the Agency shall procure 
20    contracts with zero emission facilities that are 
21    reasonably capable of generating cost-effective zero 
22    emission credits in an amount approximately equal to 16% 
23    of the portion of power and energy to be procured by the 
24    Agency for the utility. The duration of the contracts 
25    procured under this subsection (d-5) shall be for a term 
26    of 10 years ending May 31, 2027. The quantity of zero 
 
 
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1    emission credits to be procured under the contracts shall 
2    be all of the zero emission credits generated by the zero 
3    emission facility in each delivery year; however, if the 
4    zero emission facility is owned by more than one entity, 
5    then the quantity of zero emission credits to be procured 
6    under the contracts shall be the amount of zero emission 
7    credits that are generated from the portion of the zero 
8    emission facility that is owned by the winning supplier.
9        The 16% value identified in this paragraph (1) is the 
10    average of the percentage targets in subparagraph (B) of 
11    paragraph (1) of subsection (c) of this Section for the 5 
12    delivery years beginning June 1, 2017.
13        The procurement process shall be subject to the 
14    following provisions:
15            (A) Those zero emission facilities that intend to 
16        participate in the procurement shall submit to the 
17        Agency the following eligibility information for each 
18        zero emission facility on or before the date 
19        established by the Agency:
20                (i) the in-service date and remaining useful 
21            life of the zero emission facility;
22                (ii) the amount of power generated annually 
23            for each of the years 2005 through 2015, and the 
24            projected zero emission credits to be generated 
25            over the remaining useful life of the zero 
26            emission facility, which shall be used to 
 
 
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1            determine the capability of each facility;
2                (iii) the annual zero emission facility cost 
3            projections, expressed on a per megawatthour 
4            basis, over the next 6 delivery years, which shall 
5            include the following: operation and maintenance 
6            expenses; fully allocated overhead costs, which 
7            shall be allocated using the methodology developed 
8            by the Institute for Nuclear Power Operations; 
9            fuel expenditures; non-fuel capital expenditures; 
10            spent fuel expenditures; a return on working 
11            capital; the cost of operational and market risks 
12            that could be avoided by ceasing operation; and 
13            any other costs necessary for continued 
14            operations, provided that "necessary" means, for 
15            purposes of this item (iii), that the costs could 
16            reasonably be avoided only by ceasing operations 
17            of the zero emission facility; and
18                (iv) a commitment to continue operating, for 
19            the duration of the contract or contracts executed 
20            under the procurement held under this subsection 
21            (d-5), the zero emission facility that produces 
22            the zero emission credits to be procured in the 
23            procurement.
24            The information described in item (iii) of this 
25        subparagraph (A) may be submitted on a confidential 
26        basis and shall be treated and maintained by the 
 
 
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1        Agency, the procurement administrator, and the 
2        Commission as confidential and proprietary and exempt 
3        from disclosure under subparagraphs (a) and (g) of 
4        paragraph (1) of Section 7 of the Freedom of 
5        Information Act. The Office of Attorney General shall 
6        have access to, and maintain the confidentiality of, 
7        such information pursuant to Section 6.5 of the 
8        Attorney General Act. 
9            (B) The price for each zero emission credit 
10        procured under this subsection (d-5) for each delivery 
11        year shall be in an amount that equals the Social Cost 
12        of Carbon, expressed on a price per megawatthour 
13        basis. However, to ensure that the procurement remains 
14        affordable to retail customers in this State if 
15        electricity prices increase, the price in an 
16        applicable delivery year shall be reduced below the 
17        Social Cost of Carbon by the amount ("Price 
18        Adjustment") by which the market price index for the 
19        applicable delivery year exceeds the baseline market 
20        price index for the consecutive 12-month period ending 
21        May 31, 2016. If the Price Adjustment is greater than 
22        or equal to the Social Cost of Carbon in an applicable 
23        delivery year, then no payments shall be due in that 
24        delivery year. The components of this calculation are 
25        defined as follows:
26                (i) Social Cost of Carbon: The Social Cost of 
 
 
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1            Carbon is $16.50 per megawatthour, which is based 
2            on the U.S. Interagency Working Group on Social 
3            Cost of Carbon's price in the August 2016 
4            Technical Update using a 3% discount rate, 
5            adjusted for inflation for each year of the 
6            program. Beginning with the delivery year 
7            commencing June 1, 2023, the price per 
8            megawatthour shall increase by $1 per 
9            megawatthour, and continue to increase by an 
10            additional $1 per megawatthour each delivery year 
11            thereafter.
12                (ii) Baseline market price index: The baseline 
13            market price index for the consecutive 12-month 
14            period ending May 31, 2016 is $31.40 per 
15            megawatthour, which is based on the sum of (aa) 
16            the average day-ahead energy price across all 
17            hours of such 12-month period at the PJM 
18            Interconnection LLC Northern Illinois Hub, (bb) 
19            50% multiplied by the Base Residual Auction, or 
20            its successor, capacity price for the rest of the 
21            RTO zone group determined by PJM Interconnection 
22            LLC, divided by 24 hours per day, and (cc) 50% 
23            multiplied by the Planning Resource Auction, or 
24            its successor, capacity price for Zone 4 
25            determined by the Midcontinent Independent System 
26            Operator, Inc., divided by 24 hours per day. 
 
 
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1                (iii) Market price index: The market price 
2            index for a delivery year shall be the sum of 
3            projected energy prices and projected capacity 
4            prices determined as follows:
5                    (aa) Projected energy prices: the 
6                projected energy prices for the applicable 
7                delivery year shall be calculated once for the 
8                year using the forward market price for the 
9                PJM Interconnection, LLC Northern Illinois 
10                Hub. The forward market price shall be 
11                calculated as follows: the energy forward 
12                prices for each month of the applicable 
13                delivery year averaged for each trade date 
14                during the calendar year immediately preceding 
15                that delivery year to produce a single energy 
16                forward price for the delivery year. The 
17                forward market price calculation shall use 
18                data published by the Intercontinental 
19                Exchange, or its successor.
20                    (bb) Projected capacity prices:
21                        (I) For the delivery years commencing 
22                    June 1, 2017, June 1, 2018, and June 1, 
23                    2019, the projected capacity price shall 
24                    be equal to the sum of (1) 50% multiplied 
25                    by the Base Residual Auction, or its 
26                    successor, price for the rest of the RTO 
 
 
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1                    zone group as determined by PJM 
2                    Interconnection LLC, divided by 24 hours 
3                    per day and, (2) 50% multiplied by the 
4                    resource auction price determined in the 
5                    resource auction administered by the 
6                    Midcontinent Independent System Operator, 
7                    Inc., in which the largest percentage of 
8                    load cleared for Local Resource Zone 4, 
9                    divided by 24 hours per day, and where 
10                    such price is determined by the 
11                    Midcontinent Independent System Operator, 
12                    Inc.
13                        (II) For the delivery year commencing 
14                    June 1, 2020, and each year thereafter, 
15                    the projected capacity price shall be 
16                    equal to the sum of (1) 50% multiplied by 
17                    the Base Residual Auction, or its 
18                    successor, price for the ComEd zone as 
19                    determined by PJM Interconnection LLC, 
20                    divided by 24 hours per day, and (2) 50% 
21                    multiplied by the resource auction price 
22                    determined in the resource auction 
23                    administered by the Midcontinent 
24                    Independent System Operator, Inc., in 
25                    which the largest percentage of load 
26                    cleared for Local Resource Zone 4, divided 
 
 
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1                    by 24 hours per day, and where such price 
2                    is determined by the Midcontinent 
3                    Independent System Operator, Inc.
4            For purposes of this subsection (d-5):
5                "Rest of the RTO" and "ComEd Zone" shall have 
6            the meaning ascribed to them by PJM 
7            Interconnection, LLC. 
8                "RTO" means regional transmission 
9            organization. 
10            (C) No later than 45 days after June 1, 2017 (the 
11        effective date of Public Act 99-906), the Agency shall 
12        publish its proposed zero emission standard 
13        procurement plan. The plan shall be consistent with 
14        the provisions of this paragraph (1) and shall provide 
15        that winning bids shall be selected based on public 
16        interest criteria that include, but are not limited 
17        to, minimizing carbon dioxide emissions that result 
18        from electricity consumed in Illinois and minimizing 
19        sulfur dioxide, nitrogen oxide, and particulate matter 
20        emissions that adversely affect the citizens of this 
21        State. In particular, the selection of winning bids 
22        shall take into account the incremental environmental 
23        benefits resulting from the procurement, such as any 
24        existing environmental benefits that are preserved by 
25        the procurements held under Public Act 99-906 and 
26        would cease to exist if the procurements were not 
 
 
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1        held, including the preservation of zero emission 
2        facilities. The plan shall also describe in detail how 
3        each public interest factor shall be considered and 
4        weighted in the bid selection process to ensure that 
5        the public interest criteria are applied to the 
6        procurement and given full effect.
7            For purposes of developing the plan, the Agency 
8        shall consider any reports issued by a State agency, 
9        board, or commission under House Resolution 1146 of 
10        the 98th General Assembly and paragraph (4) of 
11        subsection (d) of this Section, as well as publicly 
12        available analyses and studies performed by or for 
13        regional transmission organizations that serve the 
14        State and their independent market monitors.
15            Upon publishing of the zero emission standard 
16        procurement plan, copies of the plan shall be posted 
17        and made publicly available on the Agency's website. 
18        All interested parties shall have 10 days following 
19        the date of posting to provide comment to the Agency on 
20        the plan. All comments shall be posted to the Agency's 
21        website. Following the end of the comment period, but 
22        no more than 60 days later than June 1, 2017 (the 
23        effective date of Public Act 99-906), the Agency shall 
24        revise the plan as necessary based on the comments 
25        received and file its zero emission standard 
26        procurement plan with the Commission.
 
 
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1            If the Commission determines that the plan will 
2        result in the procurement of cost-effective zero 
3        emission credits, then the Commission shall, after 
4        notice and hearing, but no later than 45 days after the 
5        Agency filed the plan, approve the plan or approve 
6        with modification. For purposes of this subsection 
7        (d-5), "cost effective" means the projected costs of 
8        procuring zero emission credits from zero emission 
9        facilities do not cause the limit stated in paragraph 
10        (2) of this subsection to be exceeded.
11            (C-5) As part of the Commission's review and 
12        acceptance or rejection of the procurement results, 
13        the Commission shall, in its public notice of 
14        successful bidders:
15                (i) identify how the winning bids satisfy the 
16            public interest criteria described in subparagraph 
17            (C) of this paragraph (1) of minimizing carbon 
18            dioxide emissions that result from electricity 
19            consumed in Illinois and minimizing sulfur 
20            dioxide, nitrogen oxide, and particulate matter 
21            emissions that adversely affect the citizens of 
22            this State;
23                (ii) specifically address how the selection of 
24            winning bids takes into account the incremental 
25            environmental benefits resulting from the 
26            procurement, including any existing environmental 
 
 
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1            benefits that are preserved by the procurements 
2            held under Public Act 99-906 and would have ceased 
3            to exist if the procurements had not been held, 
4            such as the preservation of zero emission 
5            facilities;
6                (iii) quantify the environmental benefit of 
7            preserving the resources identified in item (ii) 
8            of this subparagraph (C-5), including the 
9            following:
10                    (aa) the value of avoided greenhouse gas 
11                emissions measured as the product of the zero 
12                emission facilities' output over the contract 
13                term multiplied by the U.S. Environmental 
14                Protection Agency eGrid subregion carbon 
15                dioxide emission rate and the U.S. Interagency 
16                Working Group on Social Cost of Carbon's price 
17                in the August 2016 Technical Update using a 3% 
18                discount rate, adjusted for inflation for each 
19                delivery year; and
20                    (bb) the costs of replacement with other 
21                zero carbon dioxide resources, including wind 
22                and photovoltaic, based upon the simple 
23                average of the following:
24                        (I) the price, or if there is more 
25                    than one price, the average of the prices, 
26                    paid for renewable energy credits from new 
 
 
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1                    utility-scale wind projects in the 
2                    procurement events specified in item (i) 
3                    of subparagraph (G) of paragraph (1) of 
4                    subsection (c) of this Section; and
5                        (II) the price, or if there is more 
6                    than one price, the average of the prices, 
7                    paid for renewable energy credits from new 
8                    utility-scale solar projects and 
9                    brownfield site photovoltaic projects in 
10                    the procurement events specified in item 
11                    (ii) of subparagraph (G) of paragraph (1) 
12                    of subsection (c) of this Section and, 
13                    after January 1, 2015, renewable energy 
14                    credits from photovoltaic distributed 
15                    generation projects in procurement events 
16                    held under subsection (c) of this Section. 
17            Each utility shall enter into binding contractual 
18        arrangements with the winning suppliers.
19            The procurement described in this subsection 
20        (d-5), including, but not limited to, the execution of 
21        all contracts procured, shall be completed no later 
22        than May 10, 2017. Based on the effective date of 
23        Public Act 99-906, the Agency and Commission may, as 
24        appropriate, modify the various dates and timelines 
25        under this subparagraph and subparagraphs (C) and (D) 
26        of this paragraph (1). The procurement and plan 
 
 
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1        approval processes required by this subsection (d-5) 
2        shall be conducted in conjunction with the procurement 
3        and plan approval processes required by subsection (c) 
4        of this Section and Section 16-111.5 of the Public 
5        Utilities Act, to the extent practicable. 
6        Notwithstanding whether a procurement event is 
7        conducted under Section 16-111.5 of the Public 
8        Utilities Act, the Agency shall immediately initiate a 
9        procurement process on June 1, 2017 (the effective 
10        date of Public Act 99-906).
11            (D) Following the procurement event described in 
12        this paragraph (1) and consistent with subparagraph 
13        (B) of this paragraph (1), the Agency shall calculate 
14        the payments to be made under each contract for the 
15        next delivery year based on the market price index for 
16        that delivery year. The Agency shall publish the 
17        payment calculations no later than May 25, 2017 and 
18        every May 25 thereafter.
19            (E) Notwithstanding the requirements of this 
20        subsection (d-5), the contracts executed under this 
21        subsection (d-5) shall provide that the zero emission 
22        facility may, as applicable, suspend or terminate 
23        performance under the contracts in the following 
24        instances:
25                (i) A zero emission facility shall be excused 
26            from its performance under the contract for any 
 
 
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1            cause beyond the control of the resource, 
2            including, but not restricted to, acts of God, 
3            flood, drought, earthquake, storm, fire, 
4            lightning, epidemic, war, riot, civil disturbance 
5            or disobedience, labor dispute, labor or material 
6            shortage, sabotage, acts of public enemy, 
7            explosions, orders, regulations or restrictions 
8            imposed by governmental, military, or lawfully 
9            established civilian authorities, which, in any of 
10            the foregoing cases, by exercise of commercially 
11            reasonable efforts the zero emission facility 
12            could not reasonably have been expected to avoid, 
13            and which, by the exercise of commercially 
14            reasonable efforts, it has been unable to 
15            overcome. In such event, the zero emission 
16            facility shall be excused from performance for the 
17            duration of the event, including, but not limited 
18            to, delivery of zero emission credits, and no 
19            payment shall be due to the zero emission facility 
20            during the duration of the event.
21                (ii) A zero emission facility shall be 
22            permitted to terminate the contract if legislation 
23            is enacted into law by the General Assembly that 
24            imposes or authorizes a new tax, special 
25            assessment, or fee on the generation of 
26            electricity, the ownership or leasehold of a 
 
 
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1            generating unit, or the privilege or occupation of 
2            such generation, ownership, or leasehold of 
3            generation units by a zero emission facility. 
4            However, the provisions of this item (ii) do not 
5            apply to any generally applicable tax, special 
6            assessment or fee, or requirements imposed by 
7            federal law.
8                (iii) A zero emission facility shall be 
9            permitted to terminate the contract in the event 
10            that the resource requires capital expenditures in 
11            excess of $40,000,000 that were neither known nor 
12            reasonably foreseeable at the time it executed the 
13            contract and that a prudent owner or operator of 
14            such resource would not undertake.
15                (iv) A zero emission facility shall be 
16            permitted to terminate the contract in the event 
17            the Nuclear Regulatory Commission terminates the 
18            resource's license.
19            (F) If the zero emission facility elects to 
20        terminate a contract under subparagraph (E) of this 
21        paragraph (1), then the Commission shall reopen the 
22        docket in which the Commission approved the zero 
23        emission standard procurement plan under subparagraph 
24        (C) of this paragraph (1) and, after notice and 
25        hearing, enter an order acknowledging the contract 
26        termination election if such termination is consistent 
 
 
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1        with the provisions of this subsection (d-5).
2        (2) For purposes of this subsection (d-5), the amount 
3    paid per kilowatthour means the total amount paid for 
4    electric service expressed on a per kilowatthour basis. 
5    For purposes of this subsection (d-5), the total amount 
6    paid for electric service includes, without limitation, 
7    amounts paid for supply, transmission, distribution, 
8    surcharges, and add-on taxes.
9        Notwithstanding the requirements of this subsection 
10    (d-5), the contracts executed under this subsection (d-5) 
11    shall provide that the total of zero emission credits 
12    procured under a procurement plan shall be subject to the 
13    limitations of this paragraph (2). For each delivery year, 
14    the contractual volume receiving payments in such year 
15    shall be reduced for all retail customers based on the 
16    amount necessary to limit the net increase that delivery 
17    year to the costs of those credits included in the amounts 
18    paid by eligible retail customers in connection with 
19    electric service to no more than 1.65% of the amount paid 
20    per kilowatthour by eligible retail customers during the 
21    year ending May 31, 2009. The result of this computation 
22    shall apply to and reduce the procurement for all retail 
23    customers, and all those customers shall pay the same 
24    single, uniform cents per kilowatthour charge under 
25    subsection (k) of Section 16-108 of the Public Utilities 
26    Act. To arrive at a maximum dollar amount of zero emission 
 
 
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1    credits to be paid for the particular delivery year, the 
2    resulting per kilowatthour amount shall be applied to the 
3    actual amount of kilowatthours of electricity delivered by 
4    the electric utility in the delivery year immediately 
5    prior to the procurement, to all retail customers in its 
6    service territory. Unpaid contractual volume for any 
7    delivery year shall be paid in any subsequent delivery 
8    year in which such payments can be made without exceeding 
9    the amount specified in this paragraph (2). The 
10    calculations required by this paragraph (2) shall be made 
11    only once for each procurement plan year. Once the 
12    determination as to the amount of zero emission credits to 
13    be paid is made based on the calculations set forth in this 
14    paragraph (2), no subsequent rate impact determinations 
15    shall be made and no adjustments to those contract amounts 
16    shall be allowed. All costs incurred under those contracts 
17    and in implementing this subsection (d-5) shall be 
18    recovered by the electric utility as provided in this 
19    Section.
20        No later than June 30, 2019, the Commission shall 
21    review the limitation on the amount of zero emission 
22    credits procured under this subsection (d-5) and report to 
23    the General Assembly its findings as to whether that 
24    limitation unduly constrains the procurement of 
25    cost-effective zero emission credits. 
26        (3) Six years after the execution of a contract under 
 
 
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1    this subsection (d-5), the Agency shall determine whether 
2    the actual zero emission credit payments received by the 
3    supplier over the 6-year period exceed the Average ZEC 
4    Payment. In addition, at the end of the term of a contract 
5    executed under this subsection (d-5), or at the time, if 
6    any, a zero emission facility's contract is terminated 
7    under subparagraph (E) of paragraph (1) of this subsection 
8    (d-5), then the Agency shall determine whether the actual 
9    zero emission credit payments received by the supplier 
10    over the term of the contract exceed the Average ZEC 
11    Payment, after taking into account any amounts previously 
12    credited back to the utility under this paragraph (3). If 
13    the Agency determines that the actual zero emission credit 
14    payments received by the supplier over the relevant period 
15    exceed the Average ZEC Payment, then the supplier shall 
16    credit the difference back to the utility. The amount of 
17    the credit shall be remitted to the applicable electric 
18    utility no later than 120 days after the Agency's 
19    determination, which the utility shall reflect as a credit 
20    on its retail customer bills as soon as practicable; 
21    however, the credit remitted to the utility shall not 
22    exceed the total amount of payments received by the 
23    facility under its contract.
24        For purposes of this Section, the Average ZEC Payment 
25    shall be calculated by multiplying the quantity of zero 
26    emission credits delivered under the contract times the 
 
 
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1    average contract price. The average contract price shall 
2    be determined by subtracting the amount calculated under 
3    subparagraph (B) of this paragraph (3) from the amount 
4    calculated under subparagraph (A) of this paragraph (3), 
5    as follows:
6            (A) The average of the Social Cost of Carbon, as 
7        defined in subparagraph (B) of paragraph (1) of this 
8        subsection (d-5), during the term of the contract.
9            (B) The average of the market price indices, as 
10        defined in subparagraph (B) of paragraph (1) of this 
11        subsection (d-5), during the term of the contract, 
12        minus the baseline market price index, as defined in 
13        subparagraph (B) of paragraph (1) of this subsection 
14        (d-5).
15        If the subtraction yields a negative number, then the 
16    Average ZEC Payment shall be zero. 
17        (4) Cost-effective zero emission credits procured from 
18    zero emission facilities shall satisfy the applicable 
19    definitions set forth in Section 1-10 of this Act.
20        (5) The electric utility shall retire all zero 
21    emission credits used to comply with the requirements of 
22    this subsection (d-5).
23        (6) Electric utilities shall be entitled to recover 
24    all of the costs associated with the procurement of zero 
25    emission credits through an automatic adjustment clause 
26    tariff in accordance with subsection (k) and (m) of 
 
 
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1    Section 16-108 of the Public Utilities Act, and the 
2    contracts executed under this subsection (d-5) shall 
3    provide that the utilities' payment obligations under such 
4    contracts shall be reduced if an adjustment is required 
5    under subsection (m) of Section 16-108 of the Public 
6    Utilities Act.
7        (7) This subsection (d-5) shall become inoperative on 
8    January 1, 2028. 
9    (d-10) Nuclear Plant Assistance; carbon mitigation 
10credits.
11    (1) The General Assembly finds:
12        (A) The health, welfare, and prosperity of all 
13    Illinois citizens require that the State of Illinois act 
14    to avoid and not increase carbon emissions from electric 
15    generation sources while continuing to ensure affordable, 
16    stable, and reliable electricity to all citizens.
17        (B) Absent immediate action by the State to preserve 
18    existing carbon-free energy resources, those resources may 
19    retire, and the electric generation needs of Illinois' 
20    retail customers may be met instead by facilities that 
21    emit significant amounts of carbon pollution and other 
22    harmful air pollutants at a high social and economic cost 
23    until Illinois is able to develop other forms of clean 
24    energy.
25        (C) The General Assembly finds that nuclear power 
26    generation is necessary for the State's transition to 100% 
 
 
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1    clean energy, and ensuring continued operation of nuclear 
2    plants advances environmental and public health interests 
3    through providing carbon-free electricity while reducing 
4    the air pollution profile of the Illinois energy 
5    generation fleet.
6        (D) The clean energy attributes of nuclear generation 
7    facilities support the State in its efforts to achieve 
8    100% clean energy.
9        (E) The State currently invests in various forms of 
10    clean energy, including, but not limited to, renewable 
11    energy, energy efficiency, and low-emission vehicles, 
12    among others.
13        (F) The Environmental Protection Agency commissioned 
14    an independent audit which provided a detailed assessment 
15    of the financial condition of the Illinois nuclear fleet 
16    to evaluate its financial viability and whether the 
17    environmental benefits of such resources were at risk. The 
18    report identified the risk of losing the environmental 
19    benefits of several specific nuclear units. The report 
20    also identified that the LaSalle County Generating Station 
21    will continue to operate through 2026 and therefore is not 
22    eligible to participate in the carbon mitigation credit 
23    program.
24        (G) Nuclear plants provide carbon-free energy, which 
25    helps to avoid many health-related negative impacts for 
26    Illinois residents.
 
 
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1        (H) The procurement of carbon mitigation credits 
2    representing the environmental benefits of carbon-free 
3    generation will further the State's efforts at achieving 
4    100% clean energy and decarbonizing the electricity sector 
5    in a safe, reliable, and affordable manner. Further, the 
6    procurement of carbon emission credits will enhance the 
7    health and welfare of Illinois residents through decreased 
8    reliance on more highly polluting generation.
9        (I) The General Assembly therefore finds it necessary 
10    to establish carbon mitigation credits to ensure decreased 
11    reliance on more carbon-intensive energy resources, for 
12    transitioning to a fully decarbonized electricity sector, 
13    and to help ensure health and welfare of the State's 
14    residents.
15    (2) As used in this subsection:
16    "Baseline costs" means costs used to establish a customer 
17protection cap that have been evaluated through an independent 
18audit of a carbon-free energy resource conducted by the 
19Environmental Protection Agency that evaluated projected 
20annual costs for operation and maintenance expenses; fully 
21allocated overhead costs, which shall be allocated using the 
22methodology developed by the Institute for Nuclear Power 
23Operations; fuel expenditures; nonfuel capital expenditures; 
24spent fuel expenditures; a return on working capital; the cost 
25of operational and market risks that could be avoided by 
26ceasing operation; and any other costs necessary for continued 
 
 
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1operations, provided that "necessary" means, for purposes of 
2this definition, that the costs could reasonably be avoided 
3only by ceasing operations of the carbon-free energy resource.
4    "Carbon mitigation credit" means a tradable credit that 
5represents the carbon emission reduction attributes of one 
6megawatt-hour of energy produced from a carbon-free energy 
7resource.
8    "Carbon-free energy resource" means a generation facility 
9that: (1) is fueled by nuclear power; and (2) is 
10interconnected to PJM Interconnection, LLC.
11    (3) Procurement.
12        (A) Beginning with the delivery year commencing on 
13    June 1, 2022, the Agency shall, for electric utilities 
14    serving at least 3,000,000 retail customers in the State, 
15    seek to procure contracts for no more than approximately 
16    54,500,000 cost-effective carbon mitigation credits from 
17    carbon-free energy resources because such credits are 
18    necessary to support current levels of carbon-free energy 
19    generation and ensure the State meets its carbon dioxide 
20    emissions reduction goals. The Agency shall not make a 
21    partial award of a contract for carbon mitigation credits 
22    covering a fractional amount of a carbon-free energy 
23    resource's projected output.
24        (B) Each carbon-free energy resource that intends to 
25    participate in a procurement shall be required to submit 
26    to the Agency the following information for the resource 
 
 
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1    on or before the date established by the Agency:
2            (i) the in-service date and remaining useful life 
3        of the carbon-free energy resource;
4            (ii) the amount of power generated annually for 
5        each of the past 10 years, which shall be used to 
6        determine the capability of each facility;
7            (iii) a commitment to be reflected in any contract 
8        entered into pursuant to this subsection (d-10) to 
9        continue operating the carbon-free energy resource at 
10        a capacity factor of at least 88% annually on average 
11        for the duration of the contract or contracts executed 
12        under the procurement held under this subsection 
13        (d-10), except in an instance described in 
14        subparagraph (E) of paragraph (1) of subsection (d-5) 
15        of this Section or made impracticable as a result of 
16        compliance with law or regulation;
17            (iv) financial need and the risk of loss of the 
18        environmental benefits of such resource, which shall 
19        include the following information:
20                (I) the carbon-free energy resource's cost 
21            projections, expressed on a per megawatt-hour 
22            basis, over the next 5 delivery years, which shall 
23            include the following: operation and maintenance 
24            expenses; fully allocated overhead costs, which 
25            shall be allocated using the methodology developed 
26            by the Institute for Nuclear Power Operations; 
 
 
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1            fuel expenditures; nonfuel capital expenditures; 
2            spent fuel expenditures; a return on working 
3            capital; the cost of operational and market risks 
4            that could be avoided by ceasing operation; and 
5            any other costs necessary for continued 
6            operations, provided that "necessary" means, for 
7            purposes of this subitem (I), that the costs could 
8            reasonably be avoided only by ceasing operations 
9            of the carbon-free energy resource; and
10                (II) the carbon-free energy resource's revenue 
11            projections, including energy, capacity, ancillary 
12            services, any other direct State support, known or 
13            anticipated federal attribute credits, known or 
14            anticipated tax credits, and any other direct 
15            federal support.
16        The information described in this subparagraph (B) may 
17    be submitted on a confidential basis and shall be treated 
18    and maintained by the Agency, the procurement 
19    administrator, and the Commission as confidential and 
20    proprietary and exempt from disclosure under subparagraphs 
21    (a) and (g) of paragraph (1) of Section 7 of the Freedom of 
22    Information Act. The Office of the Attorney General shall 
23    have access to, and maintain the confidentiality of, such 
24    information pursuant to Section 6.5 of the Attorney 
25    General Act. 
26        (C) The Agency shall solicit bids for the contracts 
 
 
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1    described in this subsection (d-10) from carbon-free 
2    energy resources that have satisfied the requirements of 
3    subparagraph (B) of this paragraph (3). The contracts 
4    procured pursuant to a procurement event shall reflect, 
5    and be subject to, the following terms, requirements, and 
6    limitations:
7            (i) Contracts are for delivery of carbon 
8        mitigation credits, and are not energy or capacity 
9        sales contracts requiring physical delivery. Pursuant 
10        to item (iii), contract payments shall fully deduct 
11        the value of any monetized federal production tax 
12        credits, credits issued pursuant to a federal clean 
13        energy standard, and other federal credits if 
14        applicable.
15            (ii) Contracts for carbon mitigation credits shall 
16        commence with the delivery year beginning on June 1, 
17        2022 and shall be for a term of 5 delivery years 
18        concluding on May 31, 2027.
19            (iii) The price per carbon mitigation credit to be 
20        paid under a contract for a given delivery year shall 
21        be equal to an accepted bid price less the sum of:
22                (I) one of the following energy price indices, 
23            selected by the bidder at the time of the bid for 
24            the term of the contract:
25                    (aa) the weighted-average hourly day-ahead 
26                price for the applicable delivery year at the 
 
 
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1                busbar of all resources procured pursuant to 
2                this subsection (d-10), weighted by actual 
3                production from the resources; or
4                    (bb) the projected energy price for the 
5                PJM Interconnection, LLC Northern Illinois Hub 
6                for the applicable delivery year determined 
7                according to subitem (aa) of item (iii) of 
8                subparagraph (B) of paragraph (1) of 
9                subsection (d-5).
10                (II) the Base Residual Auction Capacity Price 
11            for the ComEd zone as determined by PJM 
12            Interconnection, LLC, divided by 24 hours per day, 
13            for the applicable delivery year for the first 3 
14            delivery years, and then any subsequent delivery 
15            years unless the PJM Interconnection, LLC applies 
16            the Minimum Offer Price Rule to participating 
17            carbon-free energy resources because they supply 
18            carbon mitigation credits pursuant to this Section 
19            at which time, upon notice by the carbon-free 
20            energy resource to the Commission and subject to 
21            the Commission's confirmation, the value under 
22            this subitem shall be zero, as further described 
23            in the carbon mitigation credit procurement plan; 
24            and
25                (III) any value of monetized federal tax 
26            credits, direct payments, or similar subsidy 
 
 
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1            provided to the carbon-free energy resource from 
2            any unit of government that is not already 
3            reflected in energy prices.
4            If the price-per-megawatt-hour calculation 
5        performed under item (iii) of this subparagraph (C) 
6        for a given delivery year results in a net positive 
7        value, then the electric utility counterparty to the 
8        contract shall multiply such net value by the 
9        applicable contract quantity and remit the amount to 
10        the supplier.
11            To protect retail customers from retail rate 
12        impacts that may arise upon the initiation of carbon 
13        policy changes, if the price-per-megawatt-hour 
14        calculation performed under item (iii) of this 
15        subparagraph (C) for a given delivery year results in 
16        a net negative value, then the supplier counterparty 
17        to the contract shall multiply such net value by the 
18        applicable contract quantity and remit such amount to 
19        the electric utility counterparty. The electric 
20        utility shall reflect such amounts remitted by 
21        suppliers as a credit on its retail customer bills as 
22        soon as practicable.
23            (iv) To ensure that retail customers in Northern 
24        Illinois do not pay more for carbon mitigation credits 
25        than the value such credits provide, and 
26        notwithstanding the provisions of this subsection 
 
 
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1        (d-10), the Agency shall not accept bids for contracts 
2        that exceed a customer protection cap equal to the 
3        baseline costs of carbon-free energy resources.
4            The baseline costs for the applicable year shall 
5        be the following:
6                (I) For the delivery year beginning June 1, 
7            2022, the baseline costs shall be an amount equal 
8            to $30.30 per megawatt-hour.
9                (II) For the delivery year beginning June 1, 
10            2023, the baseline costs shall be an amount equal 
11            to $32.50 per megawatt-hour.
12                (III) For the delivery year beginning June 1, 
13            2024, the baseline costs shall be an amount equal 
14            to $33.43 per megawatt-hour.
15                (IV) For the delivery year beginning June 1, 
16            2025, the baseline costs shall be an amount equal 
17            to $33.50 per megawatt-hour.
18                (V) For the delivery year beginning June 1, 
19            2026, the baseline costs shall be an amount equal 
20            to $34.50 per megawatt-hour.
21            An Environmental Protection Agency consultant 
22        forecast, included in a report issued April 14, 2021, 
23        projects that a carbon-free energy resource has the 
24        opportunity to earn on average approximately $30.28 
25        per megawatt-hour, for the sale of energy and capacity 
26        during the time period between 2022 and 2027. 
 
 
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1        Therefore, the sale of carbon mitigation credits 
2        provides the opportunity to receive an additional 
3        amount per megawatt-hour in addition to the projected 
4        prices for energy and capacity.
5            Although actual energy and capacity prices may 
6        vary from year-to-year, the General Assembly finds 
7        that this customer protection cap will help ensure 
8        that the cost of carbon mitigation credits will be 
9        less than its value, based upon the social cost of 
10        carbon identified in the Technical Support Document 
11        issued in February 2021 by the U.S. Interagency 
12        Working Group on Social Cost of Greenhouse Gases and 
13        the PJM Interconnection, LLC carbon dioxide marginal 
14        emission rate for 2020, and that a carbon-free energy 
15        resource receiving payment for carbon mitigation 
16        credits receives no more than necessary to keep those 
17        units in operation.
18        (D) No later than 7 days after the effective date of 
19    this amendatory Act of the 102nd General Assembly, the 
20    Agency shall publish its proposed carbon mitigation credit 
21    procurement plan. The Plan shall provide that winning bids 
22    shall be selected by taking into consideration which 
23    resources best match public interest criteria that 
24    include, but are not limited to, minimizing carbon dioxide 
25    emissions that result from electricity consumed in 
26    Illinois and minimizing sulfur dioxide, nitrogen oxide, 
 
 
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1    and particulate matter emissions that adversely affect the 
2    citizens of this State. The selection of winning bids 
3    shall also take into account the incremental environmental 
4    benefits resulting from the procurement or procurements, 
5    such as any existing environmental benefits that are 
6    preserved by a procurement held under this subsection 
7    (d-10) and would cease to exist if the procurement were 
8    not held, including the preservation of carbon-free energy 
9    resources. For those bidders having the same public 
10    interest criteria score, the relative ranking of such 
11    bidders shall be determined by price. The Plan shall 
12    describe in detail how each public interest factor shall 
13    be considered and weighted in the bid selection process to 
14    ensure that the public interest criteria are applied to 
15    the procurement. The Plan shall, to the extent practical 
16    and permissible by federal law, ensure that successful 
17    bidders make commercially reasonable efforts to apply for 
18    federal tax credits, direct payments, or similar subsidy 
19    programs that support carbon-free generation and for which 
20    the successful bidder is eligible. Upon publishing of the 
21    carbon mitigation credit procurement plan, copies of the 
22    plan shall be posted and made publicly available on the 
23    Agency's website. All interested parties shall have 7 days 
24    following the date of posting to provide comment to the 
25    Agency on the plan. All comments shall be posted to the 
26    Agency's website. Following the end of the comment period, 
 
 
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1    but no more than 19 days later than the effective date of 
2    this amendatory Act of the 102nd General Assembly, the 
3    Agency shall revise the plan as necessary based on the 
4    comments received and file its carbon mitigation credit 
5    procurement plan with the Commission.
6        (E) If the Commission determines that the plan is 
7    likely to result in the procurement of cost-effective 
8    carbon mitigation credits, then the Commission shall, 
9    after notice and hearing and opportunity for comment, but 
10    no later than 42 days after the Agency filed the plan, 
11    approve the plan or approve it with modification. For 
12    purposes of this subsection (d-10), "cost-effective" means 
13    carbon mitigation credits that are procured from 
14    carbon-free energy resources at prices that are within the 
15    limits specified in this paragraph (3). As part of the 
16    Commission's review and acceptance or rejection of the 
17    procurement results, the Commission shall, in its public 
18    notice of successful bidders:
19            (i) identify how the selected carbon-free energy 
20        resources satisfy the public interest criteria 
21        described in this paragraph (3) of minimizing carbon 
22        dioxide emissions that result from electricity 
23        consumed in Illinois and minimizing sulfur dioxide, 
24        nitrogen oxide, and particulate matter emissions that 
25        adversely affect the citizens of this State;
26            (ii) specifically address how the selection of 
 
 
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1        carbon-free energy resources takes into account the 
2        incremental environmental benefits resulting from the 
3        procurement, including any existing environmental 
4        benefits that are preserved by the procurements held 
5        under this amendatory Act of the 102nd General 
6        Assembly and would have ceased to exist if the 
7        procurements had not been held, such as the 
8        preservation of carbon-free energy resources;
9            (iii) quantify the environmental benefit of 
10        preserving the carbon-free energy resources procured 
11        pursuant to this subsection (d-10), including the 
12        following:
13                (I) an assessment value of avoided greenhouse 
14            gas emissions measured as the product of the 
15            carbon-free energy resources' output over the 
16            contract term, using generally accepted 
17            methodologies for the valuation of avoided 
18            emissions; and
19                (II) an assessment of costs of replacement 
20            with other carbon-free energy resources and 
21            renewable energy resources, including wind and 
22            photovoltaic generation, based upon an assessment 
23            of the prices paid for renewable energy credits 
24            through programs and procurements conducted 
25            pursuant to subsection (c) of Section 1-75 of this 
26            Act, and the additional storage necessary to 
 
 
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1            produce the same or similar capability of matching 
2            customer usage patterns.
3        (F) The procurements described in this paragraph (3), 
4    including, but not limited to, the execution of all 
5    contracts procured, shall be completed no later than 
6    December 3, 2021. The procurement and plan approval 
7    processes required by this paragraph (3) shall be 
8    conducted in conjunction with the procurement and plan 
9    approval processes required by Section 16-111.5 of the 
10    Public Utilities Act, to the extent practicable. However, 
11    the Agency and Commission may, as appropriate, modify the 
12    various dates and timelines under this subparagraph and 
13    subparagraphs (D) and (E) of this paragraph (3) to meet 
14    the December 3, 2021 contract execution deadline. 
15    Following the completion of such procurements, and 
16    consistent with this paragraph (3), the Agency shall 
17    calculate the payments to be made under each contract in a 
18    timely fashion.
19        (F-1) Costs incurred by the electric utility pursuant 
20    to a contract authorized by this subsection (d-10) shall 
21    be deemed prudently incurred and reasonable in amount, and 
22    the electric utility shall be entitled to full cost 
23    recovery pursuant to a tariff or tariffs filed with the 
24    Commission.
25        (G) The counterparty electric utility shall retire all 
26    carbon mitigation credits used to comply with the 
 
 
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1    requirements of this subsection (d-10).
2        (H) If a carbon-free energy resource is sold to 
3    another owner, the rights, obligations, and commitments 
4    under this subsection (d-10) shall continue to the 
5    subsequent owner.
6        (I) This subsection (d-10) shall become inoperative on 
7    January 1, 2028.
8    (d-20) Energy storage system portfolio standard.
9        (1) The General Assembly finds that the deployment of 
10    energy storage systems is necessary to successfully 
11    integrate high levels of renewable energy, to avoid the 
12    creation and increase of carbon emissions from electric 
13    generation sources, and to ensure affordable, stable, 
14    clean, reliable, and resilient electricity.
15        (2) The Agency shall develop an energy storage system 
16    resources procurement plan that includes the competitive 
17    procurement events, procurement programs, or both, as 
18    necessary (i) to meet the goals set forth in this 
19    subsection (d-20), (ii) to meet the planning requirements 
20    established under Sections 16-201 and 16-202 of the Public 
21    Utilities Act, (iii) to meet the clean energy policy 
22    established by Public Act 102-662, and (iv) to cause 
23    electric utilities serving more than 300,000 customers in 
24    the State as of January 1, 2019 to contract for energy 
25    storage resources. The energy storage system resources 
26    procurement plan approval processes shall be conducted 
 
 
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1    consistent with the processes outlined in paragraph (6) of 
2    subsection (b) of Section 16-111.5 of the Public Utilities 
3    Act, with the initial energy storage system resources 
4    procurement plan released for comment in calendar year 
5    2027. The Agency shall review and may revise the energy 
6    storage system resources procurement plan at least every 2 
7    years. The Agency shall establish, and the Commission 
8    shall approve or approve as modified, an energy storage 
9    system resources procurement plan that includes:
10            (A) storage targets in addition to the initial 
11        procurements specified in paragraph (3) of this 
12        subsection (d-20) at levels identified through the 
13        integrated resource planning process outlined in 
14        Section 16-202 of the Public Utilities Act;
15            (B) a bid selection process that is based on the 
16        bid price, when compared with an equal energy storage 
17        duration and interconnected to the same independent 
18        system operator (ISO) or regional transmission 
19        organization (RTO), and that may provide for 
20        consideration of the following:
21                (i) the project's viability and ability to 
22            meet or exceed operational date targets;
23                (ii) the developer's experience;
24                (iii) requirements for demonstration of 
25            binding site control that are sufficient for 
26            proposed energy storage facilities;
 
 
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1                (iv) the availability or dependence on any 
2            transmission expansion or upgrades needed; and
3                (v) other resource adequacy and reliability 
4            considerations;
5            (C) consideration of the need to ensure adequate, 
6        reliable, affordable, efficient, and environmentally 
7        sustainable electric service at the lowest total cost 
8        over time;
9            (D) proposals for the financial support of energy 
10        storage systems using contract models, which may 
11        include, but are not limited to, the following:
12                (i) an indexed storage credit procurement, 
13            including payments to energy storage system owners 
14            or operators with any offsets and refunds for 
15            potential energy and capacity revenues;
16                (ii) support for energy storage system 
17            resources through contract structures that do not 
18            create contractual obligations on utilities that 
19            are not contingent on full and timely cost 
20            recovery, that avoid negative financial impacts on 
21            the utilities, and that are agreed upon by the 
22            utilities; and
23                (iii) other approaches as deemed suitable by 
24            the Agency and the Commission; and
25            (E) consideration that the Agency may include a 
26        methodology that could prioritize procurement of 
 
 
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1        energy storage resources that are located in 
2        communities eligible to receive Energy Transition 
3        Community Grants pursuant to Section 10-20 of the 
4        Energy Community Reinvestment Act.    
5        In developing its procurement plan and conducting the 
6    storage procurements outlined in this paragraph (2) and in 
7    paragraph (3), the Agency may use the services of expert 
8    consulting firms identified in paragraphs (1) and (2) of 
9    subsection (a) of this Section.
10        (3) Notwithstanding whether an energy storage system 
11    resources procurement plan has been approved, the 
12    following provisions shall apply to the Agency's initial 
13    procurement of energy storage system resources under this 
14    subsection (d-20):
15            (A) The Agency shall conduct an initial energy 
16        storage procurement on or before August 26, 2026 or 90 
17        days after the effective date of this amendatory Act 
18        of the 104th General Assembly, whichever is earlier. 
19        For the purposes of this initial energy storage 
20        procurement, the Agency shall conduct a procurement 
21        that results in electric utilities that served more 
22        than 300,000 customers in the State as of January 1, 
23        2019 contracting for at least 1,038 megawatts of 
24        cost-effective stand-alone energy storage systems that 
25        can achieve commercial operation on or before December 
26        31, 2029 or an alternative date proposed by the Agency 
 
 
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1        that is no later than December 31, 2030. The 
2        procurement target shall be separated for projects 
3        interconnected within Midcontinent Independent System 
4        Operator Local Resource Zone 4 (MISO Zone 4) and for 
5        projects interconnected within the PJM 
6        Interconnection, LLC ComEd Locational Deliverability 
7        Area (PJM ComEd Area) as follows:
8                (i) 450 megawatts in MISO Zone 4; and
9                (ii) 588 megawatts in the PJM ComEd Area.
10            For purposes of this subsection (d-20), 
11        "stand-alone" means systems that are (i) separately 
12        metered by a revenue-quality meter that satisfies the 
13        requirements of the RTO; (ii) operate independently 
14        without constraints or hindrances from other 
15        generation units; and (iii) demonstrate the ability to 
16        charge and discharge independent of any generation 
17        unit output.    
18            (B) The Agency shall conduct a series of 
19        additional energy storage procurements that result in 
20        electric utilities contracting for energy storage 
21        resources in an amount of at least 3,000 megawatts of 
22        cumulative energy storage capacity for projects 
23        committed to reaching commercial operation on or 
24        before December 31, 2029, or an alternative date 
25        proposed by the Agency that is no later than December 
26        31, 2030, subject to extension for a delay due to 
 
 
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1        interconnection of the energy storage system, a delay 
2        in obtaining permits necessary to build or operate the 
3        energy storage system, or other circumstances at the 
4        discretion of the Agency.
5            The additional energy storage resources 
6        procurements shall be conducted in calendar years 
7        2026, 2027, 2028, and 2029 in a manner that ensures the 
8        quantities listed in this subparagraph (B), and as 
9        updated in the integrated resource plan approved by 
10        the Commission pursuant to Section 16-201 of the 
11        Public Utilities Act, are met in the specified 
12        timeframe. The procurements shall be conducted in a 
13        manner that maximizes projects available in the MISO 
14        and PJM queues, ensures the likelihood of project 
15        development through the development of project 
16        maturity requirements, enables sufficient competition 
17        for price competitiveness, and aligns to the extent 
18        practicable with regional transmission organization 
19        study phases. The procurements shall select projects 
20        interconnected to MISO Zone 4 and the PJM ComEd Area 
21        and shall follow either (i) a similar geographic split 
22        to the ratio of quantities established in subparagraph 
23        (A) of this paragraph (3), (ii) an alternative 
24        geographic split proposed by the Agency based on 
25        project availability in advanced stages of the MISO 
26        and PJM queues, or (iii) that is informed by MISO and 
 
 
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1        PJM planning activities, auctions, or reports that 
2        indicate capacity resource shortages or impending 
3        shortages and that reflect the assessments made 
4        through the processes outlined in subparagraph (A) of 
5        paragraph (2). The additional energy storage capacity 
6        procurements may be adjusted upward if determined 
7        necessary through the planning process outlined in 
8        Section 16-201 of the Public Utilities Act at times 
9        determined by the Commission.
10            (C) The initial energy storage resources 
11        procurement under subparagraph (A) of this paragraph 
12        (3) shall adopt a standard indexed storage credit 
13        contract modeled after the contract and follow a 
14        process modeled after the process included in the 
15        staff report submitted to the Governor, General 
16        Assembly, and Commission pursuant to subsection (g) of 
17        Section 16-135 of the Public Utilities Act on May 1, 
18        2025. In developing the procurement rules and 
19        procurement process for the initial procurement, the 
20        Agency shall provide an opportunity for comment on the 
21        indexed storage credit contract included in the May 1, 
22        2025 staff report and shall adopt modifications to the 
23        contract consistent with the process outlined in 
24        paragraph (2) of subsection (e) of Section 16-111.5 of 
25        the Public Utilities Act.
26            (D) For the additional energy storage resources 
 
 
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1        procurements conducted in accordance with subparagraph 
2        (B) of this paragraph (3), the Agency may, among other 
3        considerations, consider other contract structures if 
4        such contract structures and agreements do not create 
5        contractual obligations on utilities that are not 
6        contingent on full and timely cost recovery, avoid 
7        negative financial impacts on the utilities, and are 
8        agreed upon by the participating utility.
9            (E) The initial and additional energy storage 
10        resources procurements under this paragraph (3) shall 
11        solicit 20-year contracts.
12            (F) The Agency shall submit its proposed selection 
13        of successful bids for each procurement event pursuant 
14        to paragraphs (2) and (3) to the Commission for 
15        approval consistent with the processes outlined in 
16        Section 16-111.5 of the Public Utilities Act to the 
17        extent practicable.
18        (4) The energy storage system resources procurement 
19    plans developed by the Agency may consider alternatives to 
20    the initial and additional procurement terms described in 
21    paragraph (3) of this subsection (d-20), including, but 
22    not limited to:
23            (A) alternatives to the standard indexed storage 
24        credit contract used in the initial terms described in 
25        subparagraph (C) of paragraph (3) of this subsection 
26        (d-20);
 
 
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1            (B) energy storage systems that are not 
2        stand-alone;    
3            (C) proportionate allocations between MISO Zone 4 
4        and the PJM ComEd Area that are not based upon load 
5        share, including allocations reflecting the 
6        assessments made through the processes outlined in 
7        subparagraph (A) of paragraph (2);
8            (D) contract lengths other than 20 years;
9            (E) energy storage system durations other than 4 
10        hours; and
11            (F) energy storage systems connected to the 
12        distribution systems of the electric utilities.
13        The Agency may propose specific timelines for energy 
14    storage system resources procurements, which may differ 
15    across RTO zones, that are based in part upon a 
16    consideration of (i) the timing of the release of 
17    interconnection cost information through both MISO and PJM 
18    interconnection queue processes, (ii) factors that 
19    maximize the likelihood of successful project development, 
20    (iii) enabling sufficient competition for price 
21    competitiveness, and (iv) aligning to the extent 
22    practicable with RTO study phases.
23        (5) The Agency shall procure cost-effective energy 
24    storage credits or other contract instruments intended to 
25    facilitate the successful development of energy storage 
26    projects. The procurement administrator shall establish 
 
 
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1    confidential price benchmarks based on publicly available 
2    data on regional technology costs. Confidential price 
3    benchmarks shall be developed by the procurement 
4    administrator, in consultation with Commission staff, 
5    Agency staff, and the procurement monitor, and shall be 
6    subject to Commission review and approval. Price 
7    benchmarks shall reflect development costs, financing 
8    costs, and related costs resulting from requirements 
9    imposed through other provisions of State law. As used in 
10    this paragraph (5), "cost-effective" means a bidder's bid 
11    price that does not exceed confidential price benchmarks.
12        (6) All procurements under this subsection (d-20) 
13    shall comply with the geographic requirements in 
14    subparagraph (I) of paragraph (1) of subsection (c) of 
15    Section 1-75 and shall follow the procurement processes 
16    and procedures described in this Section and Section 
17    16-111.5 of the Public Utilities Act, to the extent 
18    practicable. The processes and procedures may be expedited 
19    to accommodate the schedule established by this Section. 
20    The Agency shall require all bidders to pay to the Agency a 
21    nonrefundable deposit determined by the Agency and no less 
22    than $10,000 per bid as practical. The Agency may also 
23    assess bidder and supplier fees to cover the cost of 
24    procurement events and develop collateral requirements to 
25    maximize the likelihood of successful project development. 
26    Bidders in the initial and additional procurements 
 
 
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1    described in paragraph (3) of this subsection (d-20) shall 
2    also demonstrate experience in developing to commercial 
3    readiness. As used in this paragraph (6), "developing to 
4    commercial readiness" means having notice to proceed in 
5    owning or operating energy facilities with a combined 
6    nameplate capacity of at least 100 megawatts.
7        (7) In order to advance priority access to the clean 
8    energy economy for businesses and workers from communities 
9    that have been excluded from economic opportunities in the 
10    energy sector, have been subject to disproportionate 
11    levels of pollution, and have disproportionately 
12    experienced negative public health outcomes, the Agency 
13    shall apply its equity accountability system and minimum 
14    equity standards established under subsections (c-10), 
15    (c-15), (c-20), (c-25), and (c-30) of this Section to 
16    energy storage procurement and programs and may include 
17    any proposed modifications to the equity accountability 
18    system and minimum equity standards that may be warranted 
19    with respect to energy storage resources in its plan 
20    submission to the Commission under Section 16-111.5 of the 
21    Public Utilities Act.
22        (8) Projects shall be developed in compliance with the 
23    prevailing wage and project labor agreement requirements 
24    for renewable energy projects in subparagraph (Q) of 
25    paragraph (1) of subsection (c) of Section 1-75.
26        (9) An entity operating an energy storage facility 
 
 
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1    shall demonstrate that it has entered into a labor peace 
2    agreement with a bona fide labor organization that is 
3    actively engaged in representing its employees. The labor 
4    peace agreement shall apply to the employees necessary for 
5    the ongoing maintenance and operation of the energy 
6    storage facility. The existence of a labor peace agreement 
7    shall be an ongoing material condition of an entity's 
8    authorization to maintain and operate the energy storage 
9    facility.    
10        (10) In order to promote the competitive development 
11    of energy storage systems in furtherance of the State's 
12    interest in the health, safety, and welfare of its 
13    residents, storage credits shall not be eligible to be 
14    selected under this subsection (d-20) if the energy 
15    storage resources are sourced from an energy storage 
16    system whose costs were being recovered through rates 
17    regulated by the State or any other state or states on or 
18    after January 1, 2017. No entity shall be permitted to bid 
19    unless it certifies to the Agency that it is not an 
20    electric utility, as defined in Section 16-102 of the 
21    Public Utilities Act, serving more than 10,000 customers 
22    in the State.
23        (11) The Agency shall require, as a prerequisite to 
24    payment for any storage credits, that the winning bidder 
25    provide the Agency or its designee a copy of the 
26    interconnection agreement under which the applicable 
 
 
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1    energy storage system is connected to the transmission or 
2    distribution system.
3        (12) Contracts shall provide that, if the cost 
4    recovery mechanism referenced in subsection (k) of Section 
5    16-108 of the Public Utilities Act remains in full force 
6    without amendment or the utility is otherwise authorized 
7    or entitled to full, prompt, and uninterrupted recovery of 
8    its costs through any other mechanism, then such seller 
9    shall be entitled to full, prompt, and uninterrupted 
10    payment under the applicable contract notwithstanding the 
11    application of this paragraph (12).    
12    (e) The draft procurement plans are subject to public 
13comment, as required by Section 16-111.5 of the Public 
14Utilities Act.
15    (f) The Agency shall submit the final procurement plan to 
16the Commission. The Agency shall revise a procurement plan if 
17the Commission determines that it does not meet the standards 
18set forth in Section 16-111.5 of the Public Utilities Act.
19    (g) The Agency shall assess fees to each affected utility 
20to recover the costs incurred in preparation of procurement 
21plans and in the operation of programs the annual procurement 
22plan for the utility.
23    (h) The Agency shall assess fees to each bidder to recover 
24the costs incurred in connection with a competitive 
25procurement process.
26    (i) A renewable energy credit, carbon emission credit, 
 
 
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1zero emission credit, or carbon mitigation credit can only be 
2used once to comply with a single portfolio or other standard 
3as set forth in subsection (c), subsection (d), or subsection 
4(d-5) of this Section, respectively. A renewable energy 
5credit, carbon emission credit, zero emission credit, or 
6carbon mitigation credit cannot be used to satisfy the 
7requirements of more than one standard. If more than one type 
8of credit is issued for the same megawatt hour of energy, only 
9one credit can be used to satisfy the requirements of a single 
10standard. After such use, the credit must be retired together 
11with any other credits issued for the same megawatt hour of 
12energy. 
13(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24; 
14103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)
 
15    (20 ILCS 3855/1-125)
16    Sec. 1-125. Agency annual reports. 
17    (a) By March February 15 of each year, the Agency shall 
18report annually to the Governor and the General Assembly on 
19the operations and transactions of the Agency. The annual 
20report shall include, but not be limited to, each of the 
21following:
22        (1) The average quantity, price, and term of all 
23    contracts for electricity procured under the procurement 
24    plans for electric utilities.
25        (2) (Blank).
 
 
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1        (3) The quantity, price, and rate impact of all energy 
2    efficiency and demand response measures purchased for 
3    electric utilities, and any measures included in the 
4    procurement plan pursuant to Section 16-111.5B of the 
5    Public Utilities Act.
6        (4) The amount of power and energy produced by each 
7    Agency facility.
8        (5) The quantity of electricity supplied by each 
9    Agency facility to municipal electric systems, 
10    governmental aggregators, or rural electric cooperatives 
11    in Illinois.
12        (6) The revenues as allocated by the Agency to each 
13    facility.
14        (7) The costs as allocated by the Agency to each 
15    facility.
16        (8) The accumulated depreciation for each facility.
17        (9) The status of any projects under development.
18        (10) Basic financial and operating information 
19    specifically detailed for the reporting year and 
20    including, but not limited to, income and expense 
21    statements, balance sheets, and changes in financial 
22    position, all in accordance with generally accepted 
23    accounting principles, debt structure, and a summary of 
24    funds on a cash basis.
25        (11) The average quantity, price, contract type and 
26    term, and rate impact of all renewable resources procured 
 
 
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1    under the long-term renewable resources procurement plans 
2    for electric utilities. 
3        (12) A comparison of the costs associated with the 
4    Agency's procurement of renewable energy resources to (A) 
5    the Agency's costs associated with electricity generated 
6    by other types of generation facilities and (B) the 
7    benefits associated with the Agency's procurement of 
8    renewable energy resources.
9        (13) An analysis of the rate impacts associated with 
10    the Illinois Power Agency's procurement of renewable 
11    resources, including, but not limited to, any long-term 
12    contracts, on the eligible retail customers of electric 
13    utilities. The analysis shall include the Agency's 
14    estimate of the total dollar impact that the Agency's 
15    procurement of renewable resources has had on the annual 
16    electricity bills of the customer classes that comprise 
17    each eligible retail customer class taking service from an 
18    electric utility.
19        (14) (Blank).
20    (b) In addition to reporting on the transactions and 
21operations of the Agency, the Agency shall also endeavor to 
22report on the following items through its annual report, 
23recognizing that full and accurate information may not be 
24available for certain items:
25        (1) The overall nameplate capacity amount of installed 
26    and scheduled renewable energy generation capacity 
 
 
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1    physically located in Illinois.
2        (2) The percentage of installed and scheduled 
3    renewable energy generation capacity as a share of overall 
4    electricity generation capacity physically located in 
5    Illinois.
6        (3) The amount of megawatt hours produced by renewable 
7    energy generation capacity physically located in Illinois 
8    for the preceding delivery year.
9        (4) The percentage of megawatt hours produced by 
10    renewable energy generation capacity physically located in 
11    Illinois as a share of overall electricity generation from 
12    facilities physically located in Illinois for the 
13    preceding delivery year and as a share of retail 
14    electricity sales in Illinois.
15        (5) The renewable portfolio standard expenditures made 
16    pursuant to paragraph (1) of subsection (c) of Section 
17    1-75 and the total scheduled and installed renewable 
18    generation capacity expected to result from these 
19    investments. This information shall include the total cost 
20    of REC delivery contracts of the renewable portfolio 
21    standard by project category, including, but not limited 
22    to, renewable energy credits delivery contracts entered 
23    into pursuant to subparagraphs (C), (G), (K), and (R) of 
24    paragraph (1) of subsection (c) Section 1-75. The Agency 
25    shall also report on the total amount of customer load 
26    featuring renewable portfolio standard compliance 
 
 
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1    obligations scheduled to be met by self-direct customers 
2    pursuant to subparagraph (R) of paragraph (1) of 
3    subsection (c) of Section 1-75, as well as the minimum 
4    annual quantities of renewable energy credits scheduled to 
5    be retired by those customers and amount of installed 
6    renewable energy generating capacity used to meet the 
7    requirements of subparagraph (R) of paragraph (1) of 
8    subsection (c) of Section 1-75.
9    The Agency may seek assistance from the Illinois Commerce 
10Commission in developing its annual report and may also retain 
11the services of its expert consulting firm used to develop its 
12procurement plans as outlined in paragraph (1) of subsection 
13(a) of Section 1-75. Confidential or commercially sensitive 
14business information provided by retail customers, alternative 
15retail electric suppliers, or other parties shall be kept 
16confidential by the Agency consistent with Section 1-120, but 
17may be publicly reported in aggregate form. 
18(Source: P.A. 102-662, eff. 9-15-21.)
 
19    Section 90-14. The State Finance Act is amended by 
20changing Sections 5.427 and 8.3 as follows:
 
21    (30 ILCS 105/5.427)
22    Sec. 5.427. The Electric Vehicle Rebate and Charging Fund. 
23(Source: P.A. 102-662, eff. 9-15-21.)
 
 
 
10400SB0025ham003- 412 -LRB104 07069 AAS 29208 a

1    (30 ILCS 105/8.3)
2    Sec. 8.3. Money in the Road Fund shall, if and when the 
3State of Illinois incurs any bonded indebtedness for the 
4construction of permanent highways, be set aside and used for 
5the purpose of paying and discharging annually the principal 
6and interest on that bonded indebtedness then due and payable, 
7and for no other purpose. The surplus, if any, in the Road Fund 
8after the payment of principal and interest on that bonded 
9indebtedness then annually due shall be used as follows:
10        first -- to pay the cost of administration of Chapters 
11    2 through 10 of the Illinois Vehicle Code, except the cost 
12    of administration of Articles I and II of Chapter 3 of that 
13    Code, and to pay the costs of the Executive Ethics 
14    Commission for oversight and administration of the Chief 
15    Procurement Officer appointed under paragraph (2) of 
16    subsection (a) of Section 10-20 of the Illinois 
17    Procurement Code for transportation; and
18        secondly -- for expenses of the Department of 
19    Transportation for construction, reconstruction, 
20    improvement, repair, maintenance, operation, and 
21    administration of highways in accordance with the 
22    provisions of laws relating thereto, or for any purpose 
23    related or incident to and connected therewith, including 
24    the separation of grades of those highways with railroads 
25    and with highways and including the payment of awards made 
26    by the Illinois Workers' Compensation Commission under the 
 
 
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1    terms of the Workers' Compensation Act or Workers' 
2    Occupational Diseases Act for injury or death of an 
3    employee of the Division of Highways in the Department of 
4    Transportation; or for the acquisition of land and the 
5    erection of buildings for highway purposes, including the 
6    acquisition of highway right-of-way or for investigations 
7    to determine the reasonably anticipated future highway 
8    needs; or for making of surveys, plans, specifications and 
9    estimates for and in the construction and maintenance of 
10    flight strips and of highways necessary to provide access 
11    to military and naval reservations, to defense industries 
12    and defense-industry sites, and to the sources of raw 
13    materials and for replacing existing highways and highway 
14    connections shut off from general public use at military 
15    and naval reservations and defense-industry sites, or for 
16    the purchase of right-of-way, except that the State shall 
17    be reimbursed in full for any expense incurred in building 
18    the flight strips; or for the operating and maintaining of 
19    highway garages; or for patrolling and policing the public 
20    highways and conserving the peace; or for the operating 
21    expenses of the Department relating to the administration 
22    of public transportation programs; or, during fiscal year 
23    2024, for the purposes of a grant not to exceed $9,108,400 
24    to the Regional Transportation Authority on behalf of PACE 
25    for the purpose of ADA/Para-transit expenses; or, during 
26    fiscal year 2025, for the purposes of a grant not to exceed 
 
 
10400SB0025ham003- 414 -LRB104 07069 AAS 29208 a

1    $10,020,000 to the Regional Transportation Authority on 
2    behalf of PACE for the purpose of ADA/Para-transit 
3    expenses; or for any of those purposes or any other 
4    purpose that may be provided by law.
5    Appropriations for any of those purposes are payable from 
6the Road Fund. Appropriations may also be made from the Road 
7Fund for the administrative expenses of any State agency that 
8are related to motor vehicles or arise from the use of motor 
9vehicles.
10    Beginning with fiscal year 1980 and thereafter, no Road 
11Fund monies shall be appropriated to the following Departments 
12or agencies of State government for administration, grants, or 
13operations; but this limitation is not a restriction upon 
14appropriating for those purposes any Road Fund monies that are 
15eligible for federal reimbursement:
16        1. Department of Public Health;
17        2. Department of Transportation, only with respect to 
18    subsidies for one-half fare Student Transportation and 
19    Reduced Fare for Elderly, except fiscal year 2024 when no 
20    more than $19,063,500 may be expended and except fiscal 
21    year 2025 when no more than $20,969,900 may be expended;
22        3. Department of Central Management Services, except 
23    for expenditures incurred for group insurance premiums of 
24    appropriate personnel;
25        4. Judicial Systems and Agencies.
26    Beginning with fiscal year 1981 and thereafter, no Road 
 
 
10400SB0025ham003- 415 -LRB104 07069 AAS 29208 a

1Fund monies shall be appropriated to the following Departments 
2or agencies of State government for administration, grants, or 
3operations; but this limitation is not a restriction upon 
4appropriating for those purposes any Road Fund monies that are 
5eligible for federal reimbursement:
6        1. Illinois State Police, except for expenditures with 
7    respect to the Division of Patrol and Division of Criminal 
8    Investigation;
9        2. Department of Transportation, only with respect to 
10    Intercity Rail Subsidies, except fiscal year 2024 when no 
11    more than $60,000,000 may be expended and except fiscal 
12    year 2025 when no more than $67,000,000 may be expended, 
13    and Rail Freight Services.
14    Beginning with fiscal year 1982 and thereafter, no Road 
15Fund monies shall be appropriated to the following Departments 
16or agencies of State government for administration, grants, or 
17operations; but this limitation is not a restriction upon 
18appropriating for those purposes any Road Fund monies that are 
19eligible for federal reimbursement: Department of Central 
20Management Services, except for awards made by the Illinois 
21Workers' Compensation Commission under the terms of the 
22Workers' Compensation Act or Workers' Occupational Diseases 
23Act for injury or death of an employee of the Division of 
24Highways in the Department of Transportation.
25    Beginning with fiscal year 1984 and thereafter, no Road 
26Fund monies shall be appropriated to the following Departments 
 
 
10400SB0025ham003- 416 -LRB104 07069 AAS 29208 a

1or agencies of State government for administration, grants, or 
2operations; but this limitation is not a restriction upon 
3appropriating for those purposes any Road Fund monies that are 
4eligible for federal reimbursement:
5        1. Illinois State Police, except not more than 40% of 
6    the funds appropriated for the Division of Patrol and 
7    Division of Criminal Investigation;
8        2. State Officers.
9    Beginning with fiscal year 1984 and thereafter, no Road 
10Fund monies shall be appropriated to any Department or agency 
11of State government for administration, grants, or operations 
12except as provided hereafter; but this limitation is not a 
13restriction upon appropriating for those purposes any Road 
14Fund monies that are eligible for federal reimbursement. It 
15shall not be lawful to circumvent the above appropriation 
16limitations by governmental reorganization or other methods. 
17Appropriations shall be made from the Road Fund only in 
18accordance with the provisions of this Section.
19    Money in the Road Fund shall, if and when the State of 
20Illinois incurs any bonded indebtedness for the construction 
21of permanent highways, be set aside and used for the purpose of 
22paying and discharging during each fiscal year the principal 
23and interest on that bonded indebtedness as it becomes due and 
24payable as provided in the General Obligation Bond Act, and 
25for no other purpose. The surplus, if any, in the Road Fund 
26after the payment of principal and interest on that bonded 
 
 
10400SB0025ham003- 417 -LRB104 07069 AAS 29208 a

1indebtedness then annually due shall be used as follows:
2        first -- to pay the cost of administration of Chapters 
3    2 through 10 of the Illinois Vehicle Code; and
4        secondly -- no Road Fund monies derived from fees, 
5    excises, or license taxes relating to registration, 
6    operation and use of vehicles on public highways or to 
7    fuels used for the propulsion of those vehicles, shall be 
8    appropriated or expended other than for costs of 
9    administering the laws imposing those fees, excises, and 
10    license taxes, statutory refunds and adjustments allowed 
11    thereunder, administrative costs of the Department of 
12    Transportation, including, but not limited to, the 
13    operating expenses of the Department relating to the 
14    administration of public transportation programs, payment 
15    of debts and liabilities incurred in construction and 
16    reconstruction of public highways and bridges, acquisition 
17    of rights-of-way for and the cost of construction, 
18    reconstruction, maintenance, repair, and operation of 
19    public highways and bridges under the direction and 
20    supervision of the State, political subdivision, or 
21    municipality collecting those monies, or during fiscal 
22    year 2024 for the purposes of a grant not to exceed 
23    $9,108,400 to the Regional Transportation Authority on 
24    behalf of PACE for the purpose of ADA/Para-transit 
25    expenses, or during fiscal year 2025 for the purposes of a 
26    grant not to exceed $10,020,000 to the Regional 
 
 
10400SB0025ham003- 418 -LRB104 07069 AAS 29208 a

1    Transportation Authority on behalf of PACE for the purpose 
2    of ADA/Para-transit expenses, and the costs for patrolling 
3    and policing the public highways (by the State, political 
4    subdivision, or municipality collecting that money) for 
5    enforcement of traffic laws. The separation of grades of 
6    such highways with railroads and costs associated with 
7    protection of at-grade highway and railroad crossing shall 
8    also be permissible.
9    Appropriations for any of such purposes are payable from 
10the Road Fund or the Grade Crossing Protection Fund as 
11provided in Section 8 of the Motor Fuel Tax Law.
12    Except as provided in this paragraph, beginning with 
13fiscal year 1991 and thereafter, no Road Fund monies shall be 
14appropriated to the Illinois State Police for the purposes of 
15this Section in excess of its total fiscal year 1990 Road Fund 
16appropriations for those purposes unless otherwise provided in 
17Section 5g of this Act. For fiscal years 2003, 2004, 2005, 
182006, and 2007 only, no Road Fund monies shall be appropriated 
19to the Department of State Police for the purposes of this 
20Section in excess of $97,310,000. For fiscal year 2008 only, 
21no Road Fund monies shall be appropriated to the Department of 
22State Police for the purposes of this Section in excess of 
23$106,100,000. For fiscal year 2009 only, no Road Fund monies 
24shall be appropriated to the Department of State Police for 
25the purposes of this Section in excess of $114,700,000. 
26Beginning in fiscal year 2010, no Road Fund moneys shall be 
 
 
10400SB0025ham003- 419 -LRB104 07069 AAS 29208 a

1appropriated to the Illinois State Police. It shall not be 
2lawful to circumvent this limitation on appropriations by 
3governmental reorganization or other methods unless otherwise 
4provided in Section 5g of this Act.
5    In fiscal year 1994, no Road Fund monies shall be 
6appropriated to the Secretary of State for the purposes of 
7this Section in excess of the total fiscal year 1991 Road Fund 
8appropriations to the Secretary of State for those purposes, 
9plus $9,800,000. It shall not be lawful to circumvent this 
10limitation on appropriations by governmental reorganization or 
11other method.
12    Beginning with fiscal year 1995 and thereafter, no Road 
13Fund monies shall be appropriated to the Secretary of State 
14for the purposes of this Section in excess of the total fiscal 
15year 1994 Road Fund appropriations to the Secretary of State 
16for those purposes. It shall not be lawful to circumvent this 
17limitation on appropriations by governmental reorganization or 
18other methods.
19    Beginning with fiscal year 2000, total Road Fund 
20appropriations to the Secretary of State for the purposes of 
21this Section shall not exceed the amounts specified for the 
22following fiscal years:
23    Fiscal Year 2000$80,500,000;
24    Fiscal Year 2001$80,500,000;
25    Fiscal Year 2002$80,500,000;
26    Fiscal Year 2003$130,500,000;
 
 
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1    Fiscal Year 2004$130,500,000;
2    Fiscal Year 2005$130,500,000; 
3    Fiscal Year 2006 $130,500,000; 
4    Fiscal Year 2007 $130,500,000; 
5    Fiscal Year 2008$130,500,000; 
6    Fiscal Year 2009 $130,500,000. 
7    For fiscal year 2010, no road fund moneys shall be 
8appropriated to the Secretary of State. 
9    Beginning in fiscal year 2011, moneys in the Road Fund 
10shall be appropriated to the Secretary of State for the 
11exclusive purpose of paying refunds due to overpayment of fees 
12related to Chapter 3 of the Illinois Vehicle Code unless 
13otherwise provided for by law. 
14    Beginning in fiscal year 2025, moneys in the Road Fund may 
15be appropriated to the Environmental Protection Agency for the 
16exclusive purpose of making deposits into the Electric Vehicle 
17Rebate and Charging Fund, subject to appropriation, to be used 
18for purposes consistent with Section 11 of Article IX of the 
19Illinois Constitution. 
20    It shall not be lawful to circumvent this limitation on 
21appropriations by governmental reorganization or other 
22methods.
23    No new program may be initiated in fiscal year 1991 and 
24thereafter that is not consistent with the limitations imposed 
25by this Section for fiscal year 1984 and thereafter, insofar 
26as appropriation of Road Fund monies is concerned.
 
 
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1    Nothing in this Section prohibits transfers from the Road 
2Fund to the State Construction Account Fund under Section 5e 
3of this Act; nor to the General Revenue Fund, as authorized by 
4Public Act 93-25.
5    The additional amounts authorized for expenditure in this 
6Section by Public Acts 92-0600, 93-0025, 93-0839, and 94-91 
7shall be repaid to the Road Fund from the General Revenue Fund 
8in the next succeeding fiscal year that the General Revenue 
9Fund has a positive budgetary balance, as determined by 
10generally accepted accounting principles applicable to 
11government.
12    The additional amounts authorized for expenditure by the 
13Secretary of State and the Department of State Police in this 
14Section by Public Act 94-91 shall be repaid to the Road Fund 
15from the General Revenue Fund in the next succeeding fiscal 
16year that the General Revenue Fund has a positive budgetary 
17balance, as determined by generally accepted accounting 
18principles applicable to government.
19(Source: P.A. 102-16, eff. 6-17-21; 102-538, eff. 8-20-21; 
20102-699, eff. 4-19-22; 102-813, eff. 5-13-22; 103-8, eff. 
216-7-23; 103-34, eff. 1-1-24; 103-588, eff. 6-5-24; 103-605, 
22eff. 7-1-24; 103-616, eff. 7-1-24; revised 8-5-24.)
 
23    Section 90-15. The Illinois Procurement Code is amended by 
24changing Sections 1-10 and 30-20 as follows:
 
 
 
10400SB0025ham003- 422 -LRB104 07069 AAS 29208 a

1    (30 ILCS 500/1-10)
2    Sec. 1-10. Application. 
3    (a) This Code applies only to procurements for which 
4bidders, offerors, potential contractors, or contractors were 
5first solicited on or after July 1, 1998. This Code shall not 
6be construed to affect or impair any contract, or any 
7provision of a contract, entered into based on a solicitation 
8prior to the implementation date of this Code as described in 
9Article 99, including, but not limited to, any covenant 
10entered into with respect to any revenue bonds or similar 
11instruments. All procurements for which contracts are 
12solicited between the effective date of Articles 50 and 99 and 
13July 1, 1998 shall be substantially in accordance with this 
14Code and its intent.
15    (b) This Code shall apply regardless of the source of the 
16funds with which the contracts are paid, including federal 
17assistance moneys. This Code shall not apply to:
18        (1) Contracts between the State and its political 
19    subdivisions or other governments, or between State 
20    governmental bodies, except as specifically provided in 
21    this Code.
22        (2) Grants, except for the filing requirements of 
23    Section 20-80.
24        (3) Purchase of care, except as provided in Section 
25    5-30.6 of the Illinois Public Aid Code and this Section.
26        (4) Hiring of an individual as an employee and not as 
 
 
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1    an independent contractor, whether pursuant to an 
2    employment code or policy or by contract directly with 
3    that individual.
4        (5) Collective bargaining contracts.
5        (6) Purchase of real estate, except that notice of 
6    this type of contract with a value of more than $25,000 
7    must be published in the Procurement Bulletin within 10 
8    calendar days after the deed is recorded in the county of 
9    jurisdiction. The notice shall identify the real estate 
10    purchased, the names of all parties to the contract, the 
11    value of the contract, and the effective date of the 
12    contract.
13        (7) Contracts necessary to prepare for anticipated 
14    litigation, enforcement actions, or investigations, 
15    provided that the chief legal counsel to the Governor 
16    shall give his or her prior approval when the procuring 
17    agency is one subject to the jurisdiction of the Governor, 
18    and provided that the chief legal counsel of any other 
19    procuring entity subject to this Code shall give his or 
20    her prior approval when the procuring entity is not one 
21    subject to the jurisdiction of the Governor.
22        (8) (Blank).
23        (9) Procurement expenditures by the Illinois 
24    Conservation Foundation when only private funds are used.
25        (10) (Blank). 
26        (11) Public-private agreements entered into according 
 
 
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1    to the procurement requirements of Section 20 of the 
2    Public-Private Partnerships for Transportation Act and 
3    design-build agreements entered into according to the 
4    procurement requirements of Section 25 of the 
5    Public-Private Partnerships for Transportation Act.
6        (12) (A) Contracts for legal, financial, and other 
7    professional and artistic services entered into by the 
8    Illinois Finance Authority in which the State of Illinois 
9    is not obligated. Such contracts shall be awarded through 
10    a competitive process authorized by the members of the 
11    Illinois Finance Authority and are subject to Sections 
12    5-30, 20-160, 50-13, 50-20, 50-35, and 50-37 of this Code, 
13    as well as the final approval by the members of the 
14    Illinois Finance Authority of the terms of the contract.
15        (B) Contracts for legal and financial services entered 
16    into by the Illinois Housing Development Authority in 
17    connection with the issuance of bonds in which the State 
18    of Illinois is not obligated. Such contracts shall be 
19    awarded through a competitive process authorized by the 
20    members of the Illinois Housing Development Authority and 
21    are subject to Sections 5-30, 20-160, 50-13, 50-20, 50-35, 
22    and 50-37 of this Code, as well as the final approval by 
23    the members of the Illinois Housing Development Authority 
24    of the terms of the contract. 
25        (13) Contracts for services, commodities, and 
26    equipment to support the delivery of timely forensic 
 
 
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1    science services in consultation with and subject to the 
2    approval of the Chief Procurement Officer as provided in 
3    subsection (d) of Section 5-4-3a of the Unified Code of 
4    Corrections, except for the requirements of Sections 
5    20-60, 20-65, 20-70, and 20-160 and Article 50 of this 
6    Code; however, the Chief Procurement Officer may, in 
7    writing with justification, waive any certification 
8    required under Article 50 of this Code. For any contracts 
9    for services which are currently provided by members of a 
10    collective bargaining agreement, the applicable terms of 
11    the collective bargaining agreement concerning 
12    subcontracting shall be followed.
13        On and after January 1, 2019, this paragraph (13), 
14    except for this sentence, is inoperative. 
15        (14) Contracts for participation expenditures required 
16    by a domestic or international trade show or exhibition of 
17    an exhibitor, member, or sponsor.
18        (15) Contracts with a railroad or utility that 
19    requires the State to reimburse the railroad or utilities 
20    for the relocation of utilities for construction or other 
21    public purpose. Contracts included within this paragraph 
22    (15) shall include, but not be limited to, those 
23    associated with: relocations, crossings, installations, 
24    and maintenance. For the purposes of this paragraph (15), 
25    "railroad" means any form of non-highway ground 
26    transportation that runs on rails or electromagnetic 
 
 
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1    guideways and "utility" means: (1) public utilities as 
2    defined in Section 3-105 of the Public Utilities Act, (2) 
3    telecommunications carriers as defined in Section 13-202 
4    of the Public Utilities Act, (3) electric cooperatives as 
5    defined in Section 3.4 of the Electric Supplier Act, (4) 
6    telephone or telecommunications cooperatives as defined in 
7    Section 13-212 of the Public Utilities Act, (5) rural 
8    water or waste water systems with 10,000 connections or 
9    less, (6) a holder as defined in Section 21-201 of the 
10    Public Utilities Act, and (7) municipalities owning or 
11    operating utility systems consisting of public utilities 
12    as that term is defined in Section 11-117-2 of the 
13    Illinois Municipal Code. 
14        (16) Procurement expenditures necessary for the 
15    Department of Public Health to provide the delivery of 
16    timely newborn screening services in accordance with the 
17    Newborn Metabolic Screening Act. 
18        (17) Procurement expenditures necessary for the 
19    Department of Agriculture, the Department of Financial and 
20    Professional Regulation, the Department of Human Services, 
21    and the Department of Public Health to implement the 
22    Compassionate Use of Medical Cannabis Program and Opioid 
23    Alternative Pilot Program requirements and ensure access 
24    to medical cannabis for patients with debilitating medical 
25    conditions in accordance with the Compassionate Use of 
26    Medical Cannabis Program Act.
 
 
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1        (18) This Code does not apply to any procurements 
2    necessary for the Department of Agriculture, the 
3    Department of Financial and Professional Regulation, the 
4    Department of Human Services, the Department of Commerce 
5    and Economic Opportunity, and the Department of Public 
6    Health to implement the Cannabis Regulation and Tax Act if 
7    the applicable agency has made a good faith determination 
8    that it is necessary and appropriate for the expenditure 
9    to fall within this exemption and if the process is 
10    conducted in a manner substantially in accordance with the 
11    requirements of Sections 20-160, 25-60, 30-22, 50-5, 
12    50-10, 50-10.5, 50-12, 50-13, 50-15, 50-20, 50-21, 50-35, 
13    50-36, 50-37, 50-38, and 50-50 of this Code; however, for 
14    Section 50-35, compliance applies only to contracts or 
15    subcontracts over $100,000. Notice of each contract 
16    entered into under this paragraph (18) that is related to 
17    the procurement of goods and services identified in 
18    paragraph (1) through (9) of this subsection shall be 
19    published in the Procurement Bulletin within 14 calendar 
20    days after contract execution. The Chief Procurement 
21    Officer shall prescribe the form and content of the 
22    notice. Each agency shall provide the Chief Procurement 
23    Officer, on a monthly basis, in the form and content 
24    prescribed by the Chief Procurement Officer, a report of 
25    contracts that are related to the procurement of goods and 
26    services identified in this subsection. At a minimum, this 
 
 
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1    report shall include the name of the contractor, a 
2    description of the supply or service provided, the total 
3    amount of the contract, the term of the contract, and the 
4    exception to this Code utilized. A copy of any or all of 
5    these contracts shall be made available to the Chief 
6    Procurement Officer immediately upon request. The Chief 
7    Procurement Officer shall submit a report to the Governor 
8    and General Assembly no later than November 1 of each year 
9    that includes, at a minimum, an annual summary of the 
10    monthly information reported to the Chief Procurement 
11    Officer. This exemption becomes inoperative 5 years after 
12    June 25, 2019 (the effective date of Public Act 101-27).
13        (19) Acquisition of modifications or adjustments, 
14    limited to assistive technology devices and assistive 
15    technology services, adaptive equipment, repairs, and 
16    replacement parts to provide reasonable accommodations (i) 
17    that enable a qualified applicant with a disability to 
18    complete the job application process and be considered for 
19    the position such qualified applicant desires, (ii) that 
20    modify or adjust the work environment to enable a 
21    qualified current employee with a disability to perform 
22    the essential functions of the position held by that 
23    employee, (iii) to enable a qualified current employee 
24    with a disability to enjoy equal benefits and privileges 
25    of employment as are enjoyed by other similarly situated 
26    employees without disabilities, and (iv) that allow a 
 
 
10400SB0025ham003- 429 -LRB104 07069 AAS 29208 a

1    customer, client, claimant, or member of the public 
2    seeking State services full use and enjoyment of and 
3    access to its programs, services, or benefits. 
4        For purposes of this paragraph (19):
5        "Assistive technology devices" means any item, piece 
6    of equipment, or product system, whether acquired 
7    commercially off the shelf, modified, or customized, that 
8    is used to increase, maintain, or improve functional 
9    capabilities of individuals with disabilities.
10        "Assistive technology services" means any service that 
11    directly assists an individual with a disability in 
12    selection, acquisition, or use of an assistive technology 
13    device.
14        "Qualified" has the same meaning and use as provided 
15    under the federal Americans with Disabilities Act when 
16    describing an individual with a disability. 
17        (20) Procurement expenditures necessary for the 
18    Illinois Commerce Commission to hire third-party 
19    facilitators pursuant to Sections 16-105.17 and 16-108.18 
20    of the Public Utilities Act or an ombudsman pursuant to 
21    Section 16-107.5 of the Public Utilities Act, a 
22    facilitator pursuant to Section 16-105.17 of the Public 
23    Utilities Act, or a grid auditor pursuant to Section 
24    16-105.10 of the Public Utilities Act, a facilitator, 
25    expert, or consultant pursuant to Sections 8-104A, 
26    16-126.2, and 16-202 of the Public Utilities Act, a 
 
 
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1    procurement monitor pursuant to Section 16-111.5 of the 
2    Public Utilities Act, an ombudsperson pursuant to Section 
3    20-145 of the Public Utilities Act, or consultants and 
4    experts pursuant to Section 15 of the Utility Data Access 
5    Act. 
6        (21) Procurement expenditures for the purchase, 
7    renewal, and expansion of software, software licenses, or 
8    software maintenance agreements that support the efforts 
9    of the Illinois State Police to enforce, regulate, and 
10    administer the Firearm Owners Identification Card Act, the 
11    Firearm Concealed Carry Act, the Firearms Restraining 
12    Order Act, the Firearm Dealer License Certification Act, 
13    the Law Enforcement Agencies Data System (LEADS), the 
14    Uniform Crime Reporting Act, the Criminal Identification 
15    Act, the Illinois Uniform Conviction Information Act, and 
16    the Gun Trafficking Information Act, or establish or 
17    maintain record management systems necessary to conduct 
18    human trafficking investigations or gun trafficking or 
19    other stolen firearm investigations. This paragraph (21) 
20    applies to contracts entered into on or after January 10, 
21    2023 (the effective date of Public Act 102-1116) and the 
22    renewal of contracts that are in effect on January 10, 
23    2023 (the effective date of Public Act 102-1116). 
24        (22) Contracts for project management services and 
25    system integration services required for the completion of 
26    the State's enterprise resource planning project. This 
 
 
10400SB0025ham003- 431 -LRB104 07069 AAS 29208 a

1    exemption becomes inoperative 5 years after June 7, 2023 
2    (the effective date of the changes made to this Section by 
3    Public Act 103-8). This paragraph (22) applies to 
4    contracts entered into on or after June 7, 2023 (the 
5    effective date of the changes made to this Section by 
6    Public Act 103-8) and the renewal of contracts that are in 
7    effect on June 7, 2023 (the effective date of the changes 
8    made to this Section by Public Act 103-8). 
9        (23) Procurements necessary for the Department of 
10    Insurance to implement the Illinois Health Benefits 
11    Exchange Law if the Department of Insurance has made a 
12    good faith determination that it is necessary and 
13    appropriate for the expenditure to fall within this 
14    exemption. The procurement process shall be conducted in a 
15    manner substantially in accordance with the requirements 
16    of Sections 20-160 and 25-60 and Article 50 of this Code. A 
17    copy of these contracts shall be made available to the 
18    Chief Procurement Officer immediately upon request. This 
19    paragraph is inoperative 5 years after June 27, 2023 (the 
20    effective date of Public Act 103-103). 
21        (24) Contracts for public education programming, 
22    noncommercial sustaining announcements, public service 
23    announcements, and public awareness and education 
24    messaging with the nonprofit trade associations of the 
25    providers of those services that inform the public on 
26    immediate and ongoing health and safety risks and hazards. 
 
 
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1        (25) Procurements necessary for the Department of 
2    Early Childhood to implement the Department of Early 
3    Childhood Act if the Department has made a good faith 
4    determination that it is necessary and appropriate for the 
5    expenditure to fall within this exemption. This exemption 
6    shall only be used for products and services procured 
7    solely for use by the Department of Early Childhood. The 
8    procurements may include those necessary to design and 
9    build integrated, operational systems of programs and 
10    services. The procurements may include, but are not 
11    limited to, those necessary to align and update program 
12    standards, integrate funding systems, design and establish 
13    data and reporting systems, align and update models for 
14    technical assistance and professional development, design 
15    systems to manage grants and ensure compliance, design and 
16    implement management and operational structures, and 
17    establish new means of engaging with families, educators, 
18    providers, and stakeholders. The procurement processes 
19    shall be conducted in a manner substantially in accordance 
20    with the requirements of Article 50 (ethics) and Sections 
21    5-5 (Procurement Policy Board), 5-7 (Commission on Equity 
22    and Inclusion), 20-80 (contract files), 20-120 
23    (subcontractors), 20-155 (paperwork), 20-160 
24    (ethics/campaign contribution prohibitions), 25-60 
25    (prevailing wage), and 25-90 (prohibited and authorized 
26    cybersecurity) of this Code. Beginning January 1, 2025, 
 
 
10400SB0025ham003- 433 -LRB104 07069 AAS 29208 a

1    the Department of Early Childhood shall provide a 
2    quarterly report to the General Assembly detailing a list 
3    of expenditures and contracts for which the Department 
4    uses this exemption. This paragraph is inoperative on and 
5    after July 1, 2027. 
6        (26) (25) Procurements that are necessary for 
7    increasing the recruitment and retention of State 
8    employees, particularly minority candidates for 
9    employment, including: 
10            (A) procurements related to registration fees for 
11        job fairs and other outreach and recruitment events;
12            (B) production of recruitment materials; and
13            (C) other services related to recruitment and 
14        retention of State employees.
15        The exemption under this paragraph (26) (25) applies 
16    only if the State agency has made a good faith 
17    determination that it is necessary and appropriate for the 
18    expenditure to fall within this paragraph (26) (25). The 
19    procurement process under this paragraph (26) (25) shall 
20    be conducted in a manner substantially in accordance with 
21    the requirements of Sections 20-160 and 25-60 and Article 
22    50 of this Code. A copy of these contracts shall be made 
23    available to the Chief Procurement Officer immediately 
24    upon request. Nothing in this paragraph (26) (25)    
25    authorizes the replacement or diminishment of State 
26    responsibilities in hiring or the positions that 
 
 
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1    effectuate that hiring. This paragraph (26) (25) is 
2    inoperative on and after June 30, 2029. 
3    Notwithstanding any other provision of law, for contracts 
4with an annual value of more than $100,000 entered into on or 
5after October 1, 2017 under an exemption provided in any 
6paragraph of this subsection (b), except paragraph (1), (2), 
7or (5), each State agency shall post to the appropriate 
8procurement bulletin the name of the contractor, a description 
9of the supply or service provided, the total amount of the 
10contract, the term of the contract, and the exception to the 
11Code utilized. The chief procurement officer shall submit a 
12report to the Governor and General Assembly no later than 
13November 1 of each year that shall include, at a minimum, an 
14annual summary of the monthly information reported to the 
15chief procurement officer. 
16    (c) This Code does not apply to the electric power 
17procurement process provided for under Section 1-75 of the 
18Illinois Power Agency Act and Section 16-111.5 of the Public 
19Utilities Act. This Code does not apply to the procurement of 
20technical and policy experts pursuant to Section 1-129 of the 
21Illinois Power Agency Act. 
22    (d) Except for Section 20-160 and Article 50 of this Code, 
23and as expressly required by Section 9.1 of the Illinois 
24Lottery Law, the provisions of this Code do not apply to the 
25procurement process provided for under Section 9.1 of the 
26Illinois Lottery Law. 
 
 
10400SB0025ham003- 435 -LRB104 07069 AAS 29208 a

1    (e) This Code does not apply to the process used by the 
2Capital Development Board to retain a person or entity to 
3assist the Capital Development Board with its duties related 
4to the determination of costs of a clean coal SNG brownfield 
5facility, as defined by Section 1-10 of the Illinois Power 
6Agency Act, as required in subsection (h-3) of Section 9-220 
7of the Public Utilities Act, including calculating the range 
8of capital costs, the range of operating and maintenance 
9costs, or the sequestration costs or monitoring the 
10construction of clean coal SNG brownfield facility for the 
11full duration of construction.
12    (f) (Blank). 
13    (g) (Blank).
14    (h) This Code does not apply to the process to procure or 
15contracts entered into in accordance with Sections 11-5.2 and 
1611-5.3 of the Illinois Public Aid Code. 
17    (i) Each chief procurement officer may access records 
18necessary to review whether a contract, purchase, or other 
19expenditure is or is not subject to the provisions of this 
20Code, unless such records would be subject to attorney-client 
21privilege. 
22    (j) This Code does not apply to the process used by the 
23Capital Development Board to retain an artist or work or works 
24of art as required in Section 14 of the Capital Development 
25Board Act. 
26    (k) This Code does not apply to the process to procure 
 
 
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1contracts, or contracts entered into, by the State Board of 
2Elections or the State Electoral Board for hearing officers 
3appointed pursuant to the Election Code. 
4    (l) This Code does not apply to the processes used by the 
5Illinois Student Assistance Commission to procure supplies and 
6services paid for from the private funds of the Illinois 
7Prepaid Tuition Fund. As used in this subsection (l), "private 
8funds" means funds derived from deposits paid into the 
9Illinois Prepaid Tuition Trust Fund and the earnings thereon. 
10    (m) This Code shall apply regardless of the source of 
11funds with which contracts are paid, including federal 
12assistance moneys. Except as specifically provided in this 
13Code, this Code shall not apply to procurement expenditures 
14necessary for the Department of Public Health to conduct the 
15Healthy Illinois Survey in accordance with Section 2310-431 of 
16the Department of Public Health Powers and Duties Law of the 
17Civil Administrative Code of Illinois. 
18(Source: P.A. 102-175, eff. 7-29-21; 102-483, eff 1-1-22; 
19102-558, eff. 8-20-21; 102-600, eff. 8-27-21; 102-662, eff. 
209-15-21; 102-721, eff. 1-1-23; 102-813, eff. 5-13-22; 
21102-1116, eff. 1-10-23; 103-8, eff. 6-7-23; 103-103, eff. 
226-27-23; 103-570, eff. 1-1-24; 103-580, eff. 12-8-23; 103-594, 
23eff. 6-25-24; 103-605, eff. 7-1-24; 103-865, eff. 1-1-25; 
24revised 11-26-24.)
 
25    (30 ILCS 500/30-20)
 
 
10400SB0025ham003- 437 -LRB104 07069 AAS 29208 a

1    Sec. 30-20. Prequalification. 
2    (a) The Capital Development Board shall promulgate rules 
3for the development of prequalified supplier lists for 
4construction and construction-related professional services 
5and the periodic updating of those lists. Construction and 
6construction-related professional services contracts over 
7$25,000 may be awarded to any qualified suppliers.
8    (b) If deemed necessary by the Agency, the The Illinois 
9Power Agency shall promulgate rules for the development of 
10prequalified supplier lists for construction and 
11construction-related professional services and the periodic 
12updating of those lists. Construction and construction-related    
13construction related professional services contracts over 
14$25,000 may be awarded to any qualified suppliers, pursuant to 
15a competitive bidding process. 
16(Source: P.A. 95-481, eff. 8-28-07.)
 
17    Section 90-17. The Illinois Works Jobs Program Act is 
18amended by changing Section 20-15 as follows:
 
19    (30 ILCS 559/20-15)
20    Sec. 20-15. Illinois Works Preapprenticeship Program; 
21Illinois Works Bid Credit Program. 
22    (a) The Illinois Works Preapprenticeship Program is 
23established and shall be administered by the Department. The 
24goal of the Illinois Works Preapprenticeship Program is to 
 
 
10400SB0025ham003- 438 -LRB104 07069 AAS 29208 a

1create a network of community-based organizations throughout 
2the State that will recruit, prescreen, and provide 
3preapprenticeship skills training, for which participants may 
4attend free of charge and receive a stipend, to create a 
5qualified, diverse pipeline of workers who are prepared for 
6careers in the construction and building trades. Upon 
7completion of the Illinois Works Preapprenticeship Program, 
8the candidates will be skilled and work-ready. 
9    (b) There is created the Illinois Works Fund, a special 
10fund in the State treasury. The Illinois Works Fund shall be 
11administered by the Department. The Illinois Works Fund shall 
12be used to provide funding for community-based organizations 
13throughout the State. In addition to any other transfers that 
14may be provided for by law, on and after July 1, 2019 at the 
15direction of the Director of the Governor's Office of 
16Management and Budget, the State Comptroller shall direct and 
17the State Treasurer shall transfer amounts not exceeding a 
18total of $50,000,000 from the Rebuild Illinois Projects Fund 
19to the Illinois Works Fund.
20    (b-5) In addition to any other transfers that may be 
21provided for by law, beginning July 1, 2024 and each July 1 
22thereafter, or as soon thereafter as practical, the State 
23Comptroller shall direct and the State Treasurer shall 
24transfer $27,500,000 from the Capital Projects Fund to the 
25Illinois Works Fund. 
26    (c) Each community-based organization that receives 
 
 
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1funding from the Illinois Works Fund shall provide an annual 
2report to the Illinois Works Review Panel by April 1 of each 
3calendar year. The annual report shall include the following 
4information: 
5        (1) a description of the community-based 
6    organization's recruitment, screening, and training 
7    efforts; 
8        (2) the number of individuals who apply to, 
9    participate in, and complete the community-based 
10    organization's program, broken down by race, gender, age, 
11    and veteran status; and
12    (3) the number of the individuals referenced in item (2) 
13    of this subsection who are initially accepted and placed 
14    into apprenticeship programs in the construction and 
15    building trades. 
16    (d) The Department shall create and administer the 
17Illinois Works Bid Credit Program that shall provide economic 
18incentives, through bid credits, to encourage contractors and 
19subcontractors to provide contracting and employment 
20opportunities to historically underrepresented populations in 
21the construction industry. 
22    The Illinois Works Bid Credit Program shall allow 
23contractors and subcontractors to earn bid credits for use 
24toward future bids for public works projects contracted by the 
25State or an agency of the State in order to increase the 
26chances that the contractor and the subcontractors will be 
 
 
10400SB0025ham003- 440 -LRB104 07069 AAS 29208 a

1selected.
2    Contractors or subcontractors may be eligible to earn bid 
3credits for employing apprentices who have been verified by 
4the Department to have completed the Illinois Works 
5Preapprenticeship Program, the Climate Works Preapprenticeship 
6Program, or the Highway Construction Careers Training Program. 
7Contractors or subcontractors shall earn bid credits at a rate 
8established by the Department and based on labor hours worked 
9by apprentices who have been verified by the Department to 
10have completed the Illinois Works Preapprenticeship Program, 
11the Climate Works Preapprenticeship Program, or the Highway 
12Construction Careers Training Program. In order to earn bid 
13credits, contractors and subcontractors shall provide the 
14Department with certified payroll documenting the hours 
15performed by apprentices who have been verified by the 
16Department to have completed the Illinois Works 
17Preapprenticeship Program, the Climate Works Preapprenticeship 
18Program, or the Highway Construction Careers Training Program. 
19Contractors and subcontractors can use bid credits toward 
20future bids for public works projects contracted or funded by 
21the State or an agency of the State in order to increase the 
22likelihood of being selected as the contractor for the public 
23works project toward which they have applied the bid credit. 
24The Department shall establish the rate by rule and shall 
25publish it on the Department's website. The rule may include 
26maximum bid credits allowed per contractor, per subcontractor, 
 
 
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1per apprentice, per bid, or per year. 
2    The Illinois Works Credit Bank is hereby created and shall 
3be administered by the Department. The Illinois Works Credit 
4Bank shall track the bid credits. 
5    A contractor or subcontractor who has been awarded bid 
6credits under any other State program for employing 
7apprentices who have completed the Illinois Works 
8Preapprenticeship Program is not eligible to receive bid 
9credits under the Illinois Works Bid Credit Program relating 
10to the same contract.
11    The Department shall report to the Illinois Works Review 
12Panel the following: (i) the number of bid credits awarded by 
13the Department; (ii) the number of bid credits submitted by 
14the contractor or subcontractor to the agency administering 
15the public works contract; and (iii) the number of bid credits 
16accepted by the agency for such contract. Any agency that 
17awards bid credits pursuant to the Illinois Works Credit Bank 
18Program shall report to the Department the number of bid 
19credits it accepted for the public works contract.
20    Upon a finding that a contractor or subcontractor has 
21reported falsified records to the Department in order to 
22fraudulently obtain bid credits, the Department may bar the 
23contractor or subcontractor from participating in the Illinois 
24Works Bid Credit Program and may suspend the contractor or 
25subcontractor from bidding on or participating in any public 
26works project. False or fraudulent claims for payment relating 
 
 
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1to false bid credits may be subject to damages and penalties 
2under applicable law. 
3    (e) The Department shall adopt any rules deemed necessary 
4to implement this Section. In order to provide for the 
5expeditious and timely implementation of this Act, the 
6Department may adopt emergency rules. The adoption of 
7emergency rules authorized by this subsection is deemed to be 
8necessary for the public interest, safety, and welfare.
9(Source: P.A. 103-8, eff. 6-7-23; 103-305, eff. 7-28-23; 
10103-588, eff. 6-5-24; 103-605, eff. 7-1-24; 104-2, eff. 
116-16-25.)
 
12    Section 90-20. The Property Tax Code is amended by adding 
13Division 22 as follows:
 
14    (35 ILCS 200/Art. 10 Div. 22 heading new)
15
Division 22.  Commercial energy storage systems

 
16    (35 ILCS 200/10-920 new)
17    Sec. 10-920. Definitions. As used in this Division:
18    "Allowance for physical depreciation" means the product of 
19the quotient that is generated by dividing the actual age in 
20years of the commercial energy storage system on the 
21assessment date by 25 years multiplied by the commercial 
22energy storage system's trended real property cost basis. 
23"Allowance for physical depreciation" may not exceed an amount 
 
 
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1that reduces the value of the commercial energy storage system 
2to 30% of its trended real property cost basis or less.
3    "Commercial energy storage system" means any device or 
4assembly of devices that is (i) either installed as a 
5stand-alone system or tied to a power generation system, (ii) 
6used for the primary purpose of storing of energy for 
7wholesale or retail sale and not primarily for storage to 
8later consume on the property on which the device resides, and 
9(iii) an energy storage system, as defined in Section 16-135 
10of the Public Utilities Act.
11    "Commercial energy storage system real property cost 
12basis" means the owner of the commercial energy storage 
13system's interest in the land within the project boundaries 
14and real property improvements and shall be calculated at $65 
15per kilowatt-hour of rated kilowatt-hour energy capacity.
16    "Consumer Price Index" means the index published by the 
17Bureau of Labor Statistics of the United States Department of 
18Labor that measures the average change in prices of goods and 
19services purchased by all urban consumers, United States city 
20average, all items, 1982-84 = 100.
21    "Rated kWh energy capacity" means the maximum amount of 
22stored energy in kilowatt hours. "Trended real property cost 
23basis" means the commercial energy storage system real 
24property cost basis multiplied by the trending factor.
25    "Trending factor" means the following:
26        (1) for stand-alone commercial energy storage systems, 
 
 
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1    the lesser of 2% or the number generated by dividing the 
2    Consumer Price Index published by the Bureau of Labor 
3    Statistics in the December immediately preceding the 
4    assessment date by the Consumer Price Index published by 
5    the Bureau of Labor Statistics in December of 2024; or
6        (2) for commercial energy storage systems tied to a 
7    power generation system, a trending factor of 1.00.
 
8    (35 ILCS 200/10-925 new)
9    Sec. 10-925. Improvement valuation of commercial energy 
10systems. Beginning in assessment year 2026, the fair cash 
11value of commercial energy storage system improvements shall 
12be determined by subtracting the allowance for physical 
13depreciation from the commercial energy storage system trended 
14real property cost basis. Functional obsolescence and external 
15obsolescence of the commercial energy storage system 
16improvements may further reduce the fair cash value of the 
17improvements to the extent the obsolescence is proven by the 
18taxpayer by clear and convincing evidence, except that the 
19combined depreciation from all functional and economic 
20obsolescence shall not exceed 70% of the trended real property 
21cost basis. The chief county assessment officer may make 
22reasonable adjustments to the actual age of the commercial 
23energy storage system to account for the routine replacement 
24or upgrade of system components.
 
 
 
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1    (35 ILCS 200/10-930 new)
2    Sec. 10-930. Commercial energy storage systems; 
3equalization. Commercial energy storage systems that are 
4subject to assessment under this Division are not subject to 
5equalization factors applied by the Department, any board of 
6review, an assessor, or a chief county assessment officer.
 
7    (35 ILCS 200/10-935 new)
8    Sec. 10-935. Survey for commercial energy storage systems; 
9parcel identification numbers. Notwithstanding any other 
10provision of law, the owner of the commercial energy storage 
11system shall commission a metes and bounds survey description 
12of the land upon which the commercial energy storage system is 
13located, including access routes, over which the owner of the 
14commercial energy storage system has exclusive control. Land 
15held for future development shall not be included in the 
16project area for real property assessment purposes. The owner 
17of the commercial energy storage system shall, at the owner's 
18own expense, use a State-registered land surveyor to prepare 
19the survey. The owner of the commercial energy storage system 
20shall deliver a copy of the survey to the chief county 
21assessment officer and to the owner of the land upon which the 
22commercial energy storage system is located. Upon receiving a 
23copy of the survey and an agreed acknowledgment to the 
24separate parcel identification number by the owner of the land 
25upon which the commercial energy storage system is 
 
 
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1constructed, the chief county assessment officer shall issue a 
2separate parcel identification number for the real property 
3improvements, including the land containing the commercial 
4energy storage system, to be used only for the purposes of 
5property assessment for taxation. If no survey is provided, 
6the chief county assessment officer shall determine the area 
7of the site that is occupied by the commercial energy storage 
8system. The chief county assessment officer's determination 
9shall be final and may not be challenged on review by the owner 
10of the commercial energy storage system. The property records 
11shall contain the legal description of the commercial energy 
12storage system parcel and describe any leasehold interest or 
13other interest of the owner of the commercial energy storage 
14system in the property. A plat prepared under this Section 
15shall not be construed as a violation of the Plat Act.
16    Surveys that are prepared in accordance with either 
17Section 10-740 or Section 10-620 and that also include the 
18location of a commercial energy storage system in the survey's 
19metes and bounds description shall satisfy the requirements of 
20this Section.
 
21    (35 ILCS 200/10-940 new)
22    Sec. 10-940. Real estate taxes. Notwithstanding the 
23provisions of Section 9-175 of this Code, the owner of the 
24commercial energy storage system shall be liable for the real 
25estate taxes for the land and real property improvements of 
 
 
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1the commercial energy storage system. Notwithstanding the 
2foregoing, the owner of the land upon which a commercial 
3energy storage system is located may pay any unpaid tax of the 
4commercial energy storage system parcel prior to the 
5initiation of any tax sale proceedings.
 
6    (35 ILCS 200/10-945 new)
7    Sec. 10-945. Property assessed as farmland. 
8Notwithstanding any other provision of law, real property 
9assessed as farmland in accordance with Section 10-110 in the 
10assessment year prior to valuation under this Division shall 
11return to being assessed as farmland in accordance with 
12Section 10-110 in the year following completion of the removal 
13of the commercial energy storage system if the property is 
14returned to a farm use, as defined in Section 1-60, 
15notwithstanding that the land was not used for farming for the 
162 preceding years.
 
17    (35 ILCS 200/10-950 new)
18    Sec. 10-950. Abatements. Any taxing district may, upon a 
19majority vote of its governing authority and after the 
20determination of the assessed valuation as set forth in this 
21Code, order the clerk of the appropriate municipality or 
22county to abate any portion of real property taxes otherwise 
23levied or extended by the taxing district on a commercial 
24energy storage system.
 
 
 
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1    (35 ILCS 200/10-953 new)
2    Sec. 10-953. Cook County exemption. This Division 22 does 
3not apply to any property located within Cook County.
 
4    (35 ILCS 200/10-955 new)
5    Sec. 10-955. Applicability. The provisions of this 
6Division apply for assessment years 2026 through 2040.
 
7    Section 90-27. The Counties Code is amended by adding 
8Division 5-46 and Section 5-12024 and changing Section 5-12020 
9as follows:
 
10    (55 ILCS 5/5-12020)
11    Sec. 5-12020. Commercial wind energy facilities and 
12commercial solar energy facilities. 
13    (a) As used in this Section:
14    "Commercial solar energy facility" means a "commercial 
15solar energy system" as defined in Section 10-720 of the 
16Property Tax Code. "Commercial solar energy facility" does not 
17mean a utility-scale solar energy facility being constructed 
18at a site that was eligible to participate in a procurement 
19event conducted by the Illinois Power Agency pursuant to 
20subsection (c-5) of Section 1-75 of the Illinois Power Agency 
21Act. 
22    "Commercial wind energy facility" means a wind energy 
 
 
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1conversion facility of equal or greater than 500 kilowatts in 
2total nameplate generating capacity. "Commercial wind energy 
3facility" includes a wind energy conversion facility seeking 
4an extension of a permit to construct granted by a county or 
5municipality before January 27, 2023 (the effective date of 
6Public Act 102-1123).
7    "Facility owner" means (i) a person with a direct 
8ownership interest in a commercial wind energy facility or a 
9commercial solar energy facility, or both, regardless of 
10whether the person is involved in acquiring the necessary 
11rights, permits, and approvals or otherwise planning for the 
12construction and operation of the facility, and (ii) at the 
13time the facility is being developed, a person who is acting as 
14a developer of the facility by acquiring the necessary rights, 
15permits, and approvals or by planning for the construction and 
16operation of the facility, regardless of whether the person 
17will own or operate the facility.
18    "Nonparticipating property" means real property that is 
19not a participating property.
20    "Nonparticipating residence" means a residence that is 
21located on nonparticipating property and that is existing and 
22occupied on the date that an application for a permit to 
23develop the commercial wind energy facility or the commercial 
24solar energy facility is filed with the county.
25    "Occupied community building" means any one or more of the 
26following buildings that is existing and occupied on the date 
 
 
10400SB0025ham003- 450 -LRB104 07069 AAS 29208 a

1that the application for a permit to develop the commercial 
2wind energy facility or the commercial solar energy facility 
3is filed with the county: a school, place of worship, day care 
4facility, public library, or community center.
5    "Participating property" means real property that is the 
6subject of a written agreement between a facility owner and 
7the owner of the real property that provides the facility 
8owner an easement, option, lease, or license to use the real 
9property for the purpose of constructing a commercial wind 
10energy facility, a commercial solar energy facility, or 
11supporting facilities. "Participating property" also includes 
12real property that is owned by a facility owner for the purpose 
13of constructing a commercial wind energy facility, a 
14commercial solar energy facility, or supporting facilities.
15    "Participating residence" means a residence that is 
16located on participating property and that is existing and 
17occupied on the date that an application for a permit to 
18develop the commercial wind energy facility or the commercial 
19solar energy facility is filed with the county.
20    "Protected lands" means real property that is: 
21        (1) subject to a permanent conservation right 
22    consistent with the Real Property Conservation Rights Act; 
23    or 
24        (2) registered or designated as a nature preserve, 
25    buffer, or land and water reserve under the Illinois 
26    Natural Areas Preservation Act.
 
 
10400SB0025ham003- 451 -LRB104 07069 AAS 29208 a

1    "Supporting facilities" means the transmission lines, 
2substations, access roads, meteorological towers, storage 
3containers, and equipment associated with the generation and 
4storage of electricity by the commercial wind energy facility 
5or commercial solar energy facility. "Supporting facilities" 
6includes energy storage systems capable of absorbing energy 
7and storing it for use at a later time, including, but not 
8limited to, batteries and other electrochemical and 
9electromechanical technologies or systems.    
10    "Wind tower" includes the wind turbine tower, nacelle, and 
11blades. 
12    (b) Notwithstanding any other provision of law or whether 
13the county has formed a zoning commission and adopted formal 
14zoning under Section 5-12007, a county may establish standards 
15for commercial wind energy facilities, commercial solar energy 
16facilities, or both. The standards may include all of the 
17requirements specified in this Section but may not include 
18requirements for commercial wind energy facilities or 
19commercial solar energy facilities that are more restrictive 
20than specified in this Section. A county may also regulate the 
21siting of commercial wind energy facilities with standards 
22that are not more restrictive than the requirements specified 
23in this Section in unincorporated areas of the county that are 
24outside the zoning jurisdiction of a municipality and that are 
25outside the 1.5-mile radius surrounding the zoning 
26jurisdiction of a municipality. A county may also regulate the 
 
 
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1siting of commercial solar energy facilities with standards 
2that are not more restrictive than the requirements specified 
3in this Section in unincorporated areas of the county that are 
4outside of the zoning jurisdiction of a municipality.    
5    (c) If a county has elected to establish standards under 
6subsection (b), before the county grants siting approval or a 
7special use permit for a commercial wind energy facility or a 
8commercial solar energy facility, or modification of an 
9approved siting or special use permit, the county board of the 
10county in which the facility is to be sited or the zoning board 
11of appeals for the county shall hold at least one public 
12hearing. The public hearing shall be conducted in accordance 
13with the Open Meetings Act and shall conclude be held not more 
14than 60 days after the filing of the application for the 
15facility. The county shall allow interested parties to a 
16special use permit an opportunity to present evidence and to 
17cross-examine witnesses at the hearing, but the county may 
18impose reasonable restrictions on the public hearing, 
19including reasonable time limitations on the presentation of 
20evidence and the cross-examination of witnesses. The county 
21shall also allow public comment at the public hearing in 
22accordance with the Open Meetings Act. The county shall make 
23its siting and permitting decisions not more than 30 days 
24after the conclusion of the public hearing. Notice of the 
25hearing shall be published in a newspaper of general 
26circulation in the county. A facility owner must enter into an 
 
 
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1agricultural impact mitigation agreement with the Department 
2of Agriculture prior to the date of the required public 
3hearing. A commercial wind energy facility owner seeking an 
4extension of a permit granted by a county prior to July 24, 
52015 (the effective date of Public Act 99-132) must enter into 
6an agricultural impact mitigation agreement with the 
7Department of Agriculture prior to a decision by the county to 
8grant the permit extension. Counties may allow test wind 
9towers or test solar energy systems to be sited without formal 
10approval by the county board.
11    (d) A county with an existing zoning ordinance in conflict 
12with this Section shall amend that zoning ordinance to be in 
13compliance with this Section within 120 days after January 27, 
142023 (the effective date of Public Act 102-1123).
15    (e) A county may require: 
16        (1) a wind tower of a commercial wind energy facility 
17    to be sited as follows, with setback distances measured 
18    from the center of the base of the wind tower: 
 
19Setback Description           Setback Distance
 
20Occupied Community            2.1 times the maximum blade tip
21Buildings                     height of the wind tower to the
22                              nearest point on the outside
23                              wall of the structure
 
 
 
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1Participating Residences      1.1 times the maximum blade tip
2                              height of the wind tower to the
3                              nearest point on the outside
4                              wall of the structure
 
5Nonparticipating Residences   2.1 times the maximum blade tip
6                              height of the wind tower to the
7                              nearest point on the outside
8                              wall of the structure
 
9Boundary Lines of             None
10Participating Property 
 
11Boundary Lines of             1.1 times the maximum blade tip
12Nonparticipating Property     height of the wind tower to the
13                              nearest point on the property
14                              line of the nonparticipating
15                              property
 
16Public Road Rights-of-Way     1.1 times the maximum blade tip
17                              height of the wind tower
18                              to the center point of the
19                              public road right-of-way
 
20Overhead Communication and    1.1 times the maximum blade tip
21Electric Transmission         height of the wind tower to the
 
 
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1and Distribution Facilities   nearest edge of the property
2(Not Including Overhead       line, easement, or 
3Utility Service Lines to      right-of-way 
4Individual Houses or          containing the overhead line
5Outbuildings)
 
6Overhead Utility Service      None
7Lines to Individual
8Houses or Outbuildings
 
9Fish and Wildlife Areas       2.1 times the maximum blade
10and Illinois Nature           tip height of the wind tower
11Preserve Commission           to the nearest point on the
12Protected Lands               property line of the fish and
13                              wildlife area or protected
14                              land
15    This Section does not exempt or excuse compliance with 
16    electric facility clearances approved or required by the 
17    National Electrical Code, the The National Electrical 
18    Safety Code, the Illinois Commerce Commission, and the    
19    Federal Energy Regulatory Commission, and their designees 
20    or successors; .    
21        (2) a wind tower of a commercial wind energy facility 
22    to be sited so that industry standard computer modeling 
23    indicates that any occupied community building or 
24    nonparticipating residence will not experience more than 
 
 
10400SB0025ham003- 456 -LRB104 07069 AAS 29208 a

1    30 hours per year of shadow flicker under planned 
2    operating conditions;
3        (3) a commercial solar energy facility to be sited as 
4    follows, with setback distances measured from the nearest 
5    edge of any above-ground component of the facility, 
6    excluding fencing: 
 
7Setback Description           Setback Distance
 
8Occupied Community            150 feet from the nearest
9Buildings and Dwellings on    point on the outside wall 
10Nonparticipating Properties   of the structure
 
11Boundary Lines of             None
12Participating Property    
 
13Public Road Rights-of-Way     50 feet from the nearest
14                              edge of the public 
15                              right-of-way 
 
16Boundary Lines of             50 feet to the nearest
17Nonparticipating Property     point on the property
18                              line of the nonparticipating
19                              property
 
20        (4) a commercial solar energy facility to be sited so 
 
 
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1    that the facility's perimeter is enclosed by fencing 
2    having a height of at least 6 feet and no more than 25 
3    feet; and 
4        (5) a commercial solar energy facility to be sited so 
5    that no component of a solar panel has a height of more 
6    than 20 feet above ground when the solar energy facility's 
7    arrays are at full tilt. 
8    The requirements set forth in this subsection (e) may be 
9waived subject to the written consent of the owner of each 
10affected nonparticipating property.
11    (f) A county may not set a sound limitation for wind towers 
12in commercial wind energy facilities or any components in 
13commercial solar energy facilities that is more restrictive 
14than the sound limitations established by the Illinois 
15Pollution Control Board under 35 Ill. Adm. Code Parts 900, 
16901, and 910.
17    (g) A county may not place any restriction on the 
18installation or use of a commercial wind energy facility or a 
19commercial solar energy facility unless it adopts an ordinance 
20that complies with this Section. A county may not establish 
21siting standards for supporting facilities that preclude 
22development of commercial wind energy facilities or commercial 
23solar energy facilities. 
24    A request for siting approval or a special use permit for a 
25commercial wind energy facility or a commercial solar energy 
26facility, or modification of an approved siting or special use 
 
 
10400SB0025ham003- 458 -LRB104 07069 AAS 29208 a

1permit, shall be approved if the request is in compliance with 
2the standards and conditions imposed in this Act, the zoning 
3ordinance adopted consistent with this Act Code, and the 
4conditions imposed under State and federal statutes and 
5regulations. 
6    (h) A county may not adopt zoning regulations that 
7disallow, permanently or temporarily, commercial wind energy 
8facilities or commercial solar energy facilities from being 
9developed or operated in any district zoned to allow 
10agricultural or industrial uses. 
11    (i) (Blank). A county may not require permit application 
12fees for a commercial wind energy facility or commercial solar 
13energy facility that are unreasonable. All application fees 
14imposed by the county shall be consistent with fees for 
15projects in the county with similar capital value and cost.    
16    (i-5) All siting approval or special use permit 
17application fees for a commercial wind energy facility or 
18commercial solar energy facility shall not exceed $5,000 per 
19each megawatt of nameplate capacity of the energy facility, 
20and the maximum fee is $125,000. A county may also require 
21reimbursement from the applicant for any reasonable expenses 
22incurred by the county in processing the siting approval or 
23special use permit application in excess of the maximum fee. A 
24siting approval or special use permit shall not be subject to 
25any time deadline to start construction or obtain a building 
26permit of less than 5 years from the date of siting approval or 
 
 
10400SB0025ham003- 459 -LRB104 07069 AAS 29208 a

1special use permit approval. A county shall allow an applicant 
2to request an extension of the deadline based upon reasonable 
3cause for the extension request. The exemption shall not be 
4unreasonably withheld, conditioned, or denied.
5    (i-10) A county may require, for a commercial wind energy 
6facility or commercial solar energy facility, a single 
7building permit and permit fee for the facility which includes 
8all supporting facilities. A county building permit fee for a 
9commercial wind energy facility or commercial solar energy 
10facility shall not exceed $5,000 per each megawatt of 
11nameplate capacity of the energy facility, and the maximum fee 
12is $75,000. A county may also require reimbursement from the 
13applicant for any reasonable expenses incurred by the county 
14in processing the building permit in excess of the maximum 
15fee. A county may require an applicant, upon start of 
16construction of the facility, to maintain liability insurance 
17that is commercially reasonable and consistent with prevailing 
18industry standards for similar energy facilities.
19    (j) Except as otherwise provided in this Section, a county 
20shall not require standards for construction, decommissioning, 
21or deconstruction of a commercial wind energy facility or 
22commercial solar energy facility or related financial 
23assurances that are more restrictive than those included in 
24the Department of Agriculture's standard wind farm 
25agricultural impact mitigation agreement, template 81818, or 
26standard solar agricultural impact mitigation agreement, 
 
 
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1version 8.19.19, as applicable and in effect on December 31, 
22022. The amount of any decommissioning payment shall be in 
3accordance with the financial assurance required by those 
4agricultural impact mitigation agreements. 
5    (j-5) A commercial wind energy facility or a commercial 
6solar energy facility shall file a farmland drainage plan with 
7the county and impacted drainage districts outlining how 
8surface and subsurface drainage of farmland will be restored 
9during and following construction or deconstruction of the 
10facility. The plan is to be created independently by the 
11facility developer and shall include the location of any 
12potentially impacted drainage district facilities to the 
13extent this information is publicly available from the county 
14or the drainage district, plans to repair any subsurface 
15drainage affected during construction or deconstruction using 
16procedures outlined in the agricultural impact mitigation 
17agreement entered into by the commercial wind energy facility 
18owner or commercial solar energy facility owner, and 
19procedures for the repair and restoration of surface drainage 
20affected during construction or deconstruction. All surface 
21and subsurface damage shall be repaired as soon as reasonably 
22practicable. 
23    (k) A county may not condition approval of a commercial 
24wind energy facility or commercial solar energy facility on a 
25property value guarantee and may not require a facility owner 
26to pay into a neighboring property devaluation escrow account. 
 
 
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1    (l) A county may require certain vegetative screening 
2between a surrounding a commercial wind energy facility or    
3commercial solar energy facility and nonparticipating 
4residences. A county but may not require earthen berms or 
5similar structures. Vegetative screening requirements shall be 
6commercially reasonable and limited in height at full maturity 
7to avoid reduction of the productive energy output of the 
8commercial solar energy facility. A county may not require 
9vegetative screening to exceed 5 feet in height when first 
10installed or prior to commercial operation date. The screening 
11requirements shall take into account the size and location of 
12the facility, visibility from nonparticipating residences, 
13compatibility of native plant species, cost and feasibility of 
14installation and maintenance, and industry standards and best 
15practices for commercial solar energy facilities.    
16    (m) A county may set blade tip height limitations for wind 
17towers in commercial wind energy facilities but may not set a 
18blade tip height limitation that is more restrictive than the 
19height allowed under a Determination of No Hazard to Air 
20Navigation by the Federal Aviation Administration under 14 CFR 
21Part 77.
22    (n) A county may require that a commercial wind energy 
23facility owner or commercial solar energy facility owner 
24provide:
25        (1) the results and recommendations from consultation 
26    with the Illinois Department of Natural Resources that are 
 
 
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1    obtained through the Ecological Compliance Assessment Tool 
2    (EcoCAT) or a comparable successor tool; and
3        (2) (blank). the results of the United States Fish and 
4    Wildlife Service's Information for Planning and Consulting 
5    environmental review or a comparable successor tool that 
6    is consistent with (i) the "U.S. Fish and Wildlife 
7    Service's Land-Based Wind Energy Guidelines" and (ii) any 
8    applicable United States Fish and Wildlife Service solar 
9    wildlife guidelines that have been subject to public 
10    review.    
11    (o) A county may require a commercial wind energy facility 
12or commercial solar energy facility to adhere to the 
13recommendations provided by the Illinois Department of Natural 
14Resources in an EcoCAT natural resource review report under 17 
15Ill. Adm. Code Part 1075. 
16    (p) A county may require a facility owner to:
17        (1) demonstrate avoidance of protected lands as 
18    identified by the Illinois Department of Natural Resources 
19    and the Illinois Nature Preserve Commission; or
20        (2) consider the recommendations of the Illinois 
21    Department of Natural Resources for setbacks from 
22    protected lands, including areas identified by the 
23    Illinois Nature Preserve Commission.
24    (q) A county may require that a facility owner provide 
25evidence of consultation with the Illinois State Historic 
26Preservation Office to assess potential impacts on 
 
 
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1State-registered historic sites under the Illinois State 
2Agency Historic Resources Preservation Act. 
3    (r) To maximize community benefits, including, but not 
4limited to, reduced stormwater runoff, flooding, and erosion 
5at the ground mounted solar energy system, improved soil 
6health, and increased foraging habitat for game birds, 
7songbirds, and pollinators, a county may (1) require a 
8commercial solar energy facility owner to plant, establish, 
9and maintain for the life of the facility vegetative ground 
10cover, consistent with the goals of the Pollinator-Friendly 
11Solar Site Act and (2) require the submittal of a vegetation 
12management plan that is in compliance with the agricultural 
13impact mitigation agreement in the application to construct 
14and operate a commercial solar energy facility in the county 
15if the vegetative ground cover and vegetation management plan 
16comply with the requirements of the underlying agreement with 
17the landowner or landowners where the facility will be 
18constructed. 
19    No later than 90 days after January 27, 2023 (the 
20effective date of Public Act 102-1123), the Illinois 
21Department of Natural Resources shall develop guidelines for 
22vegetation management plans that may be required under this 
23subsection for commercial solar energy facilities. The 
24guidelines must include guidance for short-term and long-term 
25property management practices that provide and maintain native 
26and non-invasive naturalized perennial vegetation to protect 
 
 
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1the health and well-being of pollinators. 
2    (s) If a facility owner enters into a road use agreement 
3with the Illinois Department of Transportation, a road 
4district, or other unit of local government relating to a 
5commercial wind energy facility or a commercial solar energy 
6facility, the road use agreement shall require the facility 
7owner to be responsible for (i) the reasonable cost of 
8improving roads used by the facility owner to construct the 
9commercial wind energy facility or the commercial solar energy 
10facility and (ii) the reasonable cost of repairing roads used 
11by the facility owner during construction of the commercial 
12wind energy facility or the commercial solar energy facility 
13so that those roads are in a condition that is safe for the 
14driving public after the completion of the facility's 
15construction. Roadways improved in preparation for and during 
16the construction of the commercial wind energy facility or 
17commercial solar energy facility shall be repaired and 
18restored to the improved condition at the reasonable cost of 
19the developer if the roadways have degraded or were damaged as 
20a result of construction-related activities.
21    The road use agreement shall not require the facility 
22owner to pay costs, fees, or charges for road work that is not 
23specifically and uniquely attributable to the construction of 
24the commercial wind energy facility or the commercial solar 
25energy facility. No road district or other unit of local 
26government may request or require permit fees, fines, or other 
 
 
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1payment obligations as a requirement for a road use agreement 
2with a facility owner unless the amount of the permit fee or 
3payment is equivalent to the amount of actual expenses 
4incurred by the road district or other unit of local 
5government for negotiating, executing, constructing, or 
6implementing the road use agreement. The road use agreement 
7shall not require any road work to be performed by or paid for 
8by the facility owner that is unrelated to the road 
9improvements required for the construction of the commercial 
10wind energy facility or the commercial solar energy facility 
11or the restoration of the roads used by the facility owner 
12during construction-related activities. Road-related fees, 
13permit fees, or other charges imposed by the Illinois 
14Department of Transportation, a road district, or other unit 
15of local government under a road use agreement with the 
16facility owner shall be reasonably related to the cost of 
17administration of the road use agreement.    
18    (s-5) The facility owner shall also compensate landowners 
19for crop losses or other agricultural damages resulting from 
20damage to the drainage system caused by the construction of 
21the commercial wind energy facility or the commercial solar 
22energy facility. The commercial wind energy facility owner or 
23commercial solar energy facility owner shall repair or pay for 
24the repair of all damage to the subsurface drainage system 
25caused by the construction of the commercial wind energy 
26facility or the commercial solar energy facility in accordance 
 
 
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1with the agriculture impact mitigation agreement requirements 
2for repair of drainage. The commercial wind energy facility 
3owner or commercial solar energy facility owner shall repair 
4or pay for the repair and restoration of surface drainage 
5caused by the construction or deconstruction of the commercial 
6wind energy facility or the commercial solar energy facility 
7as soon as reasonably practicable. 
8    (t) Notwithstanding any other provision of law, a facility 
9owner with siting approval from a county to construct a 
10commercial wind energy facility or a commercial solar energy 
11facility is authorized to cross or impact a drainage system, 
12including, but not limited to, drainage tiles, open drainage 
13ditches, culverts, and water gathering vaults, owned or under 
14the control of a drainage district under the Illinois Drainage 
15Code without obtaining prior agreement or approval from the 
16drainage district in accordance with the farmland drainage 
17plan required by subsection (j-5). 
18    (u) The amendments to this Section adopted in Public Act 
19102-1123 do not apply to: (1) an application for siting 
20approval or for a special use permit for a commercial wind 
21energy facility or commercial solar energy facility if the 
22application was submitted to a unit of local government before 
23January 27, 2023 (the effective date of Public Act 102-1123); 
24(2) a commercial wind energy facility or a commercial solar 
25energy facility if the facility owner has submitted an 
26agricultural impact mitigation agreement to the Department of 
 
 
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1Agriculture before January 27, 2023 (the effective date of 
2Public Act 102-1123); or (3) a commercial wind energy or 
3commercial solar energy development on property that is 
4located within an enterprise zone certified under the Illinois 
5Enterprise Zone Act, that was classified as industrial by the 
6appropriate zoning authority on or before January 27, 2023, 
7and that is located within 4 miles of the intersection of 
8Interstate 88 and Interstate 39.
9(Source: P.A. 102-1123, eff. 1-27-23; 103-81, eff. 6-9-23; 
10103-580, eff. 12-8-23; revised 7-29-24.)
 
11    (55 ILCS 5/5-12024 new)
12    Sec. 5-12024. Energy storage systems.
13    (a) As used in this Section:
14    "Energy storage system" means a facility with an aggregate 
15energy capacity that is greater than 1,000 kilowatts and that 
16is capable of absorbing energy and storing it for use at a 
17later time, including, but not limited to, electrochemical and 
18electromechanical technologies. "Energy storage system" does 
19not include technologies that require combustion. "Energy 
20storage system" also does not include energy storage systems 
21associated with commercial solar energy facilities or 
22commercial wind energy facilities as defined in Section 
235-12020.
24    "Excused service interruption" means any period during 
25which an energy storage system does not store or discharge 
 
 
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1electricity and that is planned or reasonably foreseeable for 
2standard commercial operation, including any unavailability 
3caused by a buyer; storage capacity tests; system emergencies; 
4curtailments, including curtailment orders; transmission 
5system outages; compliance with any operating restriction; 
6serial defects; and planned outages.
7    "Facility owner" means (i) a person with a direct 
8ownership interest in an energy storage system, regardless of 
9whether the person is involved in acquiring the necessary 
10rights, permits, and approvals or otherwise planning for the 
11construction and operation of the facility and (ii) a person 
12who, at the time the facility is being developed, is acting as 
13a developer of the facility by acquiring the necessary rights, 
14permits, and approvals or by planning for the construction and 
15operation of the facility, regardless of whether the person 
16will own or operate the facility.
17    "Force majeure" means any event or circumstance that 
18delays or prevents an energy storage system from timely 
19performing all or a portion of its commercial operations if 
20the act or event, despite the exercise of commercially 
21reasonable efforts, cannot be avoided by and is beyond the 
22reasonable control, whether direct or indirect, of, and 
23without the fault or negligence of, a facility owner or 
24operator or any of its assignees. "Force majeure" includes, 
25but is not limited to:
26        (1) fire, flood, tornado, or other natural disasters 
 
 
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1    or acts of God;
2        (2) war, civil strife, terrorist attack, or other 
3    similar acts of violence;
4        (3) unavailability of materials, equipment, services, 
5    or labor, including unavailability due to global supply 
6    chain shortages;
7        (4) utility or energy shortages or acts or omissions 
8    of public utility providers;
9        (5) any delay resulting from a pandemic, epidemic, or 
10    other public health emergency or related restrictions; and
11        (6) litigation or a regulatory proceeding regarding a 
12    facility.
13    "NFPA" means the National Fire Protection Association.
14    "Nonparticipating property" means real property that is 
15not a participating property.
16    "Nonparticipating residence" means a residence that is 
17located on nonparticipating property and that exists and is 
18occupied on the date that the application for a permit to 
19develop an energy storage system is filed with the county.
20    "Occupied community building" means a school, place of 
21worship, day care facility, public library, or community 
22center that is occupied on the date that the application for a 
23permit to develop an energy storage system is filed with the 
24county in which the building is located.
25    "Participating property" means real property that is the 
26subject of a written agreement between a facility owner and 
 
 
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1the owner of the real property and that provides the facility 
2owner an easement, option, lease, or license to use the real 
3property for the purpose of constructing an energy storage 
4system or supporting facilities.
5    "Protected lands" means real property that is: (i) subject 
6to a permanent conservation right consistent with the Real 
7Property Conservation Rights Act; or (ii) registered or 
8designated as a nature preserve, buffer, or land and water 
9reserve under the Illinois Natural Areas Preservation Act.
10    "Supporting facilities" means the transmission lines, 
11substations, switchyard, access roads, meteorological towers, 
12storage containers, and equipment associated with the 
13generation, storage, and dispatch of electricity by an energy 
14storage system.
15    (b) Notwithstanding any other provision of law, if a 
16county has formed a zoning commission and adopted formal 
17zoning under Section 5-12007, then a county may establish 
18standards for energy storage systems in areas of the county 
19that are not within the zoning jurisdiction of a municipality. 
20The standards may include all of the requirements specified in 
21this Section but may not include requirements for energy 
22storage systems that are more restrictive than specified in 
23this Section or requirements that are not specified in this 
24Section.
25    (c) A county may require the energy storage facility to 
26comply with the version of NFPA 855 "Standard for the 
 
 
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1Installation of Stationary Energy Storage Systems" in effect 
2on the effective date of this amendatory Act or any successor 
3standard issued by the NFPA in effect on the date of siting or 
4special use permit approval. A county may not include 
5requirements for energy storage systems that are more 
6restrictive than NFPA 855 "Standard for the Installation of 
7Stationary Energy Storage Systems" unless required by this 
8Section.
9    (d) If a county has elected to establish standards under 
10subsection (b), then the zoning board of appeals for the 
11county shall hold at least one public hearing before the 
12county grants (i) siting approval or a special use permit for 
13an energy storage system or (ii) modification of an approved 
14siting or special use permit. The public hearing shall be 
15conducted in accordance with the Open Meetings Act and shall 
16conclude not more than 60 days after the filing of the 
17application for the facility. The county shall allow 
18interested parties to a special use permit an opportunity to 
19present evidence and to cross-examine witnesses at the 
20hearing, but the county may impose reasonable restrictions on 
21the public hearing, including reasonable time limitations on 
22the presentation of evidence and the cross-examination of 
23witnesses. The county shall also allow public comment at the 
24public hearing in accordance with the Open Meetings Act. The 
25county shall make its siting and permitting decisions not more 
26than 30 days after the conclusion of the public hearing. 
 
 
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1Notice of the hearing shall be published in a newspaper of 
2general circulation in the county.
3    (e) A county with an existing zoning ordinance in conflict 
4with this Section shall amend that zoning ordinance to comply 
5with this Section within 120 days after the effective date of 
6this amendatory Act of the 104th General Assembly.
7    (f) A county shall require an energy storage system to be 
8sited as follows, with setback distances measured from the 
9nearest edge of the nearest battery or other electrochemical 
10or electromechanical enclosure:
 
11Setback Description           Setback Distance
 
12Occupied Community            150 feet from the nearest 
13Buildings and                 point of the outside wall of
14Nonparticipating Residences   the occupied community building
15                              or nonparticipating residence
 
16Boundary Lines of             50 feet to the nearest point
17Occupied Community            on the property line of
18Buildings and                 the occupied community building
19Nonparticipating Residences   or nonparticipating property
 
20Public Road Rights-of-Way     50 feet from the nearest edge
21                              of the right-of-way
22        (2) A county shall also require an energy storage 
 
 
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1    system to be sited so that the facility's perimeter is 
2    enclosed by fencing having a height of at least 7 feet and 
3    no more than 25 feet.
4    This Section does not exempt or excuse compliance with 
5electric facility clearances approved or required by the 
6National Electrical Code, the National Electrical Safety Code, 
7the Illinois Commerce Commission, the Federal Energy 
8Regulatory Commission, and their designees or successors.
9    (g) A county may not set a sound limitation for energy 
10storage systems that is more restrictive than the sound 
11limitations established by the Illinois Pollution Control 
12Board under 35 Ill. Adm. Code Parts 900, 901, and 910. After 
13commercial operation, a county may require the facility owner 
14to provide, not more than once, octave band sound pressure 
15level measurements from a reasonable number of sampled 
16locations at the perimeter of the energy storage system to 
17demonstrate compliance with this Section.
18    (h) The provisions set forth in subsection (f) may be 
19waived subject to the written consent of the owner of each 
20affected nonparticipating property or nonparticipating 
21residence.
22    (i) A county may not place any restriction on the 
23installation or use of an energy storage system unless it has 
24formed a zoning commission and adopted formal zoning under 
25Section 5-12007 and adopts an ordinance that complies with 
26this Section. A county may not establish siting standards for 
 
 
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1supporting facilities that preclude development of an energy 
2storage system.
3    (j) A request for siting approval or a special use permit 
4for an energy storage system, or modification of an approved 
5siting approval or special use permit, shall be approved if 
6the request complies with the standards and conditions imposed 
7in this Code, the zoning ordinance adopted consistent with 
8this Section, and other State and federal statutes and 
9regulations. The siting approval or special use permit 
10approved by the county shall grant the facility owner a period 
11of at least 3 years after county approval to obtain a building 
12permit or commence construction of the energy storage system, 
13before the siting approval or special use permit may become 
14subject to revocation by the county. Facility owners may be 
15granted an extension on obtaining building permits or 
16commencing constructing upon a showing of good cause. A 
17facility owner's request for an extension may not be 
18unreasonably withheld, conditioned, or denied.
19    (k) A county may not adopt zoning regulations that 
20disallow, permanently or temporarily, an energy storage system 
21from being developed or operated in any district zones to 
22allow agricultural or industrial uses.
23    (l) A facility owner shall file a farmland drainage plan 
24with the county and impacted drainage districts that outlines 
25how surface and subsurface drainage of farmland will be 
26restored during and following the construction or 
 
 
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1deconstruction of the energy storage system. The plan shall be 
2created independently by the facility owner and shall include 
3the location of any potentially impacted drainage district 
4facilities to the extent the information is publicly available 
5from the county or the drainage district and plans to repair 
6any subsurface drainage affected during construction or 
7deconstruction using procedures outlined in the 
8decommissioning plan. All surface and subsurface damage shall 
9be repaired as soon as reasonably practicable.
10    (m) A facility owner shall compensate landowners for crop 
11losses or other agricultural damages resulting from damage to 
12a drainage system caused by the construction of an energy 
13storage system. The facility owner shall repair or pay for the 
14repair of all damage to the subsurface drainage system caused 
15by the construction of the energy storage system. The facility 
16owner shall repair or pay for the repair and restoration of 
17surface drainage caused by the construction or deconstruction 
18of the energy storage facility as soon as reasonably 
19practicable.    
20    (n) County siting approval or special use permit 
21application fees for an energy storage system shall not exceed 
22the lesser of (i) $5,000 per each megawatt of nameplate 
23capacity of the energy storage system or (ii) $50,000.
24    (o) The county may require a facility owner to provide a 
25decommissioning plan to the county. The decommissioning plan 
26may include all requirements for decommissioning plans in NFPA 
 
 
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1855 and may also require the facility owner to:
2        (1) state how the energy storage system will be 
3    decommissioned, including removal to a depth of 3 feet of 
4    all structures that have no ongoing purpose and all debris 
5    and restoration of the soil and any vegetation to a 
6    condition as close as reasonably practicable to the soil's 
7    and vegetation's preconstruction condition within 18 
8    months of the end of project life or facility abandonment;
9        (2) include provisions related to commercially 
10    reasonable efforts to reuse or recycle of equipment and 
11    components associated with the commercial offsite energy 
12    storage system;
13        (3) include financial assurance in the form of a 
14    reclamation or surety bond or other commercially available 
15    financial assurance that is acceptable to the county, with 
16    the county or participating property owner as beneficiary. 
17    The amount of the financial assurance shall not be more 
18    than the estimated cost of decommissioning the energy 
19    facility, after deducting salvage value, as calculated by 
20    a professional engineer licensed to practice engineering 
21    in this State with expertise in preparing decommissioning 
22    estimates, retained by the applicant. The financial 
23    assurance shall be provided to the county incrementally as 
24    follows:
25            (A) 25% before the start of full commercial 
26        operation;
 
 
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1            (B) 50% before the start of the 5th year of 
2        commercial operation; and
3            (C) 100% by the start of the tenth year of 
4        commercial operation;
5        (4) update the amount of the financial assurance not 
6    more than every 5 years for the duration of commercial 
7    operations. The amount shall be calculated by a 
8    professional engineer licensed to practice engineering in 
9    this State with expertise in decommissioning, hired by the 
10    facility owner; and
11        (5) decommission the energy storage system, in 
12    accordance with an approved decommissioning plan, within 
13    18 months after abandonment. An energy storage system that 
14    has not stored electrical energy for 12 consecutive months 
15    or that fails, for a period of 6 consecutive months, to pay 
16    a property owner who is party to a written agreement, 
17    including, but not limited to, an easement, option, lease, 
18    or license under the terms of which an energy storage 
19    system is constructed on the property, amounts owed in 
20    accordance with the written agreement shall be considered 
21    abandoned, except when the inability to store energy is 
22    the result of an event of force majeure or excused service 
23    interruption.
24    (p) A county may not condition approval of an energy 
25storage system on a property value guarantee and may not 
26require a facility owner to pay into a neighboring property 
 
 
10400SB0025ham003- 478 -LRB104 07069 AAS 29208 a

1devaluation escrow account.
2    (q) A county may require that a facility owner provide the 
3results and recommendations from consultation with the 
4Department of Natural Resources that are obtained through the 
5Ecological Compliance Assessment Tool (EcoCAT) or a comparable 
6successor tool.
7    (r) A county may require an energy storage system to 
8adhere to the recommendations provided by the Department of 
9Natural Resources in an Agency Action Report under 17 Ill. 
10Admin. Code 1075.
11    (s) A county may require a facility owner to:
12        (1) demonstrate avoidance of protected lands as 
13    identified by the Department of Natural Resources and the 
14    Illinois Nature Preserves Commission; or
15        (2) consider the recommendations of the Department of 
16    Natural Resources for setbacks from protected lands, 
17    including areas identified by the Illinois Nature 
18    Preserves Commission.
19    (t) A county may require that a facility owner provide 
20evidence of consultation with the Illinois Historic 
21Preservation Division to assess potential impacts on 
22State-registered historic sites under the Illinois State 
23Agency Historic Resources Preservation Act.
24    (u) A county may require that an application for siting 
25approval or special use permit include the following 
26information on a site plan:
 
 
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1        (1) a description of the property lines and physical 
2    features, including roads, for the facility site;
3        (2) a description of the proposed changes to the 
4    landscape of the facility site, including vegetation 
5    clearing and planting, exterior lighting, and screening or 
6    structures; and
7        (3) a description of the zoning district designation 
8    for the parcel of land comprising the facility site.
9    (v) A county may not prohibit an energy storage system 
10from undertaking periodic augmentation to maintain the 
11approximate original capacity of the energy storage system. A 
12county may not require renewed or additional siting approval 
13or special use permit approval of periodic augmentation to 
14maintain the approximate original capacity of the energy 
15storage system.
16    (w) A county that issues a building permit for energy 
17storage systems shall review and process building permit 
18applications within 60 days after receipt of the building 
19permit application. If a county does not grant or deny the 
20building permit application within 60 days, the building 
21permit shall be deemed granted. If a county denies a building 
22permit application, it shall specify the reason for the denial 
23in writing as part of its denial.
24    (x) A county may require a single building permit and 
25permit fee for the facility which includes all supporting 
26facilities. A county building permit fee for an energy storage 
 
 
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1system shall not exceed the lesser of (i) $5,000 per each 
2megawatt of nameplate capacity of the energy storage system or 
3(ii) $50,000. A county may require that the application for 
4building permit contain:
5        (1) an electrical diagram detailing the battery energy 
6    storage system layout, associated components, and 
7    electrical interconnection methods, with all National 
8    Electrical Code compliant disconnects and overcurrent 
9    devices; and
10        (2) an equipment specification sheet.
11    (y) A county may require the facility owner to submit to 
12the county prior to the facility's commercial operation a 
13commissioning report meeting the requirements of NFPA 855 
14Sections 4.2.4, 6.1.3, and 6.1.5.5, as published in 2023, or 
15the applicable Sections in the most recent version of NFPA 
16855.
17    (z) A county may require the facility owner to submit to 
18the county prior to the facility's commercial operation a 
19hazard mitigation analysis meeting the requirements of NFPA 
20855 Section 4.4 or the applicable Sections in the most recent 
21version of NFPA 855.
22    (aa) A county may require the facility owner to submit to 
23the county an emergency operations plan meeting the 
24requirements of NFPA 855 Section 4.3.2.1.4, published in 2023, 
25or applicable Sections in the most recent version of NFPA 855, 
26prior to commercial operation.
 
 
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1    (bb) A county may require a warning that complies with 
2requirements in NFPA 855 Section 4.7.4, published in 2023, or 
3applicable sections in the most recent version of NFPA 855.
4    (cc) A county may require the energy storage system to 
5adhere to the principles for responsible outdoor lighting 
6provided by the International Dark-Sky Association and shall 
7limit outdoor lighting to that which is minimally required for 
8safety and operational purposes. Any outdoor lighting shall be 
9reasonably shielded and downcast from all residences and 
10adjacent properties.
11    (dd) This Section does not exempt compliance with fire and 
12safety standards and guidance established for the installation 
13of lithium-ion battery energy storage systems set by the NFPA.
14    (ee) Prior to commencement of commercial operation, the 
15facility owner shall offer to provide training for local fire 
16departments and emergency responders in accordance with the 
17facility emergency operations plan. A copy of the emergency 
18operations plan shall be given to the facility owner, the 
19local fire department, and emergency responders. All batteries 
20integrated within an energy storage system shall be listed 
21under the UL 1973 Standard. All batteries integrated within an 
22energy storage system shall be listed in accordance with UL 
239540 Standard, either from the manufacturer or by a field 
24evaluation.
25    (ff) If a facility owner enters into a road use agreement 
26with the Department of Transportation, a road district, or 
 
 
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1other unit of local government relating to an energy storage 
2system, then the road use agreement shall require the facility 
3owner to be responsible for (i) the reasonable cost of 
4improving, if necessary, roads used by the facility owner to 
5construct the energy storage system and (ii) the reasonable 
6cost of repairing roads used by the facility owner during 
7construction of the energy storage system so that those roads 
8are in a condition that is safe for the driving public after 
9the completion of the facility's construction. A roadway 
10improved in preparation for and during the construction of the 
11energy storage system shall be repaired and restored to the 
12improved condition at the reasonable cost of the developer if 
13the roadways have degraded or were damaged as a result of 
14construction-related activities.
15    The road use agreement shall not require the facility 
16owner to pay costs, fees, or charges for road work that is not 
17specifically and uniquely attributable to the construction of 
18the energy storage system. No road district or other unit of 
19local government may request or require a fine, permit fee, or 
20other payment obligation as a requirement for a road use 
21agreement with a facility owner unless the amount of the fine, 
22permit fee, or other payment obligation is equivalent to the 
23amount of actual expenses incurred by the road district or 
24other unit of local government for negotiating, executing, 
25constructing, or implementing the road use agreement. The road 
26use agreement shall not require the facility owner to perform 
 
 
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1or pay for any road work that is unrelated to the road 
2improvements required for the construction of the commercial 
3wind energy facility or the commercial solar energy facility 
4or the restoration of the roads used by the facility owner 
5during construction-related activities.
6    (gg) The provisions of this amendatory Act of the 104th 
7General Assembly do not apply to an application for siting 
8approval or special use permit for an energy storage system if 
9the application was submitted to a county before the effective 
10date of this amendatory Act of the 104th General Assembly.
 
11    (55 ILCS 5/Art. 5 Div. 5-46 heading new)
12
Division 5-46.  Solar Bill of Rights

 
13    (55 ILCS 5/5-46005 new)
14    Sec. 5-46005. Definitions. As used in this Division:
15    "Low-voltage solar-powered device" means a piece of 
16equipment designed for a particular purpose, including, but 
17not limited to, doorbells, security systems, and illumination 
18equipment, powered by a solar collector operating at less than 
1950 volts, and located:
20        (1) entirely within the lot or parcel owned by the 
21    property owner; or
22        (2) within a common area without being permanently 
23    attached to common property.
24    "Solar collector" means:
 
 
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1        (1) an assembly, structure, or design, including 
2    passive elements, used for gathering, concentrating, or 
3    absorbing direct and indirect solar energy and specially 
4    designed for holding a substantial amount of useful 
5    thermal energy and to transfer that energy to a gas, 
6    solid, or liquid or to use that energy directly;
7        (2) a mechanism that absorbs solar energy and converts 
8    it into electricity;
9        (3) a mechanism or process used for gathering solar 
10    energy through wind or thermal gradients; or
11        (4) a component used to transfer thermal energy to a 
12    gas, solid, or liquid, or to convert it into electricity.
13    "Solar energy" means radiant energy received from the sun 
14at wavelengths suitable for heat transfer, photosynthetic use, 
15or photovoltaic use.
16    "Solar energy system" means:
17        (1) a complete assembly, structure, or design of a 
18    solar collector or a solar storage mechanism that uses 
19    solar energy for generating electricity or for heating or 
20    cooling gases, solids, liquids, or other materials; and
21        (2) the design, materials, or elements of a system and 
22    its maintenance, operation, and labor components, and the 
23    necessary components, if any, of supplemental conventional 
24    energy systems designed or constructed to interface with a 
25    solar energy system.
26    "Solar storage mechanism" means equipment or elements, 
 
 
10400SB0025ham003- 485 -LRB104 07069 AAS 29208 a

1such as piping and transfer mechanisms, containers, heat 
2exchangers, batteries, or controls thereof and gases, solids, 
3liquids, or combinations thereof, that are utilized for 
4storing solar energy, gathered by a solar collector, for 
5subsequent use.
 
6    (55 ILCS 5/5-46010 new)
7    Sec. 5-46010. Prohibitions. Notwithstanding any provision 
8of this Code or other provision of law, the adoption of any 
9ordinance or resolution or the exercise of any power by a 
10county that prohibits or has the effect of prohibiting the 
11installation of a solar energy system or low-voltage 
12solar-powered devices is expressly prohibited.
 
13    (55 ILCS 5/5-46020 new)
14    Sec. 5-46020. Costs; attorney's fees. In any litigation 
15arising under this Division or involving the application of 
16this Division, the prevailing party shall be entitled to costs 
17and reasonable attorney's fees.
 
18    (55 ILCS 5/5-46025 new)
19    Sec. 5-46025. Applicability.
20    (a) As used in this Section, "shared roof" means any roof 
21that (i) serves more than one unit, including, but not limited 
22to, a contiguous roof serving adjacent units, or (ii) is part 
23of the common elements or common area of a unit.
 
 
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1    (b) This Division shall not apply to any building that:
2        (1) is greater than 60 feet in height; or
3        (2) has a shared roof.
4    (c) Notwithstanding subsection (b) of this Section, this 
5Division shall apply to any building with a shared roof:
6        (1) where the solar energy system is located entirely 
7    within that portion of the shared roof that is owned and 
8    maintained by the property owner;
9        (2) where all property owners sharing the shared roof 
10    are in agreement to install a solar energy system; or
11        (3) to the extent this Division applies to low-voltage 
12    solar-powered devices.    
 
13    Section 90-30. The Illinois Municipal Code is amended by 
14adding Division 15.5 as follows:
 
15    (65 ILCS 5/Art. 11 Div. 15.5 heading new)
16
Division 15.5.  Solar Bill of Rights

 
17    (65 ILCS 5/11-15.5-5 new)
18    Sec. 11-15.5-5. Definitions. As used in this Division:
19    "Low-voltage solar-powered device" means a piece of 
20equipment designed for a particular purpose, including, but 
21not limited to, doorbells, security systems, and illumination 
22equipment, powered by a solar collector operating at less than 
2350 volts, and located:
 
 
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1        (1) entirely within the lot or parcel owned by the 
2    property owner; or
3        (2) within a common area without being permanently 
4    attached to common property.
5    "Solar collector" means:
6        (1) an assembly, structure, or design, including 
7    passive elements, used for gathering, concentrating, or 
8    absorbing direct and indirect solar energy and specially 
9    designed for holding a substantial amount of useful 
10    thermal energy and to transfer that energy to a gas, 
11    solid, or liquid or to use that energy directly;
12        (2) a mechanism that absorbs solar energy and converts 
13    it into electricity;
14        (3) a mechanism or process used for gathering solar 
15    energy through wind or thermal gradients; or
16        (4) a component used to transfer thermal energy to a 
17    gas, solid, or liquid, or to convert it into electricity.
18    "Solar energy" means radiant energy received from the sun 
19at wavelengths suitable for heat transfer, photosynthetic use, 
20or photovoltaic use.
21    "Solar energy system" means:
22        (1) a complete assembly, structure, or design of a 
23    solar collector or a solar storage mechanism that uses 
24    solar energy for generating electricity or for heating or 
25    cooling gases, solids, liquids, or other materials; and
26        (2) the design, materials, or elements of a system and 
 
 
10400SB0025ham003- 488 -LRB104 07069 AAS 29208 a

1    its maintenance, operation, and labor components, and the 
2    necessary components, if any, of supplemental conventional 
3    energy systems designed or constructed to interface with a 
4    solar energy system.
5    "Solar storage mechanism" means equipment or elements, 
6such as piping and transfer mechanisms, containers, heat 
7exchangers, batteries, or controls thereof and gases, solids, 
8liquids, or combinations thereof, that are utilized for 
9storing solar energy, gathered by a solar collector, for 
10subsequent use.
 
11    (65 ILCS 5/11-15.5-10 new)
12    Sec. 11-15.5-10. Prohibitions. Notwithstanding any 
13provision of this Code or other provision of law, the adoption 
14of any ordinance or resolution or the exercise of any power, by 
15municipality that prohibits or has the effect of prohibiting 
16the installation of a solar energy system or low-voltage 
17solar-powered devices is expressly prohibited. Municipalities 
18that own local electric distribution systems may adopt and 
19implement reasonable policies, consistent with Section 17-900 
20of the Public Utilities Act, regarding the interconnection and 
21use of solar energy systems.
 
22    (65 ILCS 5/11-15.5-20 new)
23    Sec. 11-15.5-20. Costs; attorney's fees. In any litigation 
24arising under this Division or involving the application of 
 
 
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1this Division, the prevailing party shall be entitled to costs 
2and reasonable attorney's fees.
 
3    (65 ILCS 5/11-15.5-25 new)
4    Sec. 11-15.5-25. Applicability.
5    (a) As used in this Section, "shared roof" means any roof 
6that (i) serves more than one unit, including, but not limited 
7to, a contiguous roof serving adjacent units, or (ii) is part 
8of the common elements or common area of a unit.
9    (b) This Division shall not apply to any building that:
10        (1) is greater than 60 feet in height; or
11        (2) has a shared roof.
12    (c) Notwithstanding subsection (b) of this Section, this 
13Division shall apply to any building with a shared roof:
14        (1) where the solar energy system is located entirely 
15    within that portion of the shared roof owned and 
16    maintained by the property owner;
17        (2) where all property owners sharing the shared roof 
18    are in agreement to install a solar energy system; or
19        (3) to the extent this Division applies to low-voltage 
20    solar-powered devices.
 
21    Section 90-35. The Public Utilities Act is amended by 
22changing Sections 7-102, 8-103B, 8-406, 8-512, 9-229, 
2316-107.5, 16-107.6, 16-108, 16-108.19, 16-108.30, 16-111.5, 
2416-111.7, 16-115A, 16-119A, and 17-900 and by adding Sections 
 
 
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18-101.1, 8-513, 16-105.17, 16-107.8, 16-107.9, 16-126.2, 
216-145, 16-201, 16-202, 20-140, 20-145, and Article 23 as 
3follows:
 
4    (220 ILCS 5/7-102)  (from Ch. 111 2/3, par. 7-102)
5    Sec. 7-102. Transactions requiring Commission approval. 
6    (A) Unless the consent and approval of the Commission is 
7first obtained or unless such approval is waived by the 
8Commission or is exempted in accordance with the provisions of 
9this Section or of any other Section of this Act:    
10        (a) No 2 or more public utilities may enter into 
11    contracts with each other that will enable such public 
12    utilities to operate their lines or plants in connection 
13    with each other.    
14        (b) No public utility may purchase, lease, or in any 
15    other manner acquire control, direct or indirect, over the 
16    franchises, licenses, permits, plants, equipment, business 
17    or other property of any other public utility.    
18        (c) No public utility may assign, transfer, lease, 
19    mortgage, sell (by option or otherwise), or otherwise 
20    dispose of or encumber the whole or any part of its 
21    franchises, licenses, permits, plant, equipment, business, 
22    or other property, but the consent and approval of the 
23    Commission shall not be required for the sale, lease, 
24    assignment or transfer (1) by any public utility of any 
25    tangible personal property which is not necessary or 
 
 
10400SB0025ham003- 491 -LRB104 07069 AAS 29208 a

1    useful in the performance of its duties to the public, or    
2    (2) by any electric utility, as defined by Section 16-105, 
3    of functional control to a regional transmission operator, 
4    as defined in Section 16-126, of facilities operating at 
5    69,000 volts and that would otherwise qualify for such 
6    transfer under the applicable rules of the regional 
7    transmission operator taking functional control, or (3) by 
8    any railroad of any real or tangible personal property.    
9        (d) No public utility may by any means, direct or 
10    indirect, merge or consolidate its franchises, licenses, 
11    permits, plants, equipment, business or other property 
12    with that of any other public utility.    
13        (e) No public utility may purchase, acquire, take or 
14    receive any stock, stock certificates, bonds, notes or 
15    other evidences of indebtedness of any other public 
16    utility.    
17        (f) No public utility may in any manner, directly or 
18    indirectly, guarantee the performance of any contract or 
19    other obligation of any other person, firm or corporation 
20    whatsoever.    
21        (g) No public utility may use, appropriate, or divert 
22    any of its moneys, property or other resources in or to any 
23    business or enterprise which is not, prior to such use, 
24    appropriation or diversion essentially and directly 
25    connected with or a proper and necessary department or 
26    division of the business of such public utility; provided 
 
 
10400SB0025ham003- 492 -LRB104 07069 AAS 29208 a

1    that this subsection shall not be construed as modifying 
2    subsections (a) through (e) of this Section.    
3        (h) No public utility may, directly or indirectly, 
4    invest, loan or advance, or permit to be invested, loaned 
5    or advanced any of its moneys, property or other resources 
6    in, for, in behalf of or to any other person, firm, trust, 
7    group, association, company or corporation whatsoever, 
8    except that no consent or approval by the Commission is 
9    necessary for the purchase of stock in development credit 
10    corporations organized under the Illinois Development 
11    Credit Corporation Act, providing that no such purchase 
12    may be made hereunder if, as a result of such purchase, the 
13    cumulative purchase price of all such shares owned by the 
14    utility would exceed one-fiftieth of one per cent of the 
15    utility's gross operating revenue for the preceding 
16    calendar year.
17    (B) Any public utility may present to the Commission for 
18approval options or contracts to sell or lease real property, 
19notwithstanding that the value of the property under option 
20may have changed between the date of the option and the 
21subsequent date of sale or lease. If the options or contracts 
22are approved by the Commission, subsequent sales or leases in 
23conformance with those options or contracts may be made by the 
24public utility without any further action by the Commission. 
25If approval of the options or contracts is denied by the 
26Commission, the options or contracts are void and any 
 
 
10400SB0025ham003- 493 -LRB104 07069 AAS 29208 a

1consideration theretofore paid to the public utility must be 
2refunded within 30 days following disapproval of the 
3application.
4    (C) The proceedings for obtaining the approval of the 
5Commission provided for in this Section shall be as follows: 
6There shall be filed with the Commission a petition, joint or 
7otherwise, as the case may be, signed and verified by the 
8president, any vice president, secretary, treasurer, 
9comptroller, general manager, or chief engineer of the 
10respective companies, or by the person or company, as the case 
11may be, clearly setting forth the object and purposes desired, 
12and setting forth the full and complete terms of the proposed 
13assignment, transfer, lease, mortgage, purchase, sale, merger, 
14consolidation, contract or other transaction, as the case may 
15be. Upon the filing of such petition, the Commission shall, if 
16it deems necessary, fix a time and place for the hearing 
17thereon. After such hearing, or in case no hearing is 
18required, if the Commission is satisfied that such petition 
19should reasonably be granted, and that the public will be 
20convenienced thereby, the Commission shall make such order in 
21the premises as it may deem proper and as the circumstances may 
22require, attaching such conditions as it may deem proper, and 
23thereupon it shall be lawful to do the things provided for in 
24such order. The Commission shall impose such conditions as 
25will protect the interest of minority and preferred 
26stockholders.
 
 
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1    (D) The Commission shall have power by general rules 
2applicable alike to all public utilities, other than electric 
3and gas public utilities, affected thereby to waive the filing 
4and necessity for approval of the following: (a) sales of 
5property involving a consideration of not more than $300,000 
6for utilities with gross revenues in excess of $50,000,000 
7annually and a consideration of not more than $100,000 for all 
8other utilities; (b) leases, easements and licenses involving 
9a consideration or rental of not more than $30,000 per year for 
10utilities with gross revenues in excess of $50,000,000 
11annually and a consideration or rental of not more than 
12$10,000 per year for all other utilities; (c) leases of office 
13building space not required by the public utility in rendering 
14service to the public; (d) the temporary leasing, lending or 
15interchanging of equipment in the ordinary course of business 
16or in case of an emergency; and (e) purchase-money mortgages 
17given by a public utility in connection with the purchase of 
18tangible personal property where the total obligation to be 
19secured shall be payable within a period not exceeding one 
20year. However, if the Commission, after a hearing, finds that 
21any public utility to which such rule is applicable is abusing 
22or has abused such general rule and thereby is evading 
23compliance with the standard established herein, the 
24Commission shall have power to require such public utility to 
25thereafter file and receive the Commission's approval upon all 
26such transactions as described in this Section, but such 
 
 
10400SB0025ham003- 495 -LRB104 07069 AAS 29208 a

1general rule shall remain in full force and effect as to all 
2other public utilities to which such rule is applicable.
3    (E) The filing of, and the consent and approval of the 
4Commission for, any assignment, transfer, lease, mortgage, 
5purchase, sale, merger, consolidation, contract or other 
6transaction by an electric or gas public utility with gross 
7revenues in all jurisdictions of $250,000,000 or more annually 
8involving a sale price or annual consideration in an amount of 
9$5,000,000 or less shall not be required. The Commission shall 
10also have the authority, on petition by an electric or gas 
11public utility with gross revenues in all jurisdictions of 
12$250,000,000 or more annually, to establish by order higher 
13thresholds than the foregoing for the requirement of approval 
14of transactions by the Commission pursuant to this Section for 
15the electric or gas public utility, but no greater than 1% of 
16the electric or gas public utility's average total gross 
17utility plant in service in the case of sale, assignment or 
18acquisition of property, or 2.5% of the electric or gas public 
19utility's total revenue in the case of other sales price or 
20annual consideration, in each case based on the preceding 
21calendar year, and subject to the power of the Commission, 
22after notice and hearing, to further revise those thresholds 
23at a later date. In addition to the foregoing, the Commission 
24shall have power by general rules applicable alike to all 
25electric and gas public utilities affected thereby to waive 
26the filing and necessity for approval of the following: (a) 
 
 
10400SB0025ham003- 496 -LRB104 07069 AAS 29208 a

1sales of property involving a consideration of $100,000 or 
2less for electric and gas utilities with gross revenues in all 
3jurisdictions of less than $250,000,000 annually; (b) leases, 
4easements and licenses involving a consideration or rental of 
5not more than $10,000 per year for electric and gas utilities 
6with gross revenues in all jurisdictions of less than 
7$250,000,000 annually; (c) leases of office building space not 
8required by the electric or gas public utility in rendering 
9service to the public; (d) the temporary leasing, lending or 
10interchanging of equipment in the ordinary course of business 
11or in the case of an emergency; and (e) purchase-money 
12mortgages given by an electric or gas public utility in 
13connection with the purchase of tangible personal property 
14where the total obligation to be secured shall be payable 
15within a period of one year or less. However, if the 
16Commission, after a hearing, finds that any electric or gas 
17public utility is abusing or has abused such general rule and 
18thereby is evading compliance with the standard established 
19herein, the Commission shall have power to require such 
20electric or gas public utility to thereafter file and receive 
21the Commission's approval upon all such transactions as 
22described in this Section and not exempted pursuant to the 
23first sentence of this paragraph or to subsection (g) of 
24Section 16-111 of this Act, but such general rule shall remain 
25in full force and effect as to all other electric and gas 
26public utilities.
 
 
10400SB0025ham003- 497 -LRB104 07069 AAS 29208 a

1    Every assignment, transfer, lease, mortgage, sale or other 
2disposition or encumbrance of the whole or any part of the 
3franchises, licenses, permits, plant, equipment, business or 
4other property of any public utility, or any merger or 
5consolidation thereof, and every contract, purchase of stock, 
6or other transaction referred to in this Section and not 
7exempted in accordance with the provisions of the immediately 
8preceding paragraph of this Section, made otherwise than in 
9accordance with an order of the Commission authorizing the 
10same, except as provided in this Section, shall be void. The 
11provisions of this Section shall not apply to any transactions 
12by or with a political subdivision or municipal corporation of 
13this State.
14    (F) The provisions of this Section do not apply to the 
15purchase or sale of emission allowances created under and 
16defined in Title IV of the federal Clean Air Act Amendments of 
171990 (P.L. 101-549), as amended.
18(Source: P.A. 90-561, eff. 12-16-97; 91-357, eff. 7-29-99.)
 
19    (220 ILCS 5/8-101.1 new)
20    Sec. 8-101.1. Duties of public utilities; labor force.
21    (a) As used in this Section:
22    "Labor force" means the employees hired directly by the 
23utility and all employees of any and all suppliers and 
24subcontractors of the utility tasked with the construction, 
25maintenance and repair of such utility's infrastructure.
 
 
10400SB0025ham003- 498 -LRB104 07069 AAS 29208 a

1    "Public utility" means a public utility, as defined in 
2Section 3-105 of this Act, serving more than 100,000 customers 
3as of January 1, 2025.
4    "Substantial change in labor force" means either (1) a 
5greater than 5% reduction in the total labor force or (2) more 
6than a 5% decrease in the ratio of labor force spending 
7compared to capital spending.
8    (b) A public utility shall ensure that it has the 
9necessary labor force in order to furnish, provide, and 
10maintain such service instrumentalities, equipment, and 
11facilities to promote the safety, health, comfort, and 
12convenience of its patrons, employees, and the public and to 
13be in all respects adequate, efficient, just, and reasonable.
14    (c) Unless the Commission specifically orders and except 
15as otherwise provided in this Section, no substantial change 
16shall be made by any public utility in its labor force unless 
17the public utility provides notice to the Commission at least 
1845 days before the implementation of the change. A public 
19utility shall include a report with its notice that provides 
20the following:
21        (1) a detailed analysis and explanation of how and why 
22    a change in a specific law, regulation, or market factor 
23    requires the public utility to make the substantial change 
24    in its labor force; and
25        (2) whether the substantial change in the public 
26    utility's labor force, at a minimum:
 
 
10400SB0025ham003- 499 -LRB104 07069 AAS 29208 a

1            (i) is in the public interest;
2            (ii) will not endanger the quality and 
3        availability of public utility services;
4            (iii) will not have a negative impact on the 
5        safety or reliability of public utility services; and
6            (iv) is designed to minimize the financial 
7        hardship on the members of its labor force impacted by 
8        the substantial change.
 
9    (220 ILCS 5/8-103B)
10    Sec. 8-103B. Energy efficiency and demand-response 
11measures.
12    (a) It is the policy of the State that electric utilities 
13are required to use cost-effective energy efficiency and 
14demand-response measures to reduce delivery load. Requiring 
15investment in cost-effective energy efficiency and 
16demand-response measures will reduce direct and indirect costs 
17to consumers by decreasing environmental impacts and by 
18avoiding or delaying the need for new generation, 
19transmission, and distribution infrastructure. It serves the 
20public interest to allow electric utilities to recover costs 
21for reasonably and prudently incurred expenditures for energy 
22efficiency and demand-response measures. As used in this 
23Section, "cost-effective" means that the measures satisfy the 
24total resource cost test. The low-income measures described in 
25subsection (c) of this Section shall not be required to meet 
 
 
10400SB0025ham003- 500 -LRB104 07069 AAS 29208 a

1the total resource cost test. For purposes of this Section, 
2the terms "energy-efficiency", "demand-response", "electric 
3utility", and "total resource cost test" have the meanings set 
4forth in the Illinois Power Agency Act. "Black, indigenous, 
5and people of color" and "BIPOC" means people who are members 
6of the groups described in subparagraphs (a) through (e) of 
7paragraph (A) of subsection (1) of Section 2 of the Business 
8Enterprise for Minorities, Women, and Persons with 
9Disabilities Act. 
10    (a-5) This Section applies to electric utilities serving 
11more than 500,000 retail customers in the State for those 
12multi-year plans commencing after December 31, 2017. 
13    (b) For purposes of this Section, through calendar year 
142026, electric utilities subject to this Section that serve 
15more than 3,000,000 retail customers in the State shall be 
16deemed to have achieved a cumulative persisting annual savings 
17of 6.6% from energy efficiency measures and programs 
18implemented during the period beginning January 1, 2012 and 
19ending December 31, 2017, which percent is based on the deemed 
20average weather normalized sales of electric power and energy 
21during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs. 
22For the purposes of this subsection (b) and subsection (b-5), 
23the 88,000,000 MWhs of deemed electric power and energy sales 
24shall be reduced by the number of MWhs equal to the sum of the 
25annual consumption of customers that have opted out of 
26subsections (a) through (j) of this Section under paragraph 
 
 
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1(1) of subsection (l) of this Section, as averaged across the 
2calendar years 2014, 2015, and 2016. After 2017, the deemed 
3value of cumulative persisting annual savings from energy 
4efficiency measures and programs implemented during the period 
5beginning January 1, 2012 and ending December 31, 2017, shall 
6be reduced each year, as follows, and the applicable value 
7shall be applied to and count toward the utility's achievement 
8of the cumulative persisting annual savings goals set forth in 
9subsection (b-5):
10        (1) 5.8% deemed cumulative persisting annual savings 
11    for the year ending December 31, 2018;
12        (2) 5.2% deemed cumulative persisting annual savings 
13    for the year ending December 31, 2019;
14        (3) 4.5% deemed cumulative persisting annual savings 
15    for the year ending December 31, 2020;
16        (4) 4.0% deemed cumulative persisting annual savings 
17    for the year ending December 31, 2021;
18        (5) 3.5% deemed cumulative persisting annual savings 
19    for the year ending December 31, 2022;
20        (6) 3.1% deemed cumulative persisting annual savings 
21    for the year ending December 31, 2023;
22        (7) 2.8% deemed cumulative persisting annual savings 
23    for the year ending December 31, 2024;
24        (8) 2.5% deemed cumulative persisting annual savings 
25    for the year ending December 31, 2025; and    
26        (9) 2.3% deemed cumulative persisting annual savings 
 
 
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1    for the year ending December 31, 2026. ;
2        (10) 2.1% deemed cumulative persisting annual savings 
3    for the year ending December 31, 2027;
4        (11) 1.8% deemed cumulative persisting annual savings 
5    for the year ending December 31, 2028;
6        (12) 1.7% deemed cumulative persisting annual savings 
7    for the year ending December 31, 2029;
8        (13) 1.5% deemed cumulative persisting annual savings 
9    for the year ending December 31, 2030;
10        (14) 1.3% deemed cumulative persisting annual savings 
11    for the year ending December 31, 2031;
12        (15) 1.1% deemed cumulative persisting annual savings 
13    for the year ending December 31, 2032;
14        (16) 0.9% deemed cumulative persisting annual savings 
15    for the year ending December 31, 2033;
16        (17) 0.7% deemed cumulative persisting annual savings 
17    for the year ending December 31, 2034;
18        (18) 0.5% deemed cumulative persisting annual savings 
19    for the year ending December 31, 2035;
20        (19) 0.4% deemed cumulative persisting annual savings 
21    for the year ending December 31, 2036;
22        (20) 0.3% deemed cumulative persisting annual savings 
23    for the year ending December 31, 2037;
24        (21) 0.2% deemed cumulative persisting annual savings 
25    for the year ending December 31, 2038;
26        (22) 0.1% deemed cumulative persisting annual savings 
 
 
10400SB0025ham003- 503 -LRB104 07069 AAS 29208 a

1    for the year ending December 31, 2039; and
2        (23) 0.0% deemed cumulative persisting annual savings 
3    for the year ending December 31, 2040 and all subsequent 
4    years.    
5    For purposes of this Section, "cumulative persisting 
6annual savings" means the total electric energy savings in a 
7given year from measures installed in that year or in previous 
8years, but no earlier than January 1, 2012, that are still 
9operational and providing savings in that year because the 
10measures have not yet reached the end of their useful lives.
11    (b-5) Beginning in 2018 and through calendar year 2026, 
12electric utilities subject to this Section that serve more 
13than 3,000,000 retail customers in the State shall achieve the 
14following cumulative persisting annual savings goals, as 
15modified by subsection (f) of this Section and as compared to 
16the deemed baseline of 88,000,000 MWhs of electric power and 
17energy sales set forth in subsection (b), as reduced by the 
18number of MWhs equal to the sum of the annual consumption of 
19customers that have opted out of subsections (a) through (j) 
20of this Section under paragraph (1) of subsection (l) of this 
21Section as averaged across the calendar years 2014, 2015, and 
222016, through the implementation of energy efficiency measures 
23during the applicable year and in prior years, but no earlier 
24than January 1, 2012:
25        (1) 7.8% cumulative persisting annual savings for the 
26    year ending December 31, 2018;
 
 
10400SB0025ham003- 504 -LRB104 07069 AAS 29208 a

1        (2) 9.1% cumulative persisting annual savings for the 
2    year ending December 31, 2019;
3        (3) 10.4% cumulative persisting annual savings for the 
4    year ending December 31, 2020;
5        (4) 11.8% cumulative persisting annual savings for the 
6    year ending December 31, 2021;
7        (5) 13.1% cumulative persisting annual savings for the 
8    year ending December 31, 2022;
9        (6) 14.4% cumulative persisting annual savings for the 
10    year ending December 31, 2023;
11        (7) 15.7% cumulative persisting annual savings for the 
12    year ending December 31, 2024;
13        (8) 17% cumulative persisting annual savings for the 
14    year ending December 31, 2025; and    
15        (9) 17.9% cumulative persisting annual savings for the 
16    year ending December 31, 2026. ;
17        (10) 18.8% cumulative persisting annual savings for 
18    the year ending December 31, 2027;
19        (11) 19.7% cumulative persisting annual savings for 
20    the year ending December 31, 2028;
21        (12) 20.6% cumulative persisting annual savings for 
22    the year ending December 31, 2029; and
23        (13) 21.5% cumulative persisting annual savings for 
24    the year ending December 31, 2030.
25    No later than December 31, 2021, the Illinois Commerce 
26Commission shall establish additional cumulative persisting 
 
 
10400SB0025ham003- 505 -LRB104 07069 AAS 29208 a

1annual savings goals for the years 2031 through 2035. No later 
2than December 31, 2024, the Illinois Commerce Commission shall 
3establish additional cumulative persisting annual savings 
4goals for the years 2036 through 2040. The Commission shall 
5also establish additional cumulative persisting annual savings 
6goals every 5 years thereafter to ensure that utilities always 
7have goals that extend at least 11 years into the future. The 
8cumulative persisting annual savings goals beyond the year 
92030 shall increase by 0.9 percentage points per year, absent 
10a Commission decision to initiate a proceeding to consider 
11establishing goals that increase by more or less than that 
12amount. Such a proceeding must be conducted in accordance with 
13the procedures described in subsection (f) of this Section. If 
14such a proceeding is initiated, the cumulative persisting 
15annual savings goals established by the Commission through 
16that proceeding shall reflect the Commission's best estimate 
17of the maximum amount of additional savings that are forecast 
18to be cost-effectively achievable unless such best estimates 
19would result in goals that represent less than 0.5 percentage 
20point annual increases in total cumulative persisting annual 
21savings. The Commission may only establish goals that 
22represent less than 0.5 percentage point annual increases in 
23cumulative persisting annual savings if it can demonstrate, 
24based on clear and convincing evidence and through independent 
25analysis, that 0.5 percentage point increases are not 
26cost-effectively achievable. The Commission shall inform its 
 
 
10400SB0025ham003- 506 -LRB104 07069 AAS 29208 a

1decision based on an energy efficiency potential study that 
2conforms to the requirements of this Section.    
3    (b-10) For purposes of this Section, through calendar year 
42026, electric utilities subject to this Section that serve 
5less than 3,000,000 retail customers but more than 500,000 
6retail customers in the State shall be deemed to have achieved 
7a cumulative persisting annual savings of 6.6% from energy 
8efficiency measures and programs implemented during the period 
9beginning January 1, 2012 and ending December 31, 2017, which 
10is based on the deemed average weather normalized sales of 
11electric power and energy during calendar years 2014, 2015, 
12and 2016 of 36,900,000 MWhs. For the purposes of this 
13subsection (b-10) and subsection (b-15), the 36,900,000 MWhs 
14of deemed electric power and energy sales shall be reduced by 
15the number of MWhs equal to the sum of the annual consumption 
16of customers that have opted out of subsections (a) through 
17(j) of this Section under paragraph (1) of subsection (l) of 
18this Section, as averaged across the calendar years 2014, 
192015, and 2016. After 2017, the deemed value of cumulative 
20persisting annual savings from energy efficiency measures and 
21programs implemented during the period beginning January 1, 
222012 and ending December 31, 2017, shall be reduced each year, 
23as follows, and the applicable value shall be applied to and 
24count toward the utility's achievement of the cumulative 
25persisting annual savings goals set forth in subsection 
26(b-15):
 
 
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1        (1) 5.8% deemed cumulative persisting annual savings 
2    for the year ending December 31, 2018;
3        (2) 5.2% deemed cumulative persisting annual savings 
4    for the year ending December 31, 2019;
5        (3) 4.5% deemed cumulative persisting annual savings 
6    for the year ending December 31, 2020;
7        (4) 4.0% deemed cumulative persisting annual savings 
8    for the year ending December 31, 2021;
9        (5) 3.5% deemed cumulative persisting annual savings 
10    for the year ending December 31, 2022;
11        (6) 3.1% deemed cumulative persisting annual savings 
12    for the year ending December 31, 2023;
13        (7) 2.8% deemed cumulative persisting annual savings 
14    for the year ending December 31, 2024;
15        (8) 2.5% deemed cumulative persisting annual savings 
16    for the year ending December 31, 2025; and    
17        (9) 2.3% deemed cumulative persisting annual savings 
18    for the year ending December 31, 2026. ;    
19        (10) 2.1% deemed cumulative persisting annual savings 
20    for the year ending December 31, 2027;
21        (11) 1.8% deemed cumulative persisting annual savings 
22    for the year ending December 31, 2028;
23        (12) 1.7% deemed cumulative persisting annual savings 
24    for the year ending December 31, 2029;
25        (13) 1.5% deemed cumulative persisting annual savings 
26    for the year ending December 31, 2030;
 
 
10400SB0025ham003- 508 -LRB104 07069 AAS 29208 a

1        (14) 1.3% deemed cumulative persisting annual savings 
2    for the year ending December 31, 2031;
3        (15) 1.1% deemed cumulative persisting annual savings 
4    for the year ending December 31, 2032;
5        (16) 0.9% deemed cumulative persisting annual savings 
6    for the year ending December 31, 2033;
7        (17) 0.7% deemed cumulative persisting annual savings 
8    for the year ending December 31, 2034;
9        (18) 0.5% deemed cumulative persisting annual savings 
10    for the year ending December 31, 2035;
11        (19) 0.4% deemed cumulative persisting annual savings 
12    for the year ending December 31, 2036;
13        (20) 0.3% deemed cumulative persisting annual savings 
14    for the year ending December 31, 2037;
15        (21) 0.2% deemed cumulative persisting annual savings 
16    for the year ending December 31, 2038;
17        (22) 0.1% deemed cumulative persisting annual savings 
18    for the year ending December 31, 2039; and
19        (23) 0.0% deemed cumulative persisting annual savings 
20    for the year ending December 31, 2040 and all subsequent 
21    years.    
22    (b-15) Beginning in 2018 and through calendar year 2026, 
23electric utilities subject to this Section that serve less 
24than 3,000,000 retail customers but more than 500,000 retail 
25customers in the State shall achieve the following cumulative 
26persisting annual savings goals, as modified by subsection 
 
 
10400SB0025ham003- 509 -LRB104 07069 AAS 29208 a

1(b-20) and subsection (f) of this Section and as compared to 
2the deemed baseline as reduced by the number of MWhs equal to 
3the sum of the annual consumption of customers that have opted 
4out of subsections (a) through (j) of this Section under 
5paragraph (1) of subsection (l) of this Section as averaged 
6across the calendar years 2014, 2015, and 2016, through the 
7implementation of energy efficiency measures during the 
8applicable year and in prior years, but no earlier than 
9January 1, 2012:
10        (1) 7.4% cumulative persisting annual savings for the 
11    year ending December 31, 2018;
12        (2) 8.2% cumulative persisting annual savings for the 
13    year ending December 31, 2019;
14        (3) 9.0% cumulative persisting annual savings for the 
15    year ending December 31, 2020;
16        (4) 9.8% cumulative persisting annual savings for the 
17    year ending December 31, 2021;
18        (5) 10.6% cumulative persisting annual savings for the 
19    year ending December 31, 2022;
20        (6) 11.4% cumulative persisting annual savings for the 
21    year ending December 31, 2023;
22        (7) 12.2% cumulative persisting annual savings for the 
23    year ending December 31, 2024;
24        (8) 13% cumulative persisting annual savings for the 
25    year ending December 31, 2025; and    
26        (9) 13.6% cumulative persisting annual savings for the 
 
 
10400SB0025ham003- 510 -LRB104 07069 AAS 29208 a

1    year ending December 31, 2026. ;
2        (10) 14.2% cumulative persisting annual savings for 
3    the year ending December 31, 2027;
4        (11) 14.8% cumulative persisting annual savings for 
5    the year ending December 31, 2028;
6        (12) 15.4% cumulative persisting annual savings for 
7    the year ending December 31, 2029; and
8        (13) 16% cumulative persisting annual savings for the 
9    year ending December 31, 2030.    
10    No later than December 31, 2021, the Illinois Commerce 
11Commission shall establish additional cumulative persisting 
12annual savings goals for the years 2031 through 2035. No later 
13than December 31, 2024, the Illinois Commerce Commission shall 
14establish additional cumulative persisting annual savings 
15goals for the years 2036 through 2040. The Commission shall 
16also establish additional cumulative persisting annual savings 
17goals every 5 years thereafter to ensure that utilities always 
18have goals that extend at least 11 years into the future. The 
19cumulative persisting annual savings goals beyond the year 
202030 shall increase by 0.6 percentage points per year, absent 
21a Commission decision to initiate a proceeding to consider 
22establishing goals that increase by more or less than that 
23amount. Such a proceeding must be conducted in accordance with 
24the procedures described in subsection (f) of this Section. If 
25such a proceeding is initiated, the cumulative persisting 
26annual savings goals established by the Commission through 
 
 
10400SB0025ham003- 511 -LRB104 07069 AAS 29208 a

1that proceeding shall reflect the Commission's best estimate 
2of the maximum amount of additional savings that are forecast 
3to be cost-effectively achievable unless such best estimates 
4would result in goals that represent less than 0.4 percentage 
5point annual increases in total cumulative persisting annual 
6savings. The Commission may only establish goals that 
7represent less than 0.4 percentage point annual increases in 
8cumulative persisting annual savings if it can demonstrate, 
9based on clear and convincing evidence and through independent 
10analysis, that 0.4 percentage point increases are not 
11cost-effectively achievable. The Commission shall inform its 
12decision based on an energy efficiency potential study that 
13conforms to the requirements of this Section.    
14    (b-16) In 2027 and each year thereafter, each electric 
15utility subject to this Section shall achieve the following 
16savings goals:
17        (1) A utility that serves more than 3,000,000 retail 
18    customers in the State must achieve incremental annual 
19    energy savings for customers in an amount that is equal to 
20    2% of the utility's average annual electricity sales from 
21    2021 through 2023 to customers. A utility that serves less 
22    than 3,000,000 retail customers but more than 500,000 
23    retail customers in the State must achieve incremental 
24    annual energy savings for customers in an amount that is 
25    equal to 1.4% in 2027, 1.7% in 2028, and 2% in 2029 and 
26    every year thereafter of the utility's average annual 
 
 
10400SB0025ham003- 512 -LRB104 07069 AAS 29208 a

1    electricity sales from 2021 through 2023 to customers. The 
2    incremental annual energy savings requirements set forth 
3    in this paragraph (1) may be reduced by 0.025 percentage 
4    points for every percentage point increase, above the 25% 
5    minimum to be targeted at low-income households as 
6    specified in paragraph (c) of this Section, in the portion 
7    of total efficiency program spending that is on low-income 
8    or moderate-income efficiency programs. The incremental 
9    annual savings requirement shall not be reduced to a level 
10    less than 25% less than the energy savings requirement 
11    applicable to the calendar year, even if the sum of 
12    low-income spending and moderate-income spending is 
13    greater than 35% of total spending.
14        (2) A utility that serves less than 3,000,000 retail 
15    customers but more than 500,000 retail customers in the 
16    State must achieve an incremental annual coincident peak 
17    demand savings goal from energy efficiency measures 
18    installed as a result of the utility's programs by 
19    customers in an amount that is equal to the energy savings 
20    goal from paragraph (1) of this Section divided by the 
21    actual average ratio of kilowatt-hour savings to 
22    coincident peak demand reduction achieved by the utility 
23    through its energy efficiency programs in 2023. If the 
24    season in which coincident peak demands are experienced, 
25    the hours of the day that peak demands are experienced, 
26    and the methods by which peak demand impacts from 
 
 
10400SB0025ham003- 513 -LRB104 07069 AAS 29208 a

1    efficiency measures are estimated are different in the 
2    future than when 2023 peak demand impacts were originally 
3    estimated, the 2023 peak demand impacts shall be 
4    recomputed using such updated peak definitions and 
5    estimation methods for the purpose of establishing future 
6    coincident peak demand savings goals. To the extent that a 
7    utility counts either improvements to the efficiency of 
8    the use of gas and other fuels or the electrification of 
9    gas and other fuels toward its energy savings goal, as 
10    permitted under paragraphs (b-25) and (b-27) of this 
11    Section, it must estimate the actual impacts on coincident 
12    peak demand from such measures and count them, whether 
13    positive or negative, toward its coincident peak demand 
14    savings goal. Only coincident peak demand savings from 
15    efficiency measures shall count toward this goal. To the 
16    extent that some efficiency measures enable demand 
17    response, only the peak demand savings from the energy 
18    efficiency upgrade shall count toward the goal. Nothing in 
19    this Section shall limit the ability of peak demand 
20    savings from such enabled demand-response initiatives to 
21    count for other, non-energy efficiency performance 
22    standard performance metrics established for the utility.
23        (3) Each utility's incremental annual energy savings, 
24    and coincident peak demand savings if a utility serves 
25    less than 3,000,000 retail customers but more than 500,000 
26    retail customers in the State, must be achieved with an 
 
 
10400SB0025ham003- 514 -LRB104 07069 AAS 29208 a

1    average savings life of at least 12 years. In no event can 
2    more than one-fifth of the incremental annual savings or 
3    the coincident peak demand savings counted toward a 
4    utility's annual savings goal in any given year be derived 
5    from efficiency measures with average savings lives of 
6    less than 5 years. Average savings lives may be shorter 
7    than the average operational lives of measures installed 
8    if the measures do not produce savings in every year in 
9    which the measures operate or if the savings that measures 
10    produce decline during the measures' operational lives.
11            For the purposes of this Section, "incremental annual 
12    energy savings" means the total electric energy savings 
13    from all measures installed in a calendar year that will 
14    be realized within 12 months of each measure's 
15    installation; "moderate-income" means income between 80% 
16    of area median income and 300% of the federal poverty 
17    limit; "incremental annual coincident peak demand savings" 
18    means the total coincident peak reduction from all energy 
19    efficiency measures installed in a calendar year that will 
20    be realized within 12 months of each measure's 
21    installation; "average savings life" means the lifetime 
22    savings that would be realized as a result of a utility's 
23    efficiency programs divided by the incremental annual 
24    savings such programs produce.    
25    (b-20) Each electric utility subject to this Section may 
26include cost-effective voltage optimization measures in its 
 
 
10400SB0025ham003- 515 -LRB104 07069 AAS 29208 a

1plans submitted under subsections (f) and (g) of this Section, 
2and the costs incurred by a utility to implement the measures 
3under a Commission-approved plan shall be recovered under the 
4provisions of Article IX or Section 16-108.5 of this Act. For 
5purposes of this Section, the measure life of voltage 
6optimization measures shall be 15 years. The measure life 
7period is independent of the depreciation rate of the voltage 
8optimization assets deployed. Utilities may claim savings from 
9voltage optimization on circuits for more than 15 years if 
10they can demonstrate that they have made additional 
11investments necessary to enable voltage optimization savings 
12to continue beyond 15 years. Such demonstrations must be 
13subject to the review of independent evaluation. 
14    Within 270 days after June 1, 2017 (the effective date of 
15Public Act 99-906), an electric utility that serves less than 
163,000,000 retail customers but more than 500,000 retail 
17customers in the State shall file a plan with the Commission 
18that identifies the cost-effective voltage optimization 
19investment the electric utility plans to undertake through 
20December 31, 2024. The Commission, after notice and hearing, 
21shall approve or approve with modification the plan within 120 
22days after the plan's filing and, in the order approving or 
23approving with modification the plan, the Commission shall 
24adjust the applicable cumulative persisting annual savings 
25goals set forth in subsection (b-15) to reflect any amount of 
26cost-effective energy savings approved by the Commission that 
 
 
10400SB0025ham003- 516 -LRB104 07069 AAS 29208 a

1is greater than or less than the following cumulative 
2persisting annual savings values attributable to voltage 
3optimization for the applicable year:
4        (1) 0.0% of cumulative persisting annual savings for 
5    the year ending December 31, 2018;
6        (2) 0.17% of cumulative persisting annual savings for 
7    the year ending December 31, 2019;
8        (3) 0.17% of cumulative persisting annual savings for 
9    the year ending December 31, 2020;
10        (4) 0.33% of cumulative persisting annual savings for 
11    the year ending December 31, 2021;
12        (5) 0.5% of cumulative persisting annual savings for 
13    the year ending December 31, 2022;
14        (6) 0.67% of cumulative persisting annual savings for 
15    the year ending December 31, 2023;
16        (7) 0.83% of cumulative persisting annual savings for 
17    the year ending December 31, 2024; and
18        (8) 1.0% of cumulative persisting annual savings for 
19    the year ending December 31, 2025 and all subsequent 
20    years. 
21    (b-25) In the event an electric utility jointly offers an 
22energy efficiency measure or program with a gas utility under 
23plans approved under this Section and Section 8-104 of this 
24Act, the electric utility may continue offering the program, 
25including the gas energy efficiency measures, in the event the 
26gas utility discontinues funding the program. In that event, 
 
 
10400SB0025ham003- 517 -LRB104 07069 AAS 29208 a

1the energy savings value associated with such other fuels 
2shall be converted to electric energy savings on an equivalent 
3Btu basis for the premises. However, the electric utility 
4shall prioritize programs for low-income residential customers 
5to the extent practicable. An electric utility may recover the 
6costs of offering the gas energy efficiency measures under 
7this subsection (b-25).
8    For those energy efficiency measures or programs that save 
9both electricity and other fuels but are not jointly offered 
10with a gas utility under plans approved under this Section and 
11Section 8-104 or not offered with an affiliated gas utility 
12under paragraph (6) of subsection (f) of Section 8-104 of this 
13Act, the electric utility may count savings of fuels other 
14than electricity toward the achievement of its annual savings 
15goal, and the energy savings value associated with such other 
16fuels shall be converted to electric energy savings on an 
17equivalent Btu basis at the premises. 
18    For an electric utility that serves more than 3,000,000 
19retail customers in the State, on and after January 1, 2027, 
20the electric utility may only count savings of other fuels 
21under this subsection (b-25) toward the achievement of its 
22annual electric energy savings goal when such other fuel 
23savings are from weatherization measures that reduce heat loss 
24through the building envelope, insulating mechanical systems, 
25or the heating distribution system, including, but not limited 
26to, air sealing and building shell measures. This limitation 
 
 
10400SB0025ham003- 518 -LRB104 07069 AAS 29208 a

1on counting other fuel savings from efficiency measures toward 
2a utility's energy savings goal shall not affect the utility's 
3ability to claim savings from electrification measures 
4installed pursuant to the requirements in subsection (b-27).    
5    In no event shall more than 10% of each year's applicable 
6annual total savings requirement, as defined in paragraph 
7(7.5) of subsection (g) of this Section be met through savings 
8of fuels other than electricity. For an electric utility that 
9serves more than 3,000,000 retail customers in the State, in 
10no event shall more than 30% of each year's incremental annual 
11energy savings requirement, as defined in subsection (b-16) of 
12this Section, be met through savings of fuels other than 
13electricity. For an electric utility that serves less than 
143,000,000 retail customers but more than 500,000 retail 
15customers in the State, in no event shall more than 20% of each 
16year's incremental annual energy savings requirement, as 
17defined in subsection (b-16) of this Section, be met through 
18savings of fuels other than electricity.    
19    (b-27) Beginning in 2022, an electric utility may offer 
20and promote measures that electrify space heating, water 
21heating, cooling, drying, cooking, industrial processes, and 
22other building and industrial end uses that would otherwise be 
23served by combustion of fossil fuel at the premises, provided 
24that the electrification measures reduce total energy 
25consumption at the premises. The electric utility may count 
26the reduction in energy consumption at the premises toward 
 
 
10400SB0025ham003- 519 -LRB104 07069 AAS 29208 a

1achievement of its annual savings goals. The reduction in 
2energy consumption at the premises shall be calculated as the 
3difference between: (A) the reduction in Btu consumption of 
4fossil fuels as a result of electrification, converted to 
5kilowatt-hour equivalents by dividing by 3,412 Btus per 
6kilowatt hour; and (B) the increase in kilowatt hours of 
7electricity consumption resulting from the displacement of 
8fossil fuel consumption as a result of electrification. An 
9electric utility may recover the costs of offering and 
10promoting electrification measures under this subsection 
11(b-27).
12    At least 33% of all costs of offering and promoting 
13electrification measures under this subsection (b-27) must be 
14for supporting installation of electrification measures 
15through programs exclusively targeted to low-income 
16households. The percentage requirement may be reduced if the 
17utility can demonstrate that it is not possible to achieve the 
18level of low-income electrification spending, while supporting 
19programs for non-low-income residential and business 
20electrification, because of limitations regarding the number 
21of low-income households in its service territory that would 
22be able to meet program eligibility requirements set forth in 
23the multi-year energy efficiency plan. If the 33% low-income 
24electrification spending requirement is reduced, the utility 
25must prioritize support of low-income electrification in 
26housing that meets program eligibility requirements over 
 
 
10400SB0025ham003- 520 -LRB104 07069 AAS 29208 a

1electrification spending on non-low-income residential or 
2business customers.
3    The ratio of spending on electrification measures targeted 
4to low-income, multifamily buildings to spending on 
5electrification measures targeted to low-income, single-family 
6buildings shall be designed to achieve levels of 
7electrification savings from each building type that are 
8approximately proportional to the magnitude of cost-effective 
9electrification savings potential in each building type.    
10    In no event shall electrification savings counted toward 
11each year's applicable annual total savings requirement, as 
12defined in paragraph (7.5) of subsection (g) of this Section, 
13or counted toward each year's incremental annual savings, as 
14defined in paragraph (b-16) of this Section, be greater than:
15        (1) 5% per year for each year from 2022 through 2025;
16        (2) 20% 10% per year for each year from 2026 and all 
17    subsequent years through 2029; and
18        (3) (blank). 15% per year for 2030 and all subsequent 
19    years.
20In addition, a minimum of 25% of all electrification savings 
21counted toward a utility's applicable annual total savings 
22requirement must be from electrification of end uses in 
23low-income housing. The limitations on electrification savings 
24that may be counted toward a utility's annual savings goals 
25are separate from and in addition to the subsection (b-25) 
26limitations governing the counting of the other fuel savings 
 
 
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1resulting from efficiency measures and programs.
2    As part of the annual informational filing to the 
3Commission that is required under paragraph (9) of subsection 
4(g) of this Section, each utility shall identify the specific 
5electrification measures offered under this subsection (b-27); 
6the quantity of each electrification measure that was 
7installed by its customers; the average total cost, average 
8utility cost, average reduction in fossil fuel consumption, 
9and average increase in electricity consumption associated 
10with each electrification measure; the portion of 
11installations of each electrification measure that were in 
12low-income single-family housing, low-income multifamily 
13housing, non-low-income single-family housing, non-low-income 
14multifamily housing, commercial buildings, and industrial 
15facilities; and the quantity of savings associated with each 
16measure category in each customer category that are being 
17counted toward the utility's applicable annual total savings 
18requirement or counted toward each year's incremental annual 
19savings, as defined in paragraph (b-16) of this Section. Prior 
20to installing or promoting an electrification measures    
21measure, the utility shall provide customers a customer with 
22estimates an estimate of the impact of the new measures    
23measure on the customer's average monthly electric bill and 
24total annual energy expenses. 
25    (c) Electric utilities shall be responsible for overseeing 
26the design, development, and filing of energy efficiency plans 
 
 
10400SB0025ham003- 522 -LRB104 07069 AAS 29208 a

1with the Commission and may, as part of that implementation, 
2outsource various aspects of program development and 
3implementation. A minimum of 10%, for electric utilities that 
4serve more than 3,000,000 retail customers in the State, and a 
5minimum of 7%, for electric utilities that serve less than 
63,000,000 retail customers but more than 500,000 retail 
7customers in the State, of the utility's entire portfolio 
8funding level for a given year shall be used to procure 
9cost-effective energy efficiency measures from units of local 
10government, municipal corporations, school districts, public 
11housing, public institutions of higher education, and 
12community college districts, provided that a minimum 
13percentage of available funds shall be used to procure energy 
14efficiency from public housing, which percentage shall be 
15equal to public housing's share of public building energy 
16consumption.
17    The utilities shall also implement energy efficiency 
18measures targeted at low-income households, which, for 
19purposes of this Section, shall be defined as households at or 
20below 80% of area median income, and expenditures to implement 
21the measures shall be no less than 25% of total energy 
22efficiency program spending approved by the Commission 
23pursuant to review of plans filed under subsection (f) of this 
24Section $40,000,000 per year for electric utilities that serve 
25more than 3,000,000 retail customers in the State and no less 
26than $13,000,000 per year for electric utilities that serve 
 
 
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1less than 3,000,000 retail customers but more than 500,000 
2retail customers in the State. The ratio of spending on 
3efficiency programs targeted at low-income multifamily 
4buildings to spending on efficiency programs targeted at 
5low-income single-family buildings shall be designed to 
6achieve levels of savings from each building type that are 
7approximately proportional to the magnitude of cost-effective 
8lifetime savings potential in each building type. Investment 
9in low-income whole-building weatherization programs shall 
10constitute a minimum of 80% of a utility's total budget 
11specifically dedicated to serving low-income customers.
12    The utilities shall work to bundle low-income energy 
13efficiency offerings with other programs that serve low-income 
14households to maximize the benefits going to these households. 
15The utilities shall market and implement low-income energy 
16efficiency programs in coordination with low-income assistance 
17programs, the Illinois Solar for All Program, and 
18weatherization whenever practicable. The program implementer 
19shall walk the customer through the enrollment process for any 
20programs for which the customer is eligible. The utilities 
21shall also pilot targeting customers with high arrearages, 
22high energy intensity (ratio of energy usage divided by home 
23or unit square footage), or energy assistance programs with 
24energy efficiency offerings, and then track reduction in 
25arrearages as a result of the targeting. This targeting and 
26bundling of low-income energy programs shall be offered to 
 
 
10400SB0025ham003- 524 -LRB104 07069 AAS 29208 a

1both low-income single-family and multifamily customers 
2(owners and residents). 
3    The utilities shall invest in health and safety measures 
4appropriate and necessary for comprehensively weatherizing a 
5home or multifamily building, and shall implement a health and 
6safety fund of at least 15% of the total income-qualified 
7weatherization budget that shall be used for the purpose of 
8making grants for technical assistance, construction, 
9reconstruction, improvement, or repair of buildings to 
10facilitate their participation in the energy efficiency 
11programs targeted at low-income single-family and multifamily 
12households. These funds may also be used for the purpose of 
13making grants for technical assistance, construction, 
14reconstruction, improvement, or repair of the following 
15buildings to facilitate their participation in the energy 
16efficiency programs created by this Section: (1) buildings 
17that are owned or operated by registered 501(c)(3) public 
18charities; and (2) day care centers, day care homes, or group 
19day care homes, as defined under 89 Ill. Adm. Code Part 406, 
20407, or 408, respectively. 
21    Each electric utility shall assess opportunities to 
22implement cost-effective energy efficiency measures and 
23programs through a public housing authority or authorities 
24located in its service territory. If such opportunities are 
25identified, the utility shall propose such measures and 
26programs to address the opportunities. Expenditures to address 
 
 
10400SB0025ham003- 525 -LRB104 07069 AAS 29208 a

1such opportunities shall be credited toward the minimum 
2procurement and expenditure requirements set forth in this 
3subsection (c).
4    Implementation of energy efficiency measures and programs 
5targeted at low-income households should be contracted, when 
6it is practicable, to independent third parties that have 
7demonstrated capabilities to serve such households, with a 
8preference for not-for-profit entities and government agencies 
9that have existing relationships with or experience serving 
10low-income communities in the State.
11    Each electric utility shall develop and implement 
12reporting procedures that address and assist in determining 
13the amount of energy savings that can be applied to the 
14low-income procurement and expenditure requirements set forth 
15in this subsection (c). Each electric utility shall also track 
16the types and quantities or volumes of insulation and air 
17sealing materials, and their associated energy saving 
18benefits, installed in energy efficiency programs targeted at 
19low-income single-family and multifamily households. 
20    The electric utilities shall participate in a low-income 
21energy efficiency accountability committee ("the committee"), 
22which will directly inform the design, implementation, and 
23evaluation of the low-income and public-housing energy 
24efficiency programs. The committee shall be comprised of the 
25electric utilities subject to the requirements of this 
26Section, the gas utilities subject to the requirements of 
 
 
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1Section 8-104 of this Act, the utilities' low-income energy 
2efficiency implementation contractors, nonprofit 
3organizations, community action agencies, advocacy groups, 
4State and local governmental agencies, public-housing 
5organizations, and representatives of community-based 
6organizations, especially those living in or working with 
7environmental justice communities and BIPOC communities. The 
8committee shall be composed of 2 geographically differentiated 
9subcommittees: one for stakeholders in northern Illinois and 
10one for stakeholders in central and southern Illinois. The 
11subcommittees shall meet together at least twice per year.
12    There shall be one statewide leadership committee led by 
13and composed of community-based organizations that are 
14representative of BIPOC and environmental justice communities 
15and that includes equitable representation from BIPOC 
16communities. The leadership committee shall be composed of an 
17equal number of representatives from the 2 subcommittees. The 
18subcommittees shall address specific programs and issues, with 
19the leadership committee convening targeted workgroups as 
20needed. The leadership committee may elect to work with an 
21independent facilitator to solicit and organize feedback, 
22recommendations and meeting participation from a wide variety 
23of community-based stakeholders. If a facilitator is used, 
24they shall be fair and responsive to the needs of all 
25stakeholders involved in the committee. For a utility that 
26serves more than 3,000,000 retail customers in the State, if a 
 
 
10400SB0025ham003- 527 -LRB104 07069 AAS 29208 a

1facilitator is used, they shall be retained by Commission 
2staff.    
3     All committee meetings must be accessible, with rotating 
4locations if meetings are held in-person, virtual 
5participation options, and materials and agendas circulated in 
6advance.
7    There shall also be opportunities for direct input by 
8committee members outside of committee meetings, such as via 
9individual meetings, surveys, emails and calls, to ensure 
10robust participation by stakeholders with limited capacity and 
11ability to attend committee meetings. Committee meetings shall 
12emphasize opportunities to bundle and coordinate delivery of 
13low-income energy efficiency with other programs that serve 
14low-income communities, such as the Illinois Solar for All 
15Program and bill payment assistance programs. Meetings shall 
16include educational opportunities for stakeholders to learn 
17more about these additional offerings, and the committee shall 
18assist in figuring out the best methods for coordinated 
19delivery and implementation of offerings when serving 
20low-income communities. The committee shall directly and 
21equitably influence and inform utility low-income and 
22public-housing energy efficiency programs and priorities. 
23Participating utilities shall implement recommendations from 
24the committee whenever possible.
25    Participating utilities shall track and report how input 
26from the committee has led to new approaches and changes in 
 
 
10400SB0025ham003- 528 -LRB104 07069 AAS 29208 a

1their energy efficiency portfolios. This reporting shall occur 
2at committee meetings and in quarterly energy efficiency 
3reports to the Stakeholder Advisory Group and Illinois 
4Commerce Commission, and other relevant reporting mechanisms. 
5Participating utilities shall also report on relevant equity 
6data and metrics requested by the committee, such as energy 
7burden data, geographic, racial, and other relevant 
8demographic data on where programs are being delivered and 
9what populations programs are serving.
10    The Illinois Commerce Commission shall oversee and have 
11relevant staff participate in the committee. The committee 
12shall have a budget of 0.25% of each utility's entire 
13efficiency portfolio funding for a given year. The budget 
14shall be overseen by the Commission. The budget shall be used 
15to provide grants for community-based organizations serving on 
16the leadership committee, stipends for community-based 
17organizations participating in the committee, grants for 
18community-based organizations to do energy efficiency outreach 
19and education, and relevant meeting needs as determined by the 
20leadership committee. The education and outreach shall 
21include, but is not limited to, basic energy efficiency 
22education, information about low-income energy efficiency 
23programs, and information on the committee's purpose, 
24structure, and activities.
25    (d) Notwithstanding any other provision of law to the 
26contrary, a utility providing approved energy efficiency 
 
 
10400SB0025ham003- 529 -LRB104 07069 AAS 29208 a

1measures and, if applicable, demand-response measures in the 
2State shall be permitted to recover all reasonable and 
3prudently incurred costs of those measures from all retail 
4customers, except as provided in subsection (l) of this 
5Section, as follows, provided that nothing in this subsection 
6(d) permits the double recovery of such costs from customers: 
7        (1) The utility may recover its costs through an 
8    automatic adjustment clause tariff filed with and approved 
9    by the Commission. The tariff shall be established outside 
10    the context of a general rate case. Each year the 
11    Commission shall initiate a review to reconcile any 
12    amounts collected with the actual costs and to determine 
13    the required adjustment to the annual tariff factor to 
14    match annual expenditures. To enable the financing of the 
15    incremental capital expenditures, including regulatory 
16    assets, for electric utilities that serve less than 
17    3,000,000 retail customers but more than 500,000 retail 
18    customers in the State, the utility's actual year-end 
19    capital structure that includes a common equity ratio, 
20    excluding goodwill, of up to and including 50% of the 
21    total capital structure shall be deemed reasonable and 
22    used to set rates.
23        (2) A utility may recover its costs through an energy 
24    efficiency formula rate approved by the Commission under a 
25    filing under subsections (f) and (g) of this Section, 
26    which shall specify the cost components that form the 
 
 
10400SB0025ham003- 530 -LRB104 07069 AAS 29208 a

1    basis of the rate charged to customers with sufficient 
2    specificity to operate in a standardized manner and be 
3    updated annually with transparent information that 
4    reflects the utility's actual costs to be recovered during 
5    the applicable rate year, which is the period beginning 
6    with the first billing day of January and extending 
7    through the last billing day of the following December. 
8    The energy efficiency formula rate shall be implemented 
9    through a tariff filed with the Commission under 
10    subsections (f) and (g) of this Section that is consistent 
11    with the provisions of this paragraph (2) and that shall 
12    be applicable to all delivery services customers. The 
13    Commission shall conduct an investigation of the tariff in 
14    a manner consistent with the provisions of this paragraph 
15    (2), subsections (f) and (g) of this Section, and the 
16    provisions of Article IX of this Act to the extent they do 
17    not conflict with this paragraph (2). The energy 
18    efficiency formula rate approved by the Commission shall 
19    remain in effect at the discretion of the utility and 
20    shall do the following:
21            (A) Provide for the recovery of the utility's 
22        actual costs incurred under this Section that are 
23        prudently incurred and reasonable in amount consistent 
24        with Commission practice and law. The sole fact that a 
25        cost differs from that incurred in a prior calendar 
26        year or that an investment is different from that made 
 
 
10400SB0025ham003- 531 -LRB104 07069 AAS 29208 a

1        in a prior calendar year shall not imply the 
2        imprudence or unreasonableness of that cost or 
3        investment.
4            (B) Reflect the utility's actual year-end capital 
5        structure for the applicable calendar year, excluding 
6        goodwill, subject to a determination of prudence and 
7        reasonableness consistent with Commission practice and 
8        law. To enable the financing of the incremental 
9        capital expenditures, including regulatory assets, for 
10        electric utilities that serve less than 3,000,000 
11        retail customers but more than 500,000 retail 
12        customers in the State, a participating electric 
13        utility's actual year-end capital structure that 
14        includes a common equity ratio, excluding goodwill, of 
15        up to and including 50% of the total capital structure 
16        shall be deemed reasonable and used to set rates.
17            (C) Include a cost of equity that shall be equal to 
18        the baseline cost of equity approved by the Commission 
19        for the utility's electric distribution rates 
20        effective during the applicable year, whether those 
21        rates are set pursuant to Section 9-201, subparagraph 
22        (B) of paragraph (3) of subsection (d) of Section 
23        16-108.18, or any successor electric distribution 
24        ratemaking paradigm. , which shall be calculated as the 
25        sum of the following:
26                (i) the average for the applicable calendar 
 
 
10400SB0025ham003- 532 -LRB104 07069 AAS 29208 a

1            year of the monthly average yields of 30-year U.S. 
2            Treasury bonds published by the Board of Governors 
3            of the Federal Reserve System in its weekly H.15 
4            Statistical Release or successor publication; and
5                (ii) 580 basis points.
6            At such time as the Board of Governors of the 
7        Federal Reserve System ceases to include the monthly 
8        average yields of 30-year U.S. Treasury bonds in its 
9        weekly H.15 Statistical Release or successor 
10        publication, the monthly average yields of the U.S. 
11        Treasury bonds then having the longest duration 
12        published by the Board of Governors in its weekly H.15 
13        Statistical Release or successor publication shall 
14        instead be used for purposes of this paragraph (2).
15            (D) Permit and set forth protocols, subject to a 
16        determination of prudence and reasonableness 
17        consistent with Commission practice and law, for the 
18        following:
19                (i) recovery of incentive compensation expense 
20            that is based on the achievement of operational 
21            metrics, including metrics related to budget 
22            controls, outage duration and frequency, safety, 
23            customer service, efficiency and productivity, and 
24            environmental compliance; however, this protocol 
25            shall not apply if such expense related to costs 
26            incurred under this Section is recovered under 
 
 
10400SB0025ham003- 533 -LRB104 07069 AAS 29208 a

1            Article IX or Section 16-108.5 of this Act; 
2            incentive compensation expense that is based on 
3            net income or an affiliate's earnings per share 
4            shall not be recoverable under the energy 
5            efficiency formula rate;
6                (ii) recovery of pension and other 
7            post-employment benefits expense, provided that 
8            such costs are supported by an actuarial study; 
9            however, this protocol shall not apply if such 
10            expense related to costs incurred under this 
11            Section is recovered under Article IX or Section 
12            16-108.5 of this Act;
13                (iii) recovery of existing regulatory assets 
14            over the periods previously authorized by the 
15            Commission;
16                (iv) as described in subsection (e), 
17            amortization of costs incurred under this Section; 
18            and
19                (v) projected, weather normalized billing 
20            determinants for the applicable rate year.
21            (E) Provide for an annual reconciliation, as 
22        described in paragraph (3) of this subsection (d), 
23        less any deferred taxes related to the reconciliation, 
24        with interest at an annual rate of return equal to the 
25        utility's weighted average cost of capital, including 
26        a revenue conversion factor calculated to recover or 
 
 
10400SB0025ham003- 534 -LRB104 07069 AAS 29208 a

1        refund all additional income taxes that may be payable 
2        or receivable as a result of that return, of the energy 
3        efficiency revenue requirement reflected in rates for 
4        each calendar year, beginning with the calendar year 
5        in which the utility files its energy efficiency 
6        formula rate tariff under this paragraph (2), with 
7        what the revenue requirement would have been had the 
8        actual cost information for the applicable calendar 
9        year been available at the filing date.
10        The utility shall file, together with its tariff, the 
11    projected costs to be incurred by the utility during the 
12    rate year under the utility's multi-year plan approved 
13    under subsections (f) and (g) of this Section, including, 
14    but not limited to, the projected capital investment costs 
15    and projected regulatory asset balances with 
16    correspondingly updated depreciation and amortization 
17    reserves and expense, that shall populate the energy 
18    efficiency formula rate and set the initial rates under 
19    the formula.
20        The Commission shall review the proposed tariff in 
21    conjunction with its review of a proposed multi-year plan, 
22    as specified in paragraph (5) of subsection (g) of this 
23    Section. The review shall be based on the same evidentiary 
24    standards, including, but not limited to, those concerning 
25    the prudence and reasonableness of the costs incurred by 
26    the utility, the Commission applies in a hearing to review 
 
 
10400SB0025ham003- 535 -LRB104 07069 AAS 29208 a

1    a filing for a general increase in rates under Article IX 
2    of this Act. The initial rates shall take effect beginning 
3    with the January monthly billing period following the 
4    Commission's approval.
5        The tariff's rate design and cost allocation across 
6    customer classes shall be consistent with the utility's 
7    automatic adjustment clause tariff in effect on June 1, 
8    2017 (the effective date of Public Act 99-906); however, 
9    the Commission may revise the tariff's rate design and 
10    cost allocation in subsequent proceedings under paragraph 
11    (3) of this subsection (d).
12        If the energy efficiency formula rate is terminated, 
13    the then current rates shall remain in effect until such 
14    time as the energy efficiency costs are incorporated into 
15    new rates that are set under this subsection (d) or 
16    Article IX of this Act, subject to retroactive rate 
17    adjustment, with interest, to reconcile rates charged with 
18    actual costs.
19        (3) The provisions of this paragraph (3) shall only 
20    apply to an electric utility that has elected to file an 
21    energy efficiency formula rate under paragraph (2) of this 
22    subsection (d). Subsequent to the Commission's issuance of 
23    an order approving the utility's energy efficiency formula 
24    rate structure and protocols, and initial rates under 
25    paragraph (2) of this subsection (d), the utility shall 
26    file, on or before June 1 of each year, with the Chief 
 
 
10400SB0025ham003- 536 -LRB104 07069 AAS 29208 a

1    Clerk of the Commission its updated cost inputs to the 
2    energy efficiency formula rate for the applicable rate 
3    year and the corresponding new charges, as well as the 
4    information described in paragraph (9) of subsection (g) 
5    of this Section. Each such filing shall conform to the 
6    following requirements and include the following 
7    information:
8            (A) The inputs to the energy efficiency formula 
9        rate for the applicable rate year shall be based on the 
10        projected costs to be incurred by the utility during 
11        the rate year under the utility's multi-year plan 
12        approved under subsections (f) and (g) of this 
13        Section, including, but not limited to, projected 
14        capital investment costs and projected regulatory 
15        asset balances with correspondingly updated 
16        depreciation and amortization reserves and expense. 
17        The filing shall also include a reconciliation of the 
18        energy efficiency revenue requirement that was in 
19        effect for the prior rate year (as set by the cost 
20        inputs for the prior rate year) with the actual 
21        revenue requirement for the prior rate year 
22        (determined using a year-end rate base) that uses 
23        amounts reflected in the applicable FERC Form 1 that 
24        reports the actual costs for the prior rate year. Any 
25        over-collection or under-collection indicated by such 
26        reconciliation shall be reflected as a credit against, 
 
 
10400SB0025ham003- 537 -LRB104 07069 AAS 29208 a

1        or recovered as an additional charge to, respectively, 
2        with interest calculated at a rate equal to the 
3        utility's weighted average cost of capital approved by 
4        the Commission for the prior rate year, the charges 
5        for the applicable rate year. Such over-collection or 
6        under-collection shall be adjusted to remove any 
7        deferred taxes related to the reconciliation, for 
8        purposes of calculating interest at an annual rate of 
9        return equal to the utility's weighted average cost of 
10        capital approved by the Commission for the prior rate 
11        year, including a revenue conversion factor calculated 
12        to recover or refund all additional income taxes that 
13        may be payable or receivable as a result of that 
14        return. Each reconciliation shall be certified by the 
15        participating utility in the same manner that FERC 
16        Form 1 is certified. The filing shall also include the 
17        charge or credit, if any, resulting from the 
18        calculation required by subparagraph (E) of paragraph 
19        (2) of this subsection (d).
20            Notwithstanding any other provision of law to the 
21        contrary, the intent of the reconciliation is to 
22        ultimately reconcile both the revenue requirement 
23        reflected in rates for each calendar year, beginning 
24        with the calendar year in which the utility files its 
25        energy efficiency formula rate tariff under paragraph 
26        (2) of this subsection (d), with what the revenue 
 
 
10400SB0025ham003- 538 -LRB104 07069 AAS 29208 a

1        requirement determined using a year-end rate base for 
2        the applicable calendar year would have been had the 
3        actual cost information for the applicable calendar 
4        year been available at the filing date.
5            For purposes of this Section, "FERC Form 1" means 
6        the Annual Report of Major Electric Utilities, 
7        Licensees and Others that electric utilities are 
8        required to file with the Federal Energy Regulatory 
9        Commission under the Federal Power Act, Sections 3, 
10        4(a), 304 and 209, modified as necessary to be 
11        consistent with 83 Ill. Adm. Code Part 415 as of May 1, 
12        2011. Nothing in this Section is intended to allow 
13        costs that are not otherwise recoverable to be 
14        recoverable by virtue of inclusion in FERC Form 1.
15            (B) The new charges shall take effect beginning on 
16        the first billing day of the following January billing 
17        period and remain in effect through the last billing 
18        day of the next December billing period regardless of 
19        whether the Commission enters upon a hearing under 
20        this paragraph (3).
21            (C) The filing shall include relevant and 
22        necessary data and documentation for the applicable 
23        rate year. Normalization adjustments shall not be 
24        required.
25        Within 45 days after the utility files its annual 
26    update of cost inputs to the energy efficiency formula 
 
 
10400SB0025ham003- 539 -LRB104 07069 AAS 29208 a

1    rate, the Commission shall with reasonable notice, 
2    initiate a proceeding concerning whether the projected 
3    costs to be incurred by the utility and recovered during 
4    the applicable rate year, and that are reflected in the 
5    inputs to the energy efficiency formula rate, are 
6    consistent with the utility's approved multi-year plan 
7    under subsections (f) and (g) of this Section and whether 
8    the costs incurred by the utility during the prior rate 
9    year were prudent and reasonable. The Commission shall 
10    also have the authority to investigate the information and 
11    data described in paragraph (9) of subsection (g) of this 
12    Section, including the proposed adjustment to the 
13    utility's return on equity component of its weighted 
14    average cost of capital. During the course of the 
15    proceeding, each objection shall be stated with 
16    particularity and evidence provided in support thereof, 
17    after which the utility shall have the opportunity to 
18    rebut the evidence. Discovery shall be allowed consistent 
19    with the Commission's Rules of Practice, which Rules of 
20    Practice shall be enforced by the Commission or the 
21    assigned administrative law judge. The Commission shall 
22    apply the same evidentiary standards, including, but not 
23    limited to, those concerning the prudence and 
24    reasonableness of the costs incurred by the utility, 
25    during the proceeding as it would apply in a proceeding to 
26    review a filing for a general increase in rates under 
 
 
10400SB0025ham003- 540 -LRB104 07069 AAS 29208 a

1    Article IX of this Act. The Commission shall not, however, 
2    have the authority in a proceeding under this paragraph 
3    (3) to consider or order any changes to the structure or 
4    protocols of the energy efficiency formula rate approved 
5    under paragraph (2) of this subsection (d). In a 
6    proceeding under this paragraph (3), the Commission shall 
7    enter its order no later than the earlier of 195 days after 
8    the utility's filing of its annual update of cost inputs 
9    to the energy efficiency formula rate or December 15. The 
10    utility's proposed return on equity calculation, as 
11    described in paragraphs (7) through (9) of subsection (g) 
12    of this Section, shall be deemed the final, approved 
13    calculation on December 15 of the year in which it is filed 
14    unless the Commission enters an order on or before 
15    December 15, after notice and hearing, that modifies such 
16    calculation consistent with this Section. The Commission's 
17    determinations of the prudence and reasonableness of the 
18    costs incurred, and determination of such return on equity 
19    calculation, for the applicable calendar year shall be 
20    final upon entry of the Commission's order and shall not 
21    be subject to reopening, reexamination, or collateral 
22    attack in any other Commission proceeding, case, docket, 
23    order, rule, or regulation; however, nothing in this 
24    paragraph (3) shall prohibit a party from petitioning the 
25    Commission to rehear or appeal to the courts the order 
26    under the provisions of this Act.
 
 
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1    (e) Beginning on June 1, 2017 (the effective date of 
2Public Act 99-906), a utility subject to the requirements of 
3this Section may elect to defer, as a regulatory asset, up to 
4the full amount of its expenditures incurred under this 
5Section for each annual period, including, but not limited to, 
6any expenditures incurred above the funding level set by 
7subsection (f) of this Section for a given year. The total 
8expenditures deferred as a regulatory asset in a given year 
9shall be amortized and recovered over a period that is equal to 
10the weighted average of the energy efficiency measure lives 
11implemented for that year that are reflected in the regulatory 
12asset. The unamortized balance shall be recognized as of 
13December 31 for a given year. The utility shall also earn a 
14return on the total of the unamortized balances of all of the 
15energy efficiency regulatory assets, less any deferred taxes 
16related to those unamortized balances, at an annual rate equal 
17to the utility's weighted average cost of capital that 
18includes, based on a year-end capital structure, the utility's 
19actual cost of debt for the applicable calendar year and a cost 
20of equity, which shall be determined as set forth in 
21subparagraph (C) of paragraph (2) of subsection of this 
22Section calculated as the sum of the (i) the average for the 
23applicable calendar year of the monthly average yields of 
2430-year U.S. Treasury bonds published by the Board of 
25Governors of the Federal Reserve System in its weekly H.15 
26Statistical Release or successor publication; and (ii) 580 
 
 
10400SB0025ham003- 542 -LRB104 07069 AAS 29208 a

1basis points, including a revenue conversion factor calculated 
2to recover or refund all additional income taxes that may be 
3payable or receivable as a result of that return. Capital 
4investment costs shall be depreciated and recovered over their 
5useful lives consistent with generally accepted accounting 
6principles. The weighted average cost of capital shall be 
7applied to the capital investment cost balance, less any 
8accumulated depreciation and accumulated deferred income 
9taxes, as of December 31 for a given year.
10    When an electric utility creates a regulatory asset under 
11the provisions of this Section, the costs are recovered over a 
12period during which customers also receive a benefit which is 
13in the public interest. Accordingly, it is the intent of the 
14General Assembly that an electric utility that elects to 
15create a regulatory asset under the provisions of this Section 
16shall recover all of the associated costs as set forth in this 
17Section. After the Commission has approved the prudence and 
18reasonableness of the costs that comprise the regulatory 
19asset, the electric utility shall be permitted to recover all 
20such costs, and the value and recoverability through rates of 
21the associated regulatory asset shall not be limited, altered, 
22impaired, or reduced.
23    (f) Beginning in 2017, each electric utility shall file an 
24energy efficiency plan with the Commission to meet the energy 
25efficiency standards for the next applicable multi-year period 
26beginning January 1 of the year following the filing, 
 
 
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1according to the schedule set forth in paragraphs (1) through 
2(3) of this subsection (f). If a utility does not file such a 
3plan on or before the applicable filing deadline for the plan, 
4it shall face a penalty of $100,000 per day until the plan is 
5filed.
6        (1) No later than 30 days after June 1, 2017 (the 
7    effective date of Public Act 99-906), each electric 
8    utility shall file a 4-year energy efficiency plan 
9    commencing on January 1, 2018 that is designed to achieve 
10    the cumulative persisting annual savings goals specified 
11    in paragraphs (1) through (4) of subsection (b-5) of this 
12    Section or in paragraphs (1) through (4) of subsection 
13    (b-15) of this Section, as applicable, through 
14    implementation of energy efficiency measures; however, the 
15    goals may be reduced if the utility's expenditures are 
16    limited pursuant to subsection (m) of this Section or, for 
17    a utility that serves less than 3,000,000 retail 
18    customers, if each of the following conditions are met: 
19    (A) the plan's analysis and forecasts of the utility's 
20    ability to acquire energy savings demonstrate that 
21    achievement of such goals is not cost effective; and (B) 
22    the amount of energy savings achieved by the utility as 
23    determined by the independent evaluator for the most 
24    recent year for which savings have been evaluated 
25    preceding the plan filing was less than the average annual 
26    amount of savings required to achieve the goals for the 
 
 
10400SB0025ham003- 544 -LRB104 07069 AAS 29208 a

1    applicable 4-year plan period. Except as provided in 
2    subsection (m) of this Section, annual increases in 
3    cumulative persisting annual savings goals during the 
4    applicable 4-year plan period shall not be reduced to 
5    amounts that are less than the maximum amount of 
6    cumulative persisting annual savings that is forecast to 
7    be cost-effectively achievable during the 4-year plan 
8    period. The Commission shall review any proposed goal 
9    reduction as part of its review and approval of the 
10    utility's proposed plan.
11        (2) No later than March 1, 2021, each electric utility 
12    shall file a 4-year energy efficiency plan commencing on 
13    January 1, 2022 that is designed to achieve the cumulative 
14    persisting annual savings goals specified in paragraphs 
15    (5) through (8) of subsection (b-5) of this Section or in 
16    paragraphs (5) through (8) of subsection (b-15) of this 
17    Section, as applicable, through implementation of energy 
18    efficiency measures; however, the goals may be reduced if 
19    either (1) clear and convincing evidence demonstrates, 
20    through independent analysis, that the expenditure limits 
21    in subsection (m) of this Section preclude full 
22    achievement of the goals or (2) each of the following 
23    conditions are met: (A) the plan's analysis and forecasts 
24    of the utility's ability to acquire energy savings 
25    demonstrate by clear and convincing evidence and through 
26    independent analysis that achievement of such goals is not 
 
 
10400SB0025ham003- 545 -LRB104 07069 AAS 29208 a

1    cost effective; and (B) the amount of energy savings 
2    achieved by the utility as determined by the independent 
3    evaluator for the most recent year for which savings have 
4    been evaluated preceding the plan filing was less than the 
5    average annual amount of savings required to achieve the 
6    goals for the applicable 4-year plan period. If there is 
7    not clear and convincing evidence that achieving the 
8    savings goals specified in paragraph (b-5) or (b-15) of 
9    this Section is possible both cost-effectively and within 
10    the expenditure limits in subsection (m), such savings 
11    goals shall not be reduced. Except as provided in 
12    subsection (m) of this Section, annual increases in 
13    cumulative persisting annual savings goals during the 
14    applicable 4-year plan period shall not be reduced to 
15    amounts that are less than the maximum amount of 
16    cumulative persisting annual savings that is forecast to 
17    be cost-effectively achievable during the 4-year plan 
18    period. The Commission shall review any proposed goal 
19    reduction as part of its review and approval of the 
20    utility's proposed plan.
21        (2.5) Provisions of the multi-year plans for calendar 
22    years 2026 through 2029 that relate to calendar year 2026 
23    and that were filed by the electric utilities on February 
24    28, 2025 shall remain in effect through calendar year 
25    2026. Provisions of the plans for calendar years 2027 
26    through 2029 shall be modified and resubmitted to the 
 
 
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1    Commission by the electric utilities pursuant to paragraph 
2    (3) of this subsection (f).    
3        (3) No later than March 1, 2026 or the effective date 
4    of this amendatory Act of the 104th General Assembly, 
5    whichever is later 2025, each electric utility shall file 
6    a 3-year 4-year energy efficiency plan commencing on 
7    January 1, 2027 2026 that is designed to achieve, through 
8    implementation of energy efficiency measures, lifetime 
9    energy equal to the product of the incremental annual 
10    savings goals defined by paragraph (1) of subsection 
11    (b-16) and the minimum average savings life defined by 
12    paragraph (3) of subsection (b-16). The 3-year energy 
13    efficiency plan of a utility that serves less than 
14    3,000,000 retail customers but more than 500,000 retail 
15    customers in the State must also be designed to achieve 
16    lifetime peak demand savings equal to the product of the 
17    incremental annual savings goals defined by paragraph (2) 
18    of subsection (b-16) and the minimum average savings life 
19    defined by paragraph (3) of subsection (b-16) through 
20    implementation of energy efficiency measures. The savings 
21    goals may be reduced if: (i) clear and convincing evidence 
22    and independent analysis demonstrates that the expenditure 
23    limits in subsection (m) of this Section preclude full 
24    achievement of the goals, (ii) each of the following 
25    conditions are met: (A) the plan's analysis and forecasts 
26    of the utility's ability to acquire energy savings 
 
 
10400SB0025ham003- 547 -LRB104 07069 AAS 29208 a

1    demonstrate by clear and convincing evidence and through 
2    independent analysis that achievement of such goals is not 
3    cost-effective; and (B) the amount of energy savings 
4    achieved by the utility, as determined by the independent 
5    evaluator, for the most recent year for which savings have 
6    been evaluated preceding the plan filing was less than the 
7    average annual amount of savings required to achieve the 
8    goals for the applicable multi-year plan period, or (iii) 
9    changes in federal law, programs, or tariffs have a 
10    significant and demonstrable impact on the cost of 
11    delivering measures and programs. If there is not clear 
12    and convincing evidence that achieving the savings goals 
13    specified in subsection (b-16) is possible both 
14    cost-effectively and within the expenditure limits in 
15    subsection (m), such savings goals shall not be reduced. 
16    Except as provided in subsection (m), annual savings goals 
17    during the applicable multi-year plan period shall not be 
18    reduced to amounts that are less than the maximum amount 
19    of annual savings that is forecasted to be 
20    cost-effectively achievable during the applicable 
21    multi-year plan period. The Commission shall review any 
22    proposed goal reduction as part of its review and approval 
23    of the utility's proposed plan. the cumulative persisting 
24    annual savings goals specified in paragraphs (9) through 
25    (12) of subsection (b-5) of this Section or in paragraphs 
26    (9) through (12) of subsection (b-15) of this Section, as 
 
 
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1    applicable, through implementation of energy efficiency 
2    measures; however, the goals may be reduced if either (1) 
3    clear and convincing evidence demonstrates, through 
4    independent analysis, that the expenditure limits in 
5    subsection (m) of this Section preclude full achievement 
6    of the goals or (2) each of the following conditions are 
7    met: (A) the plan's analysis and forecasts of the 
8    utility's ability to acquire energy savings demonstrate by 
9    clear and convincing evidence and through independent 
10    analysis that achievement of such goals is not cost 
11    effective; and (B) the amount of energy savings achieved 
12    by the utility as determined by the independent evaluator 
13    for the most recent year for which savings have been 
14    evaluated preceding the plan filing was less than the 
15    average annual amount of savings required to achieve the 
16    goals for the applicable 4-year plan period. If there is 
17    not clear and convincing evidence that achieving the 
18    savings goals specified in paragraphs (b-5) or (b-15) of 
19    this Section is possible both cost-effectively and within 
20    the expenditure limits in subsection (m), such savings 
21    goals shall not be reduced. Except as provided in 
22    subsection (m) of this Section, annual increases in 
23    cumulative persisting annual savings goals during the 
24    applicable 4-year plan period shall not be reduced to 
25    amounts that are less than the maximum amount of 
26    cumulative persisting annual savings that is forecast to 
 
 
10400SB0025ham003- 549 -LRB104 07069 AAS 29208 a

1    be cost-effectively achievable during the 4-year plan 
2    period. The Commission shall review any proposed goal 
3    reduction as part of its review and approval of the 
4    utility's proposed plan.    
5        (4) No later than March 1, 2029, and every 4 years 
6    thereafter, each electric utility shall file a 4-year 
7    energy efficiency plan commencing on January 1, 2030, and 
8    every 4 years thereafter, respectively, that is designed 
9    to achieve the cumulative persisting annual savings goals 
10    established by the Illinois Commerce Commission pursuant 
11    to direction of subsections (b-5) and (b-15) of this 
12    Section, as applicable, through implementation of energy 
13    efficiency measures, lifetime energy equal to the product 
14    of the incremental annual savings goals defined by 
15    paragraph (1) of subsection (b-16) and the minimum average 
16    savings life described in paragraph (C) of subsection 
17    (b-16) of this Section. The 3-year energy efficiency plan 
18    of a utility that serves less than 3,000,000 retail 
19    customers but more than 500,000 retail customers in the 
20    State must also be designed to achieve lifetime peak 
21    demand savings equal to the product of the incremental 
22    annual savings goals defined by paragraph (2) of 
23    subsection (b-16) and the minimum average savings life 
24    defined by paragraph (3) of subsection (b-16) through 
25    implementation of energy efficiency measures. However ; 
26    however, the goals may be reduced if: either (1) clear and 
 
 
10400SB0025ham003- 550 -LRB104 07069 AAS 29208 a

1    convincing evidence and independent analysis demonstrates 
2    that the expenditure limits in subsection (m) of this 
3    Section preclude full achievement of the goals, or (2) 
4    each of the following conditions are met: (A) the plan's 
5    analysis and forecasts of the utility's ability to acquire 
6    energy savings demonstrate by clear and convincing 
7    evidence and through independent analysis that achievement 
8    of such goals is not cost-effective; and (B) the amount of 
9    energy savings achieved by the utility as determined by 
10    the independent evaluator for the most recent year for 
11    which savings have been evaluated preceding the plan 
12    filing was less than the average annual amount of savings 
13    required to achieve the goals for the applicable 
14    multi-year 4-year plan period, or (3) changes in federal 
15    law, programs, or tariffs have a significant and 
16    demonstrable impact on the cost of delivering measures and 
17    programs. If there is not clear and convincing evidence 
18    that achieving the savings goals specified in paragraph 
19    (b-16) paragraphs (b-5) or (b-15) of this Section is 
20    possible both cost-effectively and within the expenditure 
21    limits in subsection (m), such savings goals shall not be 
22    reduced. Except as provided in subsection (m) of this 
23    Section, annual increases in cumulative persisting annual 
24    savings goals during the applicable multi-year 4-year plan 
25    period shall not be reduced to amounts that are less than 
26    the maximum amount of cumulative persisting annual savings 
 
 
10400SB0025ham003- 551 -LRB104 07069 AAS 29208 a

1    that is forecast to be cost-effectively achievable during 
2    the applicable multi-year 4-year plan period. The 
3    Commission shall review any proposed goal reduction as 
4    part of its review and approval of the utility's proposed 
5    plan.
6    Each utility's plan shall set forth the utility's 
7proposals to meet the energy efficiency standards identified 
8in subsection (b-5), or (b-15), or (b-16), as applicable and 
9as such standards may have been modified under this subsection 
10(f), taking into account the unique circumstances of the 
11utility's service territory. For those plans commencing on 
12January 1, 2018, the Commission shall seek public comment on 
13the utility's plan and shall issue an order approving or 
14disapproving each plan no later than 105 days after June 1, 
152017 (the effective date of Public Act 99-906). For those 
16plans commencing after December 31, 2021, the Commission shall 
17seek public comment on the utility's plan and shall issue an 
18order approving or disapproving each plan within 6 months 
19after its submission. If the Commission disapproves a plan, 
20the Commission shall, within 30 days, describe in detail the 
21reasons for the disapproval and describe a path by which the 
22utility may file a revised draft of the plan to address the 
23Commission's concerns satisfactorily. If the utility does not 
24refile with the Commission within 60 days, the utility shall 
25be subject to penalties at a rate of $100,000 per day until the 
26plan is filed. This process shall continue, and penalties 
 
 
10400SB0025ham003- 552 -LRB104 07069 AAS 29208 a

1shall accrue, until the utility has successfully filed a 
2portfolio of energy efficiency and demand-response measures. 
3Penalties shall be deposited into the Energy Efficiency Trust 
4Fund. 
5    (g) In submitting proposed plans and funding levels under 
6subsection (f) of this Section to meet the savings goals 
7identified in subsection (b-5), or (b-15), or (b-16) of this 
8Section, as applicable, the utility shall:
9        (1) Demonstrate that its proposed energy efficiency 
10    measures will achieve the applicable requirements that are 
11    identified in subsection (b-5), or (b-15), or (b-16) of 
12    this Section, as modified by subsection (f) of this 
13    Section.
14        (2) (Blank).
15        (2.5) Demonstrate consideration of program options for 
16    (A) advancing new building codes, appliance standards, and 
17    municipal regulations governing existing and new building 
18    efficiency improvements and (B) supporting efforts to 
19    improve compliance with new building codes, appliance 
20    standards and municipal regulations, as potentially 
21    cost-effective means of acquiring energy savings to count 
22    toward savings goals. 
23        (3) Demonstrate that its overall portfolio of 
24    measures, not including low-income programs described in 
25    subsection (c) of this Section, is cost-effective using 
26    the total resource cost test or complies with paragraphs 
 
 
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1    (1) through (3) of subsection (f) of this Section and 
2    represents a diverse cross-section of opportunities for 
3    customers of all rate classes, other than those customers 
4    described in subsection (l) of this Section, to 
5    participate in the programs. Individual measures need not 
6    be cost effective.
7        (3.5) Demonstrate that the utility's plan integrates 
8    the delivery of energy efficiency programs with natural 
9    gas efficiency programs, programs promoting distributed 
10    solar, programs promoting demand response and other 
11    efforts to address bill payment issues, including, but not 
12    limited to, LIHEAP and the Percentage of Income Payment 
13    Plan, to the extent such integration is practical and has 
14    the potential to enhance customer engagement, minimize 
15    market confusion, or reduce administrative costs. 
16        (4) If the utility chooses, present Present a 
17    third-party energy efficiency implementation program 
18    subject to the following requirements:
19            (A) (blank); beginning with the year commencing 
20        January 1, 2019, electric utilities that serve more 
21        than 3,000,000 retail customers in the State shall 
22        fund third-party energy efficiency programs in an 
23        amount that is no less than $25,000,000 per year, and 
24        electric utilities that serve less than 3,000,000 
25        retail customers but more than 500,000 retail 
26        customers in the State shall fund third-party energy 
 
 
10400SB0025ham003- 554 -LRB104 07069 AAS 29208 a

1        efficiency programs in an amount that is no less than 
2        $8,350,000 per year;
3            (B) during 2018, the utility shall conduct a 
4        solicitation process for purposes of requesting 
5        proposals from third-party vendors for those 
6        third-party energy efficiency programs to be offered 
7        during one or more of the years commencing January 1, 
8        2019, January 1, 2020, and January 1, 2021; for those 
9        multi-year plans commencing on January 1, 2022 and 
10        January 1, 2026, the utility shall conduct a 
11        solicitation process during 2021 and 2025, 
12        respectively, for purposes of requesting proposals 
13        from third-party vendors for those third-party energy 
14        efficiency programs to be offered during one or more 
15        years of the respective multi-year plan period; for 
16        each solicitation process, the utility shall identify 
17        the sector, technology, or geographical area for which 
18        it is seeking requests for proposals; the solicitation 
19        process must be either for programs that fill gaps in 
20        the utility's program portfolio and for programs that 
21        target low-income customers, business sectors, 
22        building types, geographies, or other specific parts 
23        of its customer base with initiatives that would be 
24        more effective at reaching these customer segments 
25        than the utilities' programs filed in its energy 
26        efficiency plans;
 
 
10400SB0025ham003- 555 -LRB104 07069 AAS 29208 a

1            (C) the utility shall propose the bidder 
2        qualifications, performance measurement process, and 
3        contract structure, which must include a performance 
4        payment mechanism and general terms and conditions; 
5        the proposed qualifications, process, and structure 
6        shall be subject to Commission approval; and
7            (D) the utility shall retain an independent third 
8        party to score the proposals received through the 
9        solicitation process described in this paragraph (4), 
10        rank them according to their cost per lifetime 
11        kilowatt-hours saved, and assemble the portfolio of 
12        third-party programs.
13        The electric utility shall recover all costs 
14    associated with Commission-approved, third-party 
15    administered programs regardless of the success of those 
16    programs. 
17        (4.5) Implement cost-effective demand-response 
18    measures to reduce peak demand by 0.1% over the prior year 
19    for eligible retail customers, as defined in Section 
20    16-111.5 of this Act, and for customers that elect hourly 
21    service from the utility pursuant to Section 16-107 of 
22    this Act, provided those customers have not been declared 
23    competitive. This requirement continues until December 31, 
24    2026. 
25        (5) Include a proposed or revised cost-recovery tariff 
26    mechanism, as provided for under subsection (d) of this 
 
 
10400SB0025ham003- 556 -LRB104 07069 AAS 29208 a

1    Section, to fund the proposed energy efficiency and 
2    demand-response measures and to ensure the recovery of the 
3    prudently and reasonably incurred costs of 
4    Commission-approved programs.
5        (6) Provide for an annual independent evaluation of 
6    the performance of the cost-effectiveness of the utility's 
7    portfolio of measures, as well as a full review of the 
8    multi-year plan results of the broader net program impacts 
9    and, to the extent practical, for adjustment of the 
10    measures on a going-forward basis as a result of the 
11    evaluations. The resources dedicated to evaluation shall 
12    not exceed 3% of portfolio resources in any given year.
13        (7) For electric utilities that serve more than 
14    3,000,000 retail customers in the State:
15            (A) Through December 31, 2026 2025, provide for an 
16        adjustment to the return on equity component of the 
17        utility's weighted average cost of capital calculated 
18        under subsection (d) of this Section:
19                (i) If the independent evaluator determines 
20            that the utility achieved a cumulative persisting 
21            annual savings that is less than the applicable 
22            annual incremental goal, then the return on equity 
23            component shall be reduced by a maximum of 200 
24            basis points in the event that the utility 
25            achieved no more than 75% of such goal. If the 
26            utility achieved more than 75% of the applicable 
 
 
10400SB0025ham003- 557 -LRB104 07069 AAS 29208 a

1            annual incremental goal but less than 100% of such 
2            goal, then the return on equity component shall be 
3            reduced by 8 basis points for each percent by 
4            which the utility failed to achieve the goal.
5                (ii) If the independent evaluator determines 
6            that the utility achieved a cumulative persisting 
7            annual savings that is more than the applicable 
8            annual incremental goal, then the return on equity 
9            component shall be increased by a maximum of 200 
10            basis points in the event that the utility 
11            achieved at least 125% of such goal. If the 
12            utility achieved more than 100% of the applicable 
13            annual incremental goal but less than 125% of such 
14            goal, then the return on equity component shall be 
15            increased by 8 basis points for each percent by 
16            which the utility achieved above the goal. If the 
17            applicable annual incremental goal was reduced 
18            under paragraph (1) or (2) of subsection (f) of 
19            this Section, then the following adjustments shall 
20            be made to the calculations described in this item 
21            (ii):
22                    (aa) the calculation for determining 
23                achievement that is at least 125% of the 
24                applicable annual incremental goal shall use 
25                the unreduced applicable annual incremental 
26                goal to set the value; and
 
 
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1                    (bb) the calculation for determining 
2                achievement that is less than 125% but more 
3                than 100% of the applicable annual incremental 
4                goal shall use the reduced applicable annual 
5                incremental goal to set the value for 100% 
6                achievement of the goal and shall use the 
7                unreduced goal to set the value for 125% 
8                achievement. The 8 basis point value shall 
9                also be modified, as necessary, so that the 
10                200 basis points are evenly apportioned among 
11                each percentage point value between 100% and 
12                125% achievement.
13            (B) (Blank). For the period January 1, 2026 
14        through December 31, 2029 and in all subsequent 4-year 
15        periods, provide for an adjustment to the return on 
16        equity component of the utility's weighted average 
17        cost of capital calculated under subsection (d) of 
18        this Section:
19                (i) If the independent evaluator determines 
20            that the utility achieved a cumulative persisting 
21            annual savings that is less than the applicable 
22            annual incremental goal, then the return on equity 
23            component shall be reduced by a maximum of 200 
24            basis points in the event that the utility 
25            achieved no more than 66% of such goal. If the 
26            utility achieved more than 66% of the applicable 
 
 
10400SB0025ham003- 559 -LRB104 07069 AAS 29208 a

1            annual incremental goal but less than 100% of such 
2            goal, then the return on equity component shall be 
3            reduced by 6 basis points for each percent by 
4            which the utility failed to achieve the goal.
5                (ii) If the independent evaluator determines 
6            that the utility achieved a cumulative persisting 
7            annual savings that is more than the applicable 
8            annual incremental goal, then the return on equity 
9            component shall be increased by a maximum of 200 
10            basis points in the event that the utility 
11            achieved at least 134% of such goal. If the 
12            utility achieved more than 100% of the applicable 
13            annual incremental goal but less than 134% of such 
14            goal, then the return on equity component shall be 
15            increased by 6 basis points for each percent by 
16            which the utility achieved above the goal. If the 
17            applicable annual incremental goal was reduced 
18            under paragraph (3) of subsection (f) of this 
19            Section, then the following adjustments shall be 
20            made to the calculations described in this item 
21            (ii):
22                    (aa) the calculation for determining 
23                achievement that is at least 134% of the 
24                applicable annual incremental goal shall use 
25                the unreduced applicable annual incremental 
26                goal to set the value; and
 
 
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1                    (bb) the calculation for determining 
2                achievement that is less than 134% but more 
3                than 100% of the applicable annual incremental 
4                goal shall use the reduced applicable annual 
5                incremental goal to set the value for 100% 
6                achievement of the goal and shall use the 
7                unreduced goal to set the value for 134% 
8                achievement. The 6 basis point value shall 
9                also be modified, as necessary, so that the 
10                200 basis points are evenly apportioned among 
11                each percentage point value between 100% and 
12                134% achievement. 
13            (C) (Blank). Notwithstanding the provisions of 
14        subparagraphs (A) and (B) of this paragraph (7), if 
15        the applicable annual incremental goal for an electric 
16        utility is ever less than 0.6% of deemed average 
17        weather normalized sales of electric power and energy 
18        during calendar years 2014, 2015, and 2016, an 
19        adjustment to the return on equity component of the 
20        utility's weighted average cost of capital calculated 
21        under subsection (d) of this Section shall be made as 
22        follows:
23                (i) If the independent evaluator determines 
24            that the utility achieved a cumulative persisting 
25            annual savings that is less than would have been 
26            achieved had the applicable annual incremental 
 
 
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1            goal been achieved, then the return on equity 
2            component shall be reduced by a maximum of 200 
3            basis points if the utility achieved no more than 
4            75% of its applicable annual total savings 
5            requirement as defined in paragraph (7.5) of this 
6            subsection. If the utility achieved more than 75% 
7            of the applicable annual total savings requirement 
8            but less than 100% of such goal, then the return on 
9            equity component shall be reduced by 8 basis 
10            points for each percent by which the utility 
11            failed to achieve the goal.
12                (ii) If the independent evaluator determines 
13            that the utility achieved a cumulative persisting 
14            annual savings that is more than would have been 
15            achieved had the applicable annual incremental 
16            goal been achieved, then the return on equity 
17            component shall be increased by a maximum of 200 
18            basis points if the utility achieved at least 125% 
19            of its applicable annual total savings 
20            requirement. If the utility achieved more than 
21            100% of the applicable annual total savings 
22            requirement but less than 125% of such goal, then 
23            the return on equity component shall be increased 
24            by 8 basis points for each percent by which the 
25            utility achieved above the applicable annual total 
26            savings requirement. If the applicable annual 
 
 
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1            incremental goal was reduced under paragraph (1) 
2            or (2) of subsection (f) of this Section, then the 
3            following adjustments shall be made to the 
4            calculations described in this item (ii):
5                    (aa) the calculation for determining 
6                achievement that is at least 125% of the 
7                applicable annual total savings requirement 
8                shall use the unreduced applicable annual 
9                incremental goal to set the value; and
10                    (bb) the calculation for determining 
11                achievement that is less than 125% but more 
12                than 100% of the applicable annual total 
13                savings requirement shall use the reduced 
14                applicable annual incremental goal to set the 
15                value for 100% achievement of the goal and 
16                shall use the unreduced goal to set the value 
17                for 125% achievement. The 8 basis point value 
18                shall also be modified, as necessary, so that 
19                the 200 basis points are evenly apportioned 
20                among each percentage point value between 100% 
21                and 125% achievement. 
22        (7.5) For purposes of this Section, the term 
23    "applicable annual incremental goal" means the difference 
24    between the cumulative persisting annual savings goal for 
25    the calendar year that is the subject of the independent 
26    evaluator's determination and the cumulative persisting 
 
 
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1    annual savings goal for the immediately preceding calendar 
2    year, as such goals are defined in subsections (b-5) and 
3    (b-15) of this Section and as these goals may have been 
4    modified as provided for under subsection (b-20) and 
5    paragraphs (1) and (2) through (3) of subsection (f) of 
6    this Section. Under subsections (b), (b-5), (b-10), and 
7    (b-15) of this Section, a utility must first replace 
8    energy savings from measures that have expired before any 
9    progress towards achievement of its applicable annual 
10    incremental goal may be counted. Savings may expire 
11    because measures installed in previous years have reached 
12    the end of their lives, because measures installed in 
13    previous years are producing lower savings in the current 
14    year than in the previous year, or for other reasons 
15    identified by independent evaluators. Notwithstanding 
16    anything else set forth in this Section, the difference 
17    between the actual annual incremental savings achieved in 
18    any given year, including the replacement of energy 
19    savings that have expired, and the applicable annual 
20    incremental goal shall not affect adjustments to the 
21    return on equity for subsequent calendar years under this 
22    subsection (g). 
23        In this Section, "applicable annual total savings 
24    requirement" means the total amount of new annual savings 
25    that the utility must achieve in any given year to achieve 
26    the applicable annual incremental goal. This is equal to 
 
 
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1    the applicable annual incremental goal plus the total new 
2    annual savings that are required to replace savings that 
3    expired in or at the end of the previous year. 
4        (8) For electric utilities that serve less than 
5    3,000,000 retail customers but more than 500,000 retail 
6    customers in the State:
7            (A) Through December 31, 2026 2025, the applicable 
8        annual incremental goal shall be compared to the 
9        annual incremental savings as determined by the 
10        independent evaluator.
11                (i) The return on equity component shall be 
12            reduced by 8 basis points for each percent by 
13            which the utility did not achieve 84.4% of the 
14            applicable annual incremental goal.
15                (ii) The return on equity component shall be 
16            increased by 8 basis points for each percent by 
17            which the utility exceeded 100% of the applicable 
18            annual incremental goal.
19                (iii) The return on equity component shall not 
20            be increased or decreased if the annual 
21            incremental savings as determined by the 
22            independent evaluator is greater than 84.4% of the 
23            applicable annual incremental goal and less than 
24            100% of the applicable annual incremental goal.
25                (iv) The return on equity component shall not 
26            be increased or decreased by an amount greater 
 
 
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1            than 200 basis points pursuant to this 
2            subparagraph (A).
3            (B) (Blank). For the period of January 1, 2026 
4        through December 31, 2029 and in all subsequent 4-year 
5        periods, the applicable annual incremental goal shall 
6        be compared to the annual incremental savings as 
7        determined by the independent evaluator.
8                (i) The return on equity component shall be 
9            reduced by 6 basis points for each percent by 
10            which the utility did not achieve 100% of the 
11            applicable annual incremental goal.
12                (ii) The return on equity component shall be 
13            increased by 6 basis points for each percent by 
14            which the utility exceeded 100% of the applicable 
15            annual incremental goal.
16                (iii) The return on equity component shall not 
17            be increased or decreased by an amount greater 
18            than 200 basis points pursuant to this 
19            subparagraph (B).
20            (C) (Blank). Notwithstanding provisions in 
21        subparagraphs (A) and (B) of paragraph (7) of this 
22        subsection, if the applicable annual incremental goal 
23        for an electric utility is ever less than 0.6% of 
24        deemed average weather normalized sales of electric 
25        power and energy during calendar years 2014, 2015 and 
26        2016, an adjustment to the return on equity component 
 
 
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1        of the utility's weighted average cost of capital 
2        calculated under subsection (d) of this Section shall 
3        be made as follows:
4                (i) The return on equity component shall be 
5            reduced by 8 basis points for each percent by 
6            which the utility did not achieve 100% of the 
7            applicable annual total savings requirement.
8                (ii) The return on equity component shall be 
9            increased by 8 basis points for each percent by 
10            which the utility exceeded 100% of the applicable 
11            annual total savings requirement.
12                (iii) The return on equity component shall not 
13            be increased or decreased by an amount greater 
14            than 200 basis points pursuant to this 
15            subparagraph (C). 
16            (D) (Blank). If the applicable annual incremental 
17        goal was reduced under paragraph (1), (2), (3), or (4) 
18        of subsection (f) of this Section, then the following 
19        adjustments shall be made to the calculations 
20        described in subparagraphs (A), (B), and (C) of this 
21        paragraph (8):
22                (i) The calculation for determining 
23            achievement that is at least 125% or 134%, as 
24            applicable, of the applicable annual incremental 
25            goal or the applicable annual total savings 
26            requirement, as applicable, shall use the 
 
 
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1            unreduced applicable annual incremental goal to 
2            set the value.
3                (ii) For the period through December 31, 2025, 
4            the calculation for determining achievement that 
5            is less than 125% but more than 100% of the 
6            applicable annual incremental goal or the 
7            applicable annual total savings requirement, as 
8            applicable, shall use the reduced applicable 
9            annual incremental goal to set the value for 100% 
10            achievement of the goal and shall use the 
11            unreduced goal to set the value for 125% 
12            achievement. The 8 basis point value shall also be 
13            modified, as necessary, so that the 200 basis 
14            points are evenly apportioned among each 
15            percentage point value between 100% and 125% 
16            achievement.
17                (iii) For the period of January 1, 2026 
18            through December 31, 2029 and all subsequent 
19            4-year periods, the calculation for determining 
20            achievement that is less than 125% or 134%, as 
21            applicable, but more than 100% of the applicable 
22            annual incremental goal or the applicable annual 
23            total savings requirement, as applicable, shall 
24            use the reduced applicable annual incremental goal 
25            to set the value for 100% achievement of the goal 
26            and shall use the unreduced goal to set the value 
 
 
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1            for 125% achievement. The 6 basis-point value or 8 
2            basis-point value, as applicable, shall also be 
3            modified, as necessary, so that the 200 basis 
4            points are evenly apportioned among each 
5            percentage point value between 100% and 125% or 
6            between 100% and 134% achievement, as applicable.
7        (8.5) Beginning January 1, 2027, a utility that serves 
8    greater than 500,000 retail customers in the State shall 
9    have the utility's return on equity modified for 
10    performance on the utility's energy savings and peak 
11    demand savings goals as follows:
12            (A) The return on equity for a utility that serves 
13        more than 3,000,000 retail customers in the State may 
14        be adjusted up or down by a maximum of 200 basis points 
15        for its performance relative to its incremental annual 
16        energy savings goal. The return on equity for a 
17        utility that serves less than 3,000,000 retail 
18        customers but more than 500,000 retail customers in 
19        the State may be adjusted up or down by a maximum of 
20        100 basis points for its performance relative to its 
21        incremental annual energy savings goal and a maximum 
22        of 100 basis points for its performance relative to 
23        its incremental annual coincident peak demand savings 
24        goal.
25            (B) A utility's performance on its savings goals 
26        shall be established by comparing the actual lifetime 
 
 
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1        energy, and coincident peak demand savings if a 
2        utility serves less than 3,000,000 retail customers 
3        but more than 500,000 retail customers in the State, 
4        achieved from efficiency measures installed in a given 
5        year to the product of the incremental annual goals 
6        established in paragraphs (1) and (2) of subsection 
7        (b-16) and the minimum average savings lives 
8        established in paragraph (3) of subsection (b-16), as 
9        modified, if applicable, by the Commission under 
10        paragraph (4) of subsection (f) of this Section. For 
11        the purposes of this paragraph (8.5), "lifetime 
12        savings" means the total incremental savings that 
13        installed efficiency measures are projected to 
14        produce, relative to what would have occurred absent 
15        to the utility's efficiency programs, over the useful 
16        lives of the measures. Performance on the energy 
17        savings goal, and coincident peak demand savings if a 
18        utility serves less than 3,000,000 retail customers 
19        but more than 500,000 retail customers in the State, 
20        shall be assessed separately, such that it is possible 
21        to earn penalties on both, earn bonuses on both, or 
22        earn a bonus for performance on one goal and a penalty 
23        on the other.
24            (C) No bonus shall be earned if a utility does not 
25        achieve greater than 100% of an approved goal. The 
26        maximum bonus for a goal shall be earned if the utility 
 
 
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1        achieves 125% of the unmodified goal. For a utility 
2        that serves less than 3,000,000 retail customers but 
3        more than 500,000 retail customers in the State, the 
4        bonus earned for achieving more than 100% of an 
5        approved goal but less than 125% of the unmodified 
6        goal shall be linearly interpolated. For a utility 
7        with more than 3,000,000 retail customers, the maximum 
8        bonus for a goal shall be earned if the utility 
9        achieves 125% of the unmodified goal. For a utility 
10        with more than 3,000,000 retail customers, the bonus 
11        earned for achieving more than 100% of an approved 
12        goal but less than 125% of the unmodified goal shall be 
13        linearly interpolated.
14            (D) For utilities with greater than 3,000,000 
15        retail customers, the return on equity shall be 
16        unmodified due to performance on an individual goal 
17        only if the utility achieves exactly 100% of the goal. 
18        For utilities with more than 500,000 but fewer than 
19        3,000,000 retail customers, the return on equity shall 
20        be unmodified for achieving between 85% and 100% of 
21        the goal.
22            (E) Penalties may be earned for falling short of 
23        goals, with the magnitude of any penalty being a 
24        function of both the size of the utility and whether 
25        goals established in subsection (b-16) are modified by 
26        the Commission under paragraph (4) of subsection (f) 
 
 
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1        of this Section, as follows:
2                (i) If the savings goals specified in 
3            subsection (b-16) of this Section are unmodified, 
4            a utility with more than 3,000,000 retail 
5            customers shall earn the maximum penalty allocated 
6            to a goal for achieving 75% or less of the goal. 
7            The penalty for achieving greater than 75% but 
8            less than 100% of the goal shall be linearly 
9            interpolated.
10                (ii) If the savings goals specified in 
11            subsection (b-16) of this Section are unmodified, 
12            a utility with more than 500,000 but fewer than 
13            3,000,000 retail customers shall earn the maximum 
14            penalty allocated to a goal for achieving at least 
15            33.3 percentage points less than the bottom end of 
16            the deadband specified in subparagraph (D) of this 
17            paragraph (8.5). The penalty for achieving less 
18            than the bottom end of the deadband and greater 
19            than 33.3 percentage points less than the bottom 
20            end of the deadband shall be linearly 
21            interpolated.
22                (iii) If either the energy or peak demand 
23            savings goals specified in subsection (b-16) are 
24            reduced under paragraph (3) or (4) of subsection 
25            (f) of this Section, the maximum penalty allocated 
26            to a goal shall be earned if the utility achieves 
 
 
10400SB0025ham003- 572 -LRB104 07069 AAS 29208 a

1            80% or less of the modified goal. The penalty for 
2            achieving more than 80% but less than 100% of a 
3            modified goal shall be linearly interpolated.    
4        (9) The utility shall submit the energy savings data 
5    to the independent evaluator no later than 30 days after 
6    the close of the plan year. The independent evaluator 
7    shall determine the cumulative persisting annual savings 
8    and annual incremental savings for a given plan year, as 
9    well as an estimate of job impacts and other macroeconomic 
10    impacts of the efficiency programs for that year, no later 
11    than 120 days after the close of the plan year. The utility 
12    shall submit an informational filing to the Commission no 
13    later than 160 days after the close of the plan year that 
14    attaches the independent evaluator's final report 
15    identifying the cumulative persisting annual savings for 
16    the year and calculates, under paragraph (7) or (8) of 
17    this subsection (g), as applicable, any resulting change 
18    to the utility's return on equity component of the 
19    weighted average cost of capital applicable to the next 
20    plan year beginning with the January monthly billing 
21    period and extending through the December monthly billing 
22    period. However, if the utility recovers the costs 
23    incurred under this Section under paragraphs (2) and (3) 
24    of subsection (d) of this Section, then the utility shall 
25    not be required to submit such informational filing, and 
26    shall instead submit the information that would otherwise 
 
 
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1    be included in the informational filing as part of its 
2    filing under paragraph (3) of such subsection (d) that is 
3    due on or before June 1 of each year.
4        For those utilities that must submit the informational 
5    filing, the Commission may, on its own motion or by 
6    petition, initiate an investigation of such filing, 
7    provided, however, that the utility's proposed return on 
8    equity calculation shall be deemed the final, approved 
9    calculation on December 15 of the year in which it is filed 
10    unless the Commission enters an order on or before 
11    December 15, after notice and hearing, that modifies such 
12    calculation consistent with this Section.
13        The adjustments to the return on equity component 
14    described in paragraphs (7) and (8) of this subsection (g) 
15    shall be applied as described in such paragraphs through a 
16    separate tariff mechanism, which shall be filed by the 
17    utility under subsections (f) and (g) of this Section. 
18        (9.5) The utility must demonstrate how it will ensure 
19    that program implementation contractors and energy 
20    efficiency installation vendors will promote workforce 
21    equity and quality jobs. For all construction, 
22    installation, or other related services procured under 
23    this Section, an electric utility must:
24            (A) award a bid preference of 2% to a contractor if 
25        the contractor certifies under oath that the 
26        contractor's primary place of business is located 
 
 
10400SB0025ham003- 574 -LRB104 07069 AAS 29208 a

1        within the utility's service area; and
2            (B) award a bid preference of 2% to a contractor if 
3        the contractor certifies under oath that at least 85% 
4        of the workforce to be utilized for such construction, 
5        installation, or other related services reside in the 
6        utility's service area.    
7        (9.6) Utilities shall collect data necessary to ensure 
8    compliance with paragraph (9.5) no less than quarterly and 
9    shall communicate progress toward compliance with 
10    paragraph (9.5) to program implementation contractors and 
11    energy efficiency installation vendors no less than 
12    quarterly. Utilities shall work with relevant vendors, 
13    providing education, training, and other resources needed 
14    to ensure compliance and, where necessary, adjusting or 
15    terminating work with vendors that cannot assist with 
16    compliance.
17        (10) Utilities required to implement efficiency 
18    programs under subsections (b-5), and (b-10), and (b-16)    
19    shall report annually to the Illinois Commerce Commission 
20    and the General Assembly on how hiring, contracting, job 
21    training, and other practices related to its energy 
22    efficiency programs enhance the diversity of vendors 
23    working on such programs. These reports must include data 
24    on vendor and employee diversity, including data on the 
25    implementation of paragraphs (9.5) and (9.6) and the 
26    proportion of total program dollars awarded to firms that 
 
 
10400SB0025ham003- 575 -LRB104 07069 AAS 29208 a

1    meet the criteria of subparagraphs (A) and (B) of 
2    paragraph (9.5). If the utility is not meeting the 
3    requirements of paragraphs (9.5) and (9.6), the utility 
4    shall submit a plan to adjust their activities so that 
5    they meet the requirements of paragraphs (9.5) and (9.6) 
6    within the following year.
7    (h) No more than 4% of energy efficiency and 
8demand-response program revenue may be allocated for research, 
9development, or pilot deployment of new equipment or measures. 
10Electric utilities shall work with interested stakeholders to 
11formulate a plan for how these funds should be spent, 
12incorporate statewide approaches for these allocations, and 
13file a 4-year plan that demonstrates that collaboration. If a 
14utility files a request for modified annual energy savings 
15goals with the Commission, then a utility shall forgo spending 
16portfolio dollars on research and development proposals. 
17    (i) When practicable, electric utilities shall incorporate 
18advanced metering infrastructure data into the planning, 
19implementation, and evaluation of energy efficiency measures 
20and programs, subject to the data privacy and confidentiality 
21protections of applicable law.
22    (j) The independent evaluator shall follow the guidelines 
23and use the savings set forth in Commission-approved energy 
24efficiency policy manuals and technical reference manuals, as 
25each may be updated from time to time. Until such time as 
26measure life values for energy efficiency measures implemented 
 
 
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1for low-income households under subsection (c) of this Section 
2are incorporated into such Commission-approved manuals, the 
3low-income measures shall have the same measure life values 
4that are established for same measures implemented in 
5households that are not low-income households.
6    (k) Notwithstanding any provision of law to the contrary, 
7an electric utility subject to the requirements of this 
8Section may file a tariff cancelling an automatic adjustment 
9clause tariff in effect under this Section or Section 8-103, 
10which shall take effect no later than one business day after 
11the date such tariff is filed. Thereafter, the utility shall 
12be authorized to defer and recover its expenditures incurred 
13under this Section through a new tariff authorized under 
14subsection (d) of this Section or in the utility's next rate 
15case under Article IX or Section 16-108.5 of this Act, with 
16interest at an annual rate equal to the utility's weighted 
17average cost of capital as approved by the Commission in such 
18case. If the utility elects to file a new tariff under 
19subsection (d) of this Section, the utility may file the 
20tariff within 10 days after June 1, 2017 (the effective date of 
21Public Act 99-906), and the cost inputs to such tariff shall be 
22based on the projected costs to be incurred by the utility 
23during the calendar year in which the new tariff is filed and 
24that were not recovered under the tariff that was cancelled as 
25provided for in this subsection. Such costs shall include 
26those incurred or to be incurred by the utility under its 
 
 
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1multi-year plan approved under subsections (f) and (g) of this 
2Section, including, but not limited to, projected capital 
3investment costs and projected regulatory asset balances with 
4correspondingly updated depreciation and amortization reserves 
5and expense. The Commission shall, after notice and hearing, 
6approve, or approve with modification, such tariff and cost 
7inputs no later than 75 days after the utility filed the 
8tariff, provided that such approval, or approval with 
9modification, shall be consistent with the provisions of this 
10Section to the extent they do not conflict with this 
11subsection (k). The tariff approved by the Commission shall 
12take effect no later than 5 days after the Commission enters 
13its order approving the tariff.
14    No later than 60 days after the effective date of the 
15tariff cancelling the utility's automatic adjustment clause 
16tariff, the utility shall file a reconciliation that 
17reconciles the moneys collected under its automatic adjustment 
18clause tariff with the costs incurred during the period 
19beginning June 1, 2016 and ending on the date that the electric 
20utility's automatic adjustment clause tariff was cancelled. In 
21the event the reconciliation reflects an under-collection, the 
22utility shall recover the costs as specified in this 
23subsection (k). If the reconciliation reflects an 
24over-collection, the utility shall apply the amount of such 
25over-collection as a one-time credit to retail customers' 
26bills.
 
 
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1    (l) For the calendar years covered by a multi-year plan 
2commencing after December 31, 2017, subsections (a) through 
3(j) of this Section do not apply to eligible large private 
4energy customers that have chosen to opt out of multi-year 
5plans consistent with this subsection (1).
6        (1) For purposes of this subsection (l), "eligible 
7    large private energy customer" means any retail customers, 
8    except for federal, State, municipal, and other public 
9    customers, of an electric utility that serves more than 
10    3,000,000 retail customers, except for federal, State, 
11    municipal and other public customers, in the State and 
12    whose total highest 30 minute demand was more than 10,000 
13    kilowatts, or any retail customers of an electric utility 
14    that serves less than 3,000,000 retail customers but more 
15    than 500,000 retail customers in the State and whose total 
16    highest 15 minute demand was more than 10,000 kilowatts. 
17    For purposes of this subsection (l), "retail customer" has 
18    the meaning set forth in Section 16-102 of this Act. 
19    However, for a business entity with multiple sites located 
20    in the State, where at least one of those sites qualifies 
21    as an eligible large private energy customer, then any of 
22    that business entity's sites, properly identified on a 
23    form for notice, shall be considered eligible large 
24    private energy customers for the purposes of this 
25    subsection (l). A determination of whether this subsection 
26    is applicable to a customer shall be made for each 
 
 
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1    multi-year plan beginning after December 31, 2017. The 
2    criteria for determining whether this subsection (l) is 
3    applicable to a retail customer shall be based on the 12 
4    consecutive billing periods prior to the start of the 
5    first year of each such multi-year plan.
6        (2) Within 45 days after September 15, 2021 (the 
7    effective date of Public Act 102-662), the Commission 
8    shall prescribe the form for notice required for opting 
9    out of energy efficiency programs. The notice must be 
10    submitted to the retail electric utility 12 months before 
11    the next energy efficiency planning cycle. However, within 
12    120 days after the Commission's initial issuance of the 
13    form for notice, eligible large private energy customers 
14    may submit a form for notice to an electric utility. The 
15    form for notice for opting out of energy efficiency 
16    programs shall include all of the following:
17            (A) a statement indicating that the customer has 
18        elected to opt out;
19            (B) the account numbers for the customer accounts 
20        to which the opt out shall apply;
21            (C) the mailing address associated with the 
22        customer accounts identified under subparagraph (B);
23            (D) an American Society of Heating, Refrigerating, 
24        and Air-Conditioning Engineers (ASHRAE) level 2 or 
25        higher audit report conducted by an independent 
26        third-party expert identifying cost-effective energy 
 
 
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1        efficiency project opportunities that could be 
2        invested in over the next 10 years. A retail customer 
3        with specialized processes may utilize a self-audit 
4        process in lieu of the ASHRAE audit;
5            (E) a description of the customer's plans to 
6        reallocate the funds toward internal energy efficiency 
7        efforts identified in the subparagraph (D) report, 
8        including, but not limited to: (i) strategic energy 
9        management or other programs, including descriptions 
10        of targeted buildings, equipment and operations; (ii) 
11        eligible energy efficiency measures; and (iii) 
12        expected energy savings, itemized by technology. If 
13        the subparagraph (D) audit report identifies that the 
14        customer currently utilizes the best available energy 
15        efficient technology, equipment, programs, and 
16        operations, the customer may provide a statement that 
17        more efficient technology, equipment, programs, and 
18        operations are not reasonably available as a means of 
19        satisfying this subparagraph (E); and
20            (F) the effective date of the opt out, which will 
21        be the next January 1 following notice of the opt out.
22        (3) Upon receipt of a properly and timely noticed 
23    request for opt out submitted by an eligible large private 
24    energy customer, the retail electric utility shall grant 
25    the request, file the request with the Commission and, 
26    beginning January 1 of the following year, the opted out 
 
 
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1    customer shall no longer be assessed the costs of the plan 
2    and shall be prohibited from participating in that 4-year 
3    plan cycle to give the retail utility the certainty to 
4    design program plan proposals.
5        (4) Upon a customer's election to opt out under 
6    paragraphs (1) and (2) of this subsection (l) and 
7    commencing on the effective date of said opt out, the 
8    account properly identified in the customer's notice under 
9    paragraph (2) shall not be subject to any cost recovery 
10    and shall not be eligible to participate in, or directly 
11    benefit from, compliance with energy efficiency cumulative 
12    persisting savings requirements under subsections (a) 
13    through (j).
14        (5) A utility's cumulative persisting annual savings 
15    targets will exclude any opted out load.
16        (6) The request to opt out is only valid for the 
17    requested plan cycle. An eligible large private energy 
18    customer must also request to opt out for future energy 
19    plan cycles, otherwise the customer will be included in 
20    the future energy plan cycle. 
21    (m) Notwithstanding the requirements of this Section, as 
22part of a proceeding to approve a multi-year plan under 
23subsections (f) and (g) of this Section if the multi-year plan 
24has been designed to maximize savings, but does not meet the 
25cost cap limitations of this Section, the Commission shall 
26reduce the amount of energy efficiency measures implemented 
 
 
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1for any single year, and whose costs are recovered under 
2subsection (d) of this Section, by an amount necessary to 
3limit the estimated average net increase due to the cost of the 
4measures to no more than
5        (1) 3.5% for each of the 4 years beginning January 1, 
6    2018,
7        (2) (blank),
8        (3) 4% for each of the 4 years beginning January 1, 
9    2022,
10        (3.5) 4.25% for 2026,    
11        (4) 4.25% for electric utilities that serve more than 
12    3,000,000 retail customers in the State, and 4.21% for 
13    2027, 5.25% for 2028, and 6.06% for 2029 for electric 
14    utilities with less than 3,000,000 retail customers but 
15    more than 500,000 retail customers in the State, for the 3    
16    4 years beginning January 1, 2027 2026, and
17        (5) the percentage specified in paragraph (4) 
18    applicable to 2029 4.25% plus an increase sufficient to 
19    account for the rate of inflation between January 1, 2027    
20    2026 and January 1 of the first year of each subsequent 
21    4-year plan cycle, 
22of the average amount paid per kilowatthour by residential 
23eligible retail customers during calendar year 2015 for plans 
24in effect through 2026 and during calendar year 2023 for plans 
25commencing in 2027 and thereafter. An electric utility may 
26plan to spend up to 10% more in any year during an applicable 
 
 
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1multi-year plan period, including any transition period 
2authorized under paragraph (2.5) of subsection (f), to 
3cost-effectively achieve additional savings so long as the 
4average over the applicable multi-year plan period, which 
5shall include any transition period, does not exceed the 
6percentages defined in items (1) through (5). To determine the 
7total amount that may be spent by an electric utility in any 
8single year, the applicable percentage of the average amount 
9paid per kilowatthour shall be multiplied by the total amount 
10of energy delivered by such electric utility in the calendar 
11year 2015 for plans in effect through 2026 and during calendar 
12year 2023 for plans commencing in 2027 and thereafter, 
13adjusted to reflect the proportion of the utility's load 
14attributable to customers that have opted out of subsections 
15(a) through (j) of this Section under subsection (l) of this 
16Section. For purposes of this subsection (m), the amount paid 
17per kilowatthour includes, without limitation, estimated 
18amounts paid for supply, transmission, distribution, 
19surcharges, and add-on taxes. For purposes of this Section, 
20"eligible retail customers" shall have the meaning set forth 
21in Section 16-111.5 of this Act. Once the Commission has 
22approved a plan under subsections (f) and (g) of this Section, 
23no subsequent rate impact determinations shall be made.
24    (n) A utility shall take advantage of the efficiencies 
25available through existing Illinois Home Weatherization 
26Assistance Program infrastructure and services, such as 
 
 
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1enrollment, marketing, quality assurance and implementation, 
2which can reduce the need for similar services at a lower cost 
3than utility-only programs, subject to capacity constraints at 
4community action agencies, for both single-family and 
5multifamily weatherization services, to the extent Illinois 
6Home Weatherization Assistance Program community action 
7agencies provide multifamily services. A utility's plan shall 
8demonstrate that in formulating annual weatherization budgets, 
9it has sought input and coordination with community action 
10agencies regarding agencies' capacity to expand and maximize 
11Illinois Home Weatherization Assistance Program delivery using 
12the ratepayer dollars collected under this Section. 
13(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23; 
14103-613, eff. 7-1-24.)
 
15    (220 ILCS 5/8-406)  (from Ch. 111 2/3, par. 8-406)
16    Sec. 8-406. Certificate of public convenience and 
17necessity. 
18    (a) No public utility not owning any city or village 
19franchise nor engaged in performing any public service or in 
20furnishing any product or commodity within this State as of 
21July 1, 1921 and not possessing a certificate of public 
22convenience and necessity from the Illinois Commerce 
23Commission, the State Public Utilities Commission, or the 
24Public Utilities Commission, at the time Public Act 84-617 
25goes into effect (January 1, 1986), shall transact any 
 
 
10400SB0025ham003- 585 -LRB104 07069 AAS 29208 a

1business in this State until it shall have obtained a 
2certificate from the Commission that public convenience and 
3necessity require the transaction of such business. A 
4certificate of public convenience and necessity requiring the 
5transaction of public utility business in any area of this 
6State shall include authorization to the public utility 
7receiving the certificate of public convenience and necessity 
8to construct such plant, equipment, property, or facility as 
9is provided for under the terms and conditions of its tariff 
10and as is necessary to provide utility service and carry out 
11the transaction of public utility business by the public 
12utility in the designated area.
13    (b) No public utility shall begin the construction of any 
14new plant, equipment, property, or facility which is not in 
15substitution of any existing plant, equipment, property, or 
16facility, or any extension or alteration thereof or in 
17addition thereto, unless and until it shall have obtained from 
18the Commission a certificate that public convenience and 
19necessity require such construction. Whenever after a hearing 
20the Commission determines that any new construction or the 
21transaction of any business by a public utility will promote 
22the public convenience and is necessary thereto, it shall have 
23the power to issue certificates of public convenience and 
24necessity. The Commission shall determine that proposed 
25construction will promote the public convenience and necessity 
26only if the utility demonstrates: (1) that the proposed 
 
 
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1construction is necessary to provide adequate, reliable, and 
2efficient service to its customers and is the least-cost means 
3of satisfying the service needs of its customers or that the 
4proposed construction will promote the development of an 
5effectively competitive electricity market that operates 
6efficiently, is equitable to all customers, and is the 
7least-cost least cost means of satisfying those objectives; 
8(2) that the utility is capable of efficiently managing and 
9supervising the construction process and has taken sufficient 
10action to ensure adequate and efficient construction and 
11supervision thereof; and (3) that the utility is capable of 
12financing the proposed construction without significant 
13adverse financial consequences for the utility or its 
14customers.
15    (b-5) As used in this subsection (b-5):
16    "Qualifying direct current applicant" means an entity that 
17seeks to provide direct current bulk transmission service for 
18the purpose of transporting electric energy in interstate 
19commerce.
20    "Qualifying direct current project" means a high voltage 
21direct current electric service line that crosses at least one 
22Illinois border, the Illinois portion of which is physically 
23located within the region of the Midcontinent Independent 
24System Operator, Inc., or its successor organization, and runs 
25through the counties of Pike, Scott, Greene, Macoupin, 
26Montgomery, Christian, Shelby, Cumberland, and Clark, is 
 
 
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1capable of transmitting electricity at voltages of 345 
2kilovolts or above, and may also include associated 
3interconnected alternating current interconnection facilities 
4in this State that are part of the proposed project and 
5reasonably necessary to connect the project with other 
6portions of the grid.
7    Notwithstanding any other provision of this Act, a 
8qualifying direct current applicant that does not own, 
9control, operate, or manage, within this State, any plant, 
10equipment, or property used or to be used for the transmission 
11of electricity at the time of its application or of the 
12Commission's order may file an application on or before 
13December 31, 2023 with the Commission pursuant to this Section 
14or Section 8-406.1 for, and the Commission may grant, a 
15certificate of public convenience and necessity to construct, 
16operate, and maintain a qualifying direct current project. The 
17qualifying direct current applicant may also include in the 
18application requests for authority under Section 8-503. The 
19Commission shall grant the application for a certificate of 
20public convenience and necessity and requests for authority 
21under Section 8-503 if it finds that the qualifying direct 
22current applicant and the proposed qualifying direct current 
23project satisfy the requirements of this subsection and 
24otherwise satisfy the criteria of this Section or Section 
258-406.1 and the criteria of Section 8-503, as applicable to 
26the application and to the extent such criteria are not 
 
 
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1superseded by the provisions of this subsection. The 
2Commission's order on the application for the certificate of 
3public convenience and necessity shall also include the 
4Commission's findings and determinations on the request or 
5requests for authority pursuant to Section 8-503. Prior to 
6filing its application under either this Section or Section 
78-406.1, the qualifying direct current applicant shall conduct 
83 public meetings in accordance with subsection (h) of this 
9Section. If the qualifying direct current applicant 
10demonstrates in its application that the proposed qualifying 
11direct current project is designed to deliver electricity to a 
12point or points on the electric transmission grid in either or 
13both the PJM Interconnection, LLC or the Midcontinent 
14Independent System Operator, Inc., or their respective 
15successor organizations, the proposed qualifying direct 
16current project shall be deemed to be, and the Commission 
17shall find it to be, for public use. If the qualifying direct 
18current applicant further demonstrates in its application that 
19the proposed transmission project has a capacity of 1,000 
20megawatts or larger and a voltage level of 345 kilovolts or 
21greater, the proposed transmission project shall be deemed to 
22satisfy, and the Commission shall find that it satisfies, the 
23criteria stated in item (1) of subsection (b) of this Section 
24or in paragraph (1) of subsection (f) of Section 8-406.1, as 
25applicable to the application, without the taking of 
26additional evidence on these criteria. Prior to the transfer 
 
 
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1of functional control of any transmission assets to a regional 
2transmission organization, a qualifying direct current 
3applicant shall request Commission approval to join a regional 
4transmission organization in an application filed pursuant to 
5this subsection (b-5) or separately pursuant to Section 7-102 
6of this Act. The Commission may grant permission to a 
7qualifying direct current applicant to join a regional 
8transmission organization if it finds that the membership, and 
9associated transfer of functional control of transmission 
10assets, benefits Illinois customers in light of the attendant 
11costs and is otherwise in the public interest. Nothing in this 
12subsection (b-5) requires a qualifying direct current 
13applicant to join a regional transmission organization. 
14Nothing in this subsection (b-5) requires the owner or 
15operator of a high voltage direct current transmission line 
16that is not a qualifying direct current project to obtain a 
17certificate of public convenience and necessity to the extent 
18it is not otherwise required by this Section 8-406 or any other 
19provision of this Act. 
20    (c) As used in this subsection (c):
21    "Decommissioning" has the meaning given to that term in 
22subsection (a) of Section 8-508.1.
23    "Nuclear power reactor" has the meaning given to that term 
24in Section 8 of the Nuclear Safety Law of 2004. 
25    After the effective date of this amendatory Act of the 
26103rd General Assembly, no construction shall commence on any 
 
 
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1new nuclear power reactor with a nameplate capacity of more 
2than 300 megawatts of electricity to be located within this 
3State, and no certificate of public convenience and necessity 
4or other authorization shall be issued therefor by the 
5Commission, until the Illinois Emergency Management Agency and 
6Office of Homeland Security, in consultation with the Illinois 
7Environmental Protection Agency and the Illinois Department of 
8Natural Resources, finds that the United States Government, 
9through its authorized agency, has identified and approved a 
10demonstrable technology or means for the disposal of high 
11level nuclear waste, or until such construction has been 
12specifically approved by a statute enacted by the General 
13Assembly. Beginning January 1, 2026, construction may commence 
14on a new nuclear power reactor with a nameplate capacity of 300 
15megawatts of electricity or less within this State if the 
16entity constructing the new nuclear power reactor has obtained 
17all permits, licenses, permissions, or approvals governing the 
18construction, operation, and funding of decommissioning of 
19such nuclear power reactors required by: (1) this Act; (2) any 
20rules adopted by the Illinois Emergency Management Agency and 
21Office of Homeland Security under the authority of this Act; 
22(3) any applicable federal statutes, including, but not 
23limited to, the Atomic Energy Act of 1954, the Energy 
24Reorganization Act of 1974, the Low-Level Radioactive Waste 
25Policy Amendments Act of 1985, and the Energy Policy Act of 
261992; (4) any regulations promulgated or enforced by the U.S. 
 
 
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1Nuclear Regulatory Commission, including, but not limited to, 
2those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of 
3the Code of Federal Regulations, as from time to time amended; 
4and (5) any other federal or State statute, rule, or 
5regulation governing the permitting, licensing, operation, or 
6decommissioning of such nuclear power reactors. None of the 
7rules developed by the Illinois Emergency Management Agency 
8and Office of Homeland Security or any other State agency, 
9board, or commission pursuant to this Act shall be construed 
10to supersede the authority of the U.S. Nuclear Regulatory 
11Commission. The changes made by this amendatory Act of the 
12103rd General Assembly shall not apply to the uprate, renewal, 
13or subsequent renewal of any license for an existing nuclear 
14power reactor that began operation prior to the effective date 
15of this amendatory Act of the 103rd General Assembly. 
16    None of the changes made in this amendatory Act of the 
17103rd General Assembly are intended to authorize the 
18construction of nuclear power plants powered by nuclear power 
19reactors that are not either: (1) small modular nuclear 
20reactors; or (2) nuclear power reactors licensed by the U.S. 
21Nuclear Regulatory Commission to operate in this State prior 
22to the effective date of this amendatory Act of the 103rd 
23General Assembly. 
24    (d) In making its determination under subsection (b) of 
25this Section, the Commission shall attach primary weight to 
26the cost or cost savings to the customers of the utility. The 
 
 
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1Commission may consider any or all factors which will or may 
2affect such cost or cost savings, including the public 
3utility's engineering judgment regarding the materials used 
4for construction.
5    (e) The Commission may issue a temporary certificate which 
6shall remain in force not to exceed one year in cases of 
7emergency, to assure maintenance of adequate service or to 
8serve particular customers, without notice or hearing, pending 
9the determination of an application for a certificate, and may 
10by regulation exempt from the requirements of this Section 
11temporary acts or operations for which the issuance of a 
12certificate will not be required in the public interest.
13    A public utility shall not be required to obtain but may 
14apply for and obtain a certificate of public convenience and 
15necessity pursuant to this Section with respect to any matter 
16as to which it has received the authorization or order of the 
17Commission under the Electric Supplier Act, and any such 
18authorization or order granted a public utility by the 
19Commission under that Act shall as between public utilities be 
20deemed to be, and shall have except as provided in that Act the 
21same force and effect as, a certificate of public convenience 
22and necessity issued pursuant to this Section.
23    No electric cooperative shall be made or shall become a 
24party to or shall be entitled to be heard or to otherwise 
25appear or participate in any proceeding initiated under this 
26Section for authorization of power plant construction and as 
 
 
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1to matters as to which a remedy is available under the Electric 
2Supplier Act.
3    (f) Such certificates may be altered or modified by the 
4Commission, upon its own motion or upon application by the 
5person or corporation affected. Unless exercised within a 
6period of 2 years from the grant thereof, authority conferred 
7by a certificate of convenience and necessity issued by the 
8Commission shall be null and void.
9    No certificate of public convenience and necessity shall 
10be construed as granting a monopoly or an exclusive privilege, 
11immunity or franchise.
12    (g) A public utility that undertakes any of the actions 
13described in items (1) through (3) of this subsection (g) or 
14that has obtained approval pursuant to Section 8-406.1 of this 
15Act shall not be required to comply with the requirements of 
16this Section to the extent such requirements otherwise would 
17apply. For purposes of this Section and Section 8-406.1 of 
18this Act, "high voltage electric service line" means an 
19electric line having a design voltage of 100,000 or more. For 
20purposes of this subsection (g), a public utility may do any of 
21the following:
22        (1) replace or upgrade any existing high voltage 
23    electric service line and related facilities, 
24    notwithstanding its length;
25        (2) relocate any existing high voltage electric 
26    service line and related facilities, notwithstanding its 
 
 
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1    length, to accommodate construction or expansion of a 
2    roadway or other transportation infrastructure; or
3        (3) construct a high voltage electric service line and 
4    related facilities that is constructed solely to serve a 
5    single customer's premises or to provide a generator 
6    interconnection to the public utility's transmission 
7    system and that will pass under or over the premises owned 
8    by the customer or generator to be served or under or over 
9    premises for which the customer or generator has secured 
10    the necessary right-of-way right of way. 
11    (h) A public utility seeking to construct a high-voltage 
12electric service line and related facilities (Project) must 
13show that the utility has held a minimum of 2 pre-filing public 
14meetings to receive public comment concerning the Project in 
15each county where the Project is to be located, no earlier than 
166 months prior to filing an application for a certificate of 
17public convenience and necessity from the Commission. Notice 
18of the public meeting shall be published in a newspaper of 
19general circulation within the affected county once a week for 
203 consecutive weeks, beginning no earlier than one month prior 
21to the first public meeting. If the Project traverses 2 
22contiguous counties and where in one county the transmission 
23line mileage and number of landowners over whose property the 
24proposed route traverses is one-fifth or less of the 
25transmission line mileage and number of such landowners of the 
26other county, then the utility may combine the 2 pre-filing 
 
 
10400SB0025ham003- 595 -LRB104 07069 AAS 29208 a

1meetings in the county with the greater transmission line 
2mileage and affected landowners. All other requirements 
3regarding pre-filing meetings shall apply in both counties. 
4Notice of the public meeting, including a description of the 
5Project, must be provided in writing to the clerk of each 
6county where the Project is to be located. A representative of 
7the Commission shall be invited to each pre-filing public 
8meeting.
9    (h-5) A public utility seeking to construct a high-voltage 
10electric service line and related facilities must also show 
11that the Project has complied with training and competence 
12requirements under subsection (b) of Section 15 of the 
13Electric Transmission Systems Construction Standards Act. 
14    (i) For applications filed after August 18, 2015 (the 
15effective date of Public Act 99-399), the Commission shall, by 
16certified mail, notify each owner of record of land, as 
17identified in the records of the relevant county tax assessor, 
18included in the right-of-way over which the utility seeks in 
19its application to construct a high-voltage electric line of 
20the time and place scheduled for the initial hearing on the 
21public utility's application. The utility shall reimburse the 
22Commission for the cost of the postage and supplies incurred 
23for mailing the notice.
24(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21; 
25102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff. 
266-1-24; 103-1066, eff. 2-20-25.)
 
 
 
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1    (220 ILCS 5/8-512)
2    Sec. 8-512. Renewable energy access plan.
3    (a) It is the policy of this State to promote 
4cost-effective transmission system development that ensures 
5reliability of the electric transmission system, lowers carbon 
6emissions, minimizes long-term costs for consumers, and 
7supports the electric policy goals of this State. The General 
8Assembly finds that:
9        (1) Transmission planning, primarily for reliability 
10    purposes, but also for economic and public policy reasons 
11    is conducted by regional transmission organizations in 
12    which transmission-owning Illinois utilities and other 
13    stakeholders are members.
14        (2) Order No. 1000 of the Federal Energy Regulatory 
15    Commission requires regional transmission organizations to 
16    plan for transmission system needs in light of State 
17    public policies and to accept input from states during the 
18    transmission system planning processes.
19        (3) The State of Illinois does not currently have a 
20    comprehensive power and environmental policy planning 
21    process to identify transmission infrastructure needs that 
22    can serve as a vital input into the regional and 
23    interregional transmission organization planning 
24    processes conducted under Order No. 1000 and other laws 
25    and regulations.
 
 
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1        (4) This State is an electricity generation and power 
2    transmission hub, and can leverage that position to invest 
3    in infrastructure that enables new and existing Illinois 
4    generators to meet the public policy goals of the State of 
5    Illinois and of interconnected states while 
6    cost-effectively supporting tens of thousands of jobs in 
7    the renewable energy sector in this State.
8        (5) The nation has a need to readily access this 
9    State's low-cost, clean electric power, and this State 
10    also desires access to clean energy resources in other 
11    states to develop and support its low-carbon economy and 
12    keep electricity prices low in Illinois and interconnected 
13    States.
14        (6) Existing transmission infrastructure may constrain 
15    the State's achievement of 100% renewable energy by 2050, 
16    the accelerated adoption of electric vehicles in a just 
17    and equitable way, and electrification of additional 
18    sectors of the Illinois economy.
19        (7) Transmission system congestion within this State 
20    and the regional transmission organizations serving this 
21    State limits the ability of this State's existing and new 
22    electric generation facilities that do not emit carbon 
23    dioxide, including renewable energy resources and zero 
24    emission facilities, to serve the public policy goals of 
25    this State and other states, which constrains investment 
26    in this State.
 
 
10400SB0025ham003- 598 -LRB104 07069 AAS 29208 a

1        (8) Investment in infrastructure to support existing 
2    and new electric generation facilities that do not emit 
3    carbon dioxide, including renewable energy resources and 
4    zero emission facilities, stimulates significant economic 
5    development and job growth in this State, as well as 
6    creates environmental and public health benefits in this 
7    State.
8        (9) Creating a forward-looking plan for this State's 
9    electric transmission infrastructure, as opposed to 
10    relying on case-by-case development and repeated marginal 
11    upgrades, will achieve a lower-cost system for Illinois' 
12    electricity customers. A forward-looking plan can also 
13    help integrate and achieve a comprehensive set of 
14    objectives and multiple state, regional, and national 
15    policy goals.
16        (10) Alternatives to overhead electric transmission 
17    lines can achieve cost-effective resolution of system 
18    impacts and warrant investigation of the circumstances 
19    under which those alternatives should be considered and 
20    approved. The alternatives are likely to be beneficial as 
21    investment in electric transmission infrastructure moves 
22    forward.
23        (11) Because transmission planning is conducted 
24    primarily by the regional transmission organizations, the 
25    Commission should be advocating for the State's interests 
26    at the regional transmission organizations to ensure that 
 
 
10400SB0025ham003- 599 -LRB104 07069 AAS 29208 a

1    such planning facilitates the State's policies and goals, 
2    including overall consumer savings, power system 
3    reliability, economic development, environmental 
4    improvement, and carbon reduction.
5        (12) Advanced transmission technologies have an 
6    important role to play in meeting the State's clean energy 
7    goals. For the purposes of this Section, "advanced 
8    transmission technology" is hardware or software that 
9    provides cost-effective increases to the capacity, 
10    efficiency, or reliability of existing transmission 
11    infrastructure, and includes, but is not limited to: (i) 
12    technology that dynamically adjusts the rated capacity of 
13    transmission lines based on real-time conditions; (ii) 
14    advanced power flow controls used to actively control the 
15    flow of electricity across transmission lines to optimize 
16    usage or relieve congestion; (iii) software or hardware 
17    used to identify optimal transmission grid configurations 
18    or enable routing power flows around congestion points; 
19    and (iv) advanced transmission line conductors that have a 
20    direct current electrical resistance at least 10% lower 
21    than existing conductors of a similar diameter on the 
22    transmission system.    
23    (b) Consistent with the findings identified in subsection 
24(a), the Commission shall open an investigation to develop and 
25adopt an initial a renewable energy access plan no later than 
26December 31, 2022. To assist and support the Commission in the 
 
 
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1development of the plan, the Commission shall retain the 
2services of technical and policy experts with relevant fields 
3of expertise, solicit technical and policy analysis from the 
4public, and provide for a 120-day open public comment period 
5after publication of a draft report, which shall be published 
6no later than 90 days after the comment period ends. The plan 
7shall, at a minimum, do the following:
8        (1) designate renewable energy access plan zones 
9    throughout this State in areas in which renewable energy 
10    resources and suitable land areas are sufficient for 
11    developing generating capacity from renewable energy 
12    technologies;
13        (2) develop a plan to achieve transmission capacity 
14    necessary to deliver the electric output from renewable 
15    energy technologies in the renewable energy access plan 
16    zones to customers in Illinois and other states in a 
17    manner that is most beneficial and cost-effective to 
18    customers;
19        (3) use this State's position as an electricity 
20    generation and power transmission hub to create new 
21    investment in this State's renewable energy resources;
22        (4) consider programs, policies, and electric 
23    transmission projects that can be adopted within this 
24    State that promote the cost-effective delivery of power 
25    from renewable energy resources interconnected to the bulk 
26    electric system to meet the renewable portfolio standard 
 
 
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1    targets under subsection (c) of Section 1-75 of the 
2    Illinois Power Agency Act;
3        (5) consider proposals to improve regional 
4    transmission organizations' regional and interregional 
5    system planning processes, especially proposals that 
6    reduce costs and emissions, create jobs, and increase 
7    State and regional power system reliability to prevent 
8    high-cost outages that can endanger lives, and analyze of 
9    how those proposals would improve reliability and 
10    cost-effective delivery of electricity in Illinois and the 
11    region;
12        (6) make findings and policy recommendations based on 
13    technical and policy analysis regarding locations of 
14    renewable energy access plan zones and the transmission 
15    system developments needed to cost-effectively achieve the 
16    public policy goals identified herein;
17        (6.5) make findings and policy recommendations based 
18    on analysis regarding the impact of converting non-powered 
19    dams to hydropower dams relative to the alternative 
20    renewable energy resources; and 
21        (7) present the Commission's conclusions and proposed 
22    recommendations based on its analysis and use the findings 
23    and policy recommendations to determine actions that the 
24    Commission should take.
25    (c) No later than December 31, 2025 or 180 days after the 
26effective date of this amendatory Act of the 104th General 
 
 
10400SB0025ham003- 602 -LRB104 07069 AAS 29208 a

1Assembly, whichever is later, and every other year thereafter, 
2the Commission shall open an investigation to develop and 
3adopt a an updated renewable energy access plan update that 
4considers electric transmission projects, transmission 
5policies, transmission alternatives, advanced transmission 
6technologies, other ways to expand capacity on existing or 
7future transmission, and transmission headroom and, at a 
8minimum, : evaluates the implementation and effectiveness of 
9the renewable energy access plan, recommends improvements to 
10the renewable energy access plan, and provides changes to 
11transmission capacity necessary to deliver electric output 
12from the renewable energy access plan zones.
13        (1) evaluates the implementation and effectiveness of 
14    the renewable energy access plan;
15        (2) recommends improvements to the renewable energy 
16    access plan;
17        (3) includes updated inputs and assumptions developed 
18    under the integrated resource plan developed and approved 
19    pursuant to Section 16-201 and Section 16-202;
20        (4) requests utilities and other parties to 
21    specifically identify all elements of the existing 
22    transmission system where advanced transmission 
23    technologies are likely to achieve enhanced system 
24    resilience or reliability, reduce potential siting 
25    conflicts or land impacts from the development of new 
26    transmission lines, promote the cost-effective delivery of 
 
 
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1    power from renewable energy resources interconnected to 
2    the bulk electric system, enable the interconnection of 
3    renewable energy resources, or reduce curtailment of 
4    renewable energy resources. The plan must identify all 
5    elements of the existing transmission system which have 
6    experienced capacity constraints or congestion within the 
7    prior 2 years and explain whether any advanced 
8    transmission technology could reduce or resolve the 
9    capacity constraint or congestion;
10        (5) includes an evaluation of identified and proposed 
11    transmission projects, including proposed advanced 
12    transmission technology projects, based on independent 
13    analysis of costs and benefits, including customer bill 
14    impacts over the life of the project and achievement of 
15    State clean energy goals. Projects shall be evaluated in 
16    coordination with other proposals, and may include a 
17    combined evaluation of portfolios of projects;
18        (6) develops a recommended list of transmission 
19    projects and advanced transmission technology projects 
20    that achieve the clean energy public policy objectives of 
21    the State. Nothing in this Section shall limit the 
22    recommended list of transmission projects to those 
23    initially proposed. However, no transmission or advanced 
24    transmission technology project can be included in the 
25    recommended list unless evaluated; and
26        (7) considers additional mechanisms designed to 
 
 
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1    capture the potential value of geographically diverse 
2    resources that proposed interregional transmission 
3    projects may provide.    
4    The Commission may evaluate options for implementation of 
5the recommended list of transmission projects and advanced 
6transmission technology projects that achieve the clean energy 
7public policy objectives of the State, including through the 
8use of a state agreement approach or a similar structure made 
9available through the relevant regional transmission 
10organizations, and approves final recommendations on 
11implementation.
12    The Commission may invite parties to identify transmission 
13projects, including any associated network upgrades, necessary 
14to facilitate achievement of the goals of the plan and the most 
15recently approved integrated resource plan. Proposals for 
16projects shall include a description of each project; a 
17proposed target date for completion; an estimated timeline for 
18development; the energy, capacity, and generation profile of 
19renewable generation and energy storage enabled by the 
20project; anticipated new loads served by the project; the 
21proposed technology used, including the use of any advanced 
22transmission technologies; and the status of any permits or 
23approvals necessary. For projects with a target completion 
24date of within 5 years from the date of proposal, the proposal 
25must also include an estimated cost of the project and the 
26proposed routing corridor. The Commission shall aim to 
 
 
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1complete the updated plan investigation within 12 months of 
2opening.
3    (d) Each transmission-owning State utility serving more 
4than 200,000 customers in this State may prepare a plan for 
5integrating advanced transmission technologies into the 
6utility's existing transmission system. The plan must identify 
7all elements of the existing transmission system where 
8advanced transmission technologies are likely to achieve any 
9of the following purposes:
10        (1) enhance system resilience or reliability;
11        (2) reduce potential siting conflicts or land impacts 
12    from the development of new transmission lines;
13        (3) promote the cost-effective delivery of power from 
14    renewable energy resources interconnected to the bulk 
15    electric system to meet the renewable portfolio standard 
16    targets under subsection (c) of Section 1-75 of the 
17    Illinois Power Agency Act;
18        (4) enable the interconnection of renewable energy 
19    resources to meet the renewable portfolio standard targets 
20    under subsection (c) of Section 1-75 of the Illinois Power 
21    Agency Act; or
22        (5) reduce curtailment of renewable or zero-carbon 
23    resources.
24    The plan must identify all elements of the existing 
25transmission system which have experienced capacity 
26constraints or congestion within the prior 2 years and explain 
 
 
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1whether any advanced transmission technology could reduce or 
2resolve the capacity constraint or congestion. Each 
3transmission-owning State utility may submit an advanced 
4transmission technology integration plan to the Commission for 
5consideration as part of the Commission's updated renewable 
6energy access plan investigation under subsection (c). In the 
7Commission's updated renewable energy access plan, the 
8Commission may evaluate, request modifications for, change the 
9timelines of implementation for, and determine the next steps 
10for each advanced transmission integration plan.
11    (e) Each transmission-owning State utility serving more 
12than 200,000 customers in this State may conduct a 
13comprehensive Transmission Headroom Study that shall identify, 
14at a minimum, the points of interconnection with unused, 
15existing transmission headroom on the State system, including 
16available capacity behind existing, underutilized points of 
17interconnection, and the amount of available headroom in 
18megawatts at each identified point of interconnection. Each 
19transmission-owning State utility may submit a Transmission 
20Headroom Study to the Commission for consideration as part of 
21the Commission's updated renewable energy access plan 
22investigation under subsection (c).
23    (f) The Commission shall approve an updated renewable 
24energy access plan if it finds that, at a minimum, the evidence 
25in the investigation meets the criteria outlined in subsection 
26(c) and demonstrates that the updated plan will support the 
 
 
10400SB0025ham003- 607 -LRB104 07069 AAS 29208 a

1clean energy public policy objectives of the State.    
2    (g) The Commission shall notify the applicable regional 
3transmission organizations and utilities of any final 
4recommendations to support the clean energy public policy 
5objectives of the State.
6    (h) Nothing in this Section alters the rights of 
7transmission utilities (i) under rates on file with the 
8Federal Energy Regulatory Commission or the Illinois Commerce 
9Commission, (ii) under orders and determinations of the 
10Federal Energy Regulatory Commission or a regional 
11transmission organization, or (iii) under applicable State 
12laws and policies.
13(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
 
14    (220 ILCS 5/8-513 new)
15    Sec. 8-513. Thermal Energy Network Pilot Program.
16    (a) The Commission shall coordinate with the Illinois 
17Finance Authority, in its role as Climate Bank for the State, 
18to leverage any available federal funding to support thermal 
19energy network pilot projects through the provision of grants 
20or to provide or leverage financing. If that federal funding 
21is not available or not sufficient to meet program objectives, 
22the Commission shall authorize the allocation of up to 
23$20,000,000 to support the thermal energy network pilot 
24projects, to be provided to the Illinois Finance Authority to 
25distribute to projects as a grant or to provide or leverage 
 
 
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1financing. The Illinois Finance Authority shall submit 
2projects that have already been approved by the Illinois 
3Finance Authority to the Commission for review and approval in 
4a form and manner determined by the Commission. The Commission 
5shall approve projects that it deems to be just, reasonable, 
6and in the public interest. Any allocation of funding shall 
7provide for the Illinois Finance Authority to use a portion of 
8such allocated funds to support its reasonable administrative 
9costs in administering the program under this Section.
10    (b) An electric utility shall be entitled to recover, 
11through tariffed charges approved by the Commission, all of 
12the costs associated with projects authorized for funding by 
13the Commission pursuant to this Section and shall be recovered 
14as part of the utility's costs incurred under Section 45 of the 
15Electric Vehicle Act. If any authorized funds have not been 
16recovered by the utility as of January 1, 2029, the 
17Environmental Protection Agency shall allocate the remaining 
18funds to the Illinois Finance Authority as part of its 
19beneficial electrification programs described in Section 45 of 
20the Electric Vehicle Act.    
21    (c) As part of any pilot project proposed pursuant to this 
22Section, the Commission is authorized to approve any specific 
23customer rebates and incentives and any project-specific 
24tariffs and rules. The Commission may create a standard 
25proposed rate structure or minimum requirements for a rate 
26structure to be required of all thermal energy network pilot 
 
 
10400SB0025ham003- 609 -LRB104 07069 AAS 29208 a

1projects. The Commission may approve the proposed rate 
2structure of a thermal energy network pilot project if the 
3projected heating and cooling costs for end users is not 
4greater than the projected heating and cooling costs the end 
5users would have incurred if the end users had not 
6participated in the program. In its approval process, the 
7Commission shall take into account scenarios where pilot 
8projects enhance comfort and safety for customers through 
9expanded access to affordable heating and cooling.
10    (d) Approved thermal energy network pilot projects shall 
11report to the Commission, on a quarterly basis and until 
12completion of the thermal energy network pilot project, the 
13status of each thermal energy network pilot project. The 
14Commission shall post and make publicly available the reports 
15on its website. The reports shall include, but not be limited 
16to:
17        (1) the stage of development of each pilot project;
18        (2) the barriers to development;
19        (3) the number of customers served;
20        (4) the costs of the pilot project;
21        (5) the number of jobs retained or created by the 
22    pilot project;
23        (6) energy savings and fuel savings from the project 
24    and energy consumption by the project; and
25        (7) other information the Commission deems to be in 
26    the public interest or considers likely to prove useful or 
 
 
10400SB0025ham003- 610 -LRB104 07069 AAS 29208 a

1    relevant to the rulemaking described in subsection (i).
2    (e) Any entity operating a Commission-approved thermal 
3energy network pilot project shall demonstrate that it has 
4entered into a labor peace agreement with a bona fide labor 
5organization that is actively engaged in representing its 
6employees. The labor peace agreement shall apply to the 
7employees necessary for the ongoing maintenance and operation 
8of the thermal energy network. The existence of a labor peace 
9agreement shall be an ongoing material condition of an 
10entity's authorization to maintain and operate the thermal 
11energy networks.
12    (f) Any contractor or subcontractor that performs work on 
13a thermal energy network pilot project under this Section 
14shall be a responsible bidder, as described in Section 30-22 
15of the Illinois Procurement Code, and shall certify that not 
16less than prevailing wage, as determined under the Prevailing 
17Wage Act, was or will be paid to the employees who are engaged 
18in construction activities associated with the pilot thermal 
19energy network system. The contractor or subcontractor shall 
20submit evidence to the Commission that it complied with the 
21requirements of this subsection (f). For any approved thermal 
22energy network pilot project, the contractor or subcontractor 
23shall submit evidence that the contractor or subcontractor has 
24entered into a fully executed project labor agreement for the 
25thermal energy network system prior to the initiation of 
26construction activities.
 
 
 
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1    (220 ILCS 5/9-229)
2    Sec. 9-229. Consideration of attorney and expert 
3compensation as an expense and intervenor compensation fund. 
4    (a) The Commission shall specifically assess the justness 
5and reasonableness of any amount expended by a public utility 
6to compensate attorneys or technical experts to prepare and 
7litigate a general rate case filing. This issue shall be 
8expressly addressed in the Commission's final order.
9    (b) The State of Illinois shall create a Consumer 
10Intervenor Compensation Fund subject to the following:
11        (1) Provision of compensation for consumer interest 
12    representatives Consumer Interest Representatives that 
13    intervene in Illinois Commerce Commission proceedings will 
14    increase public engagement, encourage additional 
15    transparency, expand the information available to the 
16    Commission, and improve decision-making.
17        (2) As used in this Section, "consumer Consumer    
18    interest representative" means:
19            (A) a residential utility customer or group of 
20        residential utility customers represented by a 
21        not-for-profit group or organization registered with 
22        the Illinois Attorney General under the Solicitation 
23        for Charity Act;
24            (B) representatives of not-for-profit groups or 
25        organizations whose membership is limited to 
 
 
10400SB0025ham003- 612 -LRB104 07069 AAS 29208 a

1        residential utility customers; or
2            (C) representatives of not-for-profit groups or 
3        organizations whose membership includes Illinois 
4        residents and that address the community, economic, 
5        environmental, or social welfare of Illinois 
6        residents, except government agencies or intervenors    
7        specifically authorized by Illinois law to participate 
8        in Commission proceedings on behalf of Illinois 
9        consumers.
10        (3) A consumer interest representative is eligible to 
11    receive compensation from the Consumer Intervenor 
12    Compensation Fund consumer intervenor compensation fund if 
13    its participation included lay or expert testimony or 
14    legal briefing and argument concerning the expenses, 
15    investments, rate design, rate impact, development of an 
16    integrated resource plan pursuant to Section 16-201 and 
17    any related proceedings, or other matters affecting the 
18    pricing, rates, costs or other charges associated with 
19    utility service and , the Commission does not find the 
20    participation to be immaterial adopts a material 
21    recommendation related to a significant issue in the 
22    docket, and participation caused a significant financial 
23    hardship to the participant; however, no consumer interest 
24    representative shall be eligible to receive an award 
25    pursuant to this Section if the consumer interest 
26    representative receives any compensation, funding, or 
 
 
10400SB0025ham003- 613 -LRB104 07069 AAS 29208 a

1    donations, directly or indirectly, from parties that have 
2    a financial interest in the outcome of the proceeding. 
3    Funding from residential ratepayers shall not be 
4    considered funding from a party with a financial interest 
5    unless determined to be by the Commission. The Commission 
6    shall determine participation by the consumer interest 
7    representative to be material if recommendations made by 
8    the consumer interest representative are:
9            (A) relevant to issues in the proceeding on which 
10        the Commission makes a finding;
11            (B) supported by facts, such as studies, methods, 
12        or calculations, or by legal or policy analysis; and
13            (C) offered by the consumer interest 
14        representative into evidence in the record of that 
15        proceeding, or for legal or policy analysis, are filed 
16        in the docket of that proceeding, through briefing, 
17        motion, or other method.    
18        (4) Within 30 days after September 15, 2021 (the 
19    effective date of Public Act 102-662), each utility that 
20    files a request for an increase in rates under Article IX 
21    or Article XVI shall deposit an amount equal to one half of 
22    the rate case attorney and expert expense allowed by the 
23    Commission, but not to exceed $500,000, into the fund 
24    within 35 days of the date of the Commission's final Order 
25    in the rate case or 20 days after the denial of rehearing 
26    under Section 10-113 of this Act, whichever is later. The 
 
 
10400SB0025ham003- 614 -LRB104 07069 AAS 29208 a

1    Consumer Intervenor Compensation Fund shall be used to 
2    provide payment to consumer interest representatives as 
3    described in this Section.
4        (5) An electric public utility with 3,000,000 or more 
5    retail customers shall contribute $450,000 to the Consumer 
6    Intervenor Compensation Fund within 60 days after 
7    September 15, 2021 (the effective date of Public Act 
8    102-662). A combined electric and gas public utility 
9    serving fewer than 3,000,000 but more than 500,000 retail 
10    customers shall contribute $225,000 to the Consumer 
11    Intervenor Compensation Fund within 60 days after 
12    September 15, 2021 (the effective date of Public Act 
13    102-662). A gas public utility with 1,500,000 or more 
14    retail customers that is not a combined electric and gas 
15    public utility shall contribute $225,000 to the Consumer 
16    Intervenor Compensation Fund within 60 days after 
17    September 15, 2021 (the effective date of Public Act 
18    102-662). A gas public utility with fewer than 1,500,000 
19    retail customers but more than 300,000 retail customers 
20    that is not a combined electric and gas public utility 
21    shall contribute $80,000 to the Consumer Intervenor 
22    Compensation Fund within 60 days after September 15, 2021 
23    (the effective date of Public Act 102-662). A gas public 
24    utility with fewer than 300,000 retail customers that is 
25    not a combined electric and gas public utility shall 
26    contribute $20,000 to the Consumer Intervenor Compensation 
 
 
10400SB0025ham003- 615 -LRB104 07069 AAS 29208 a

1    Fund within 60 days after September 15, 2021 (the 
2    effective date of Public Act 102-662). A combined electric 
3    and gas public utility serving fewer than 500,000 retail 
4    customers shall contribute $20,000 to the Consumer 
5    Intervenor Compensation Fund within 60 days after 
6    September 15, 2021 (the effective date of Public Act 
7    102-662). A water or sewer public utility serving more 
8    than 100,000 retail customers shall contribute $80,000, 
9    and a water or sewer public utility serving fewer than 
10    100,000 but more than 10,000 retail customers shall 
11    contribute $20,000.
12        (6)(A) Prior to the entry of a final order Final Order    
13    in a docketed case, the Commission Administrator shall 
14    provide a payment to a consumer interest representative 
15    that demonstrates through a verified application for 
16    funding that the consumer interest representative's 
17    participation or intervention without an award of fees or 
18    costs imposes a significant financial cost for the 
19    consumer interest representative hardship based on a 
20    schedule to be developed by the Commission. The 
21    Administrator may require verification of costs expected 
22    to be incurred, including statements of expected hours 
23    spent, as a condition to paying the consumer interest 
24    representative prior to the entry of a final order Final 
25    Order in a docketed case. The upfront payment prior to the 
26    entry of a final order in the relevant docketed case shall 
 
 
10400SB0025ham003- 616 -LRB104 07069 AAS 29208 a

1    be subject to the reconciliation process described in 
2    subparagraph (C) of this paragraph. For purposes of 
3    upfront payments provided for under this subparagraph, and 
4    provided the testimony or legal argument was offered into 
5    evidence or filed in the docket, a decision by the 
6    Commission prior to entry of a final order that a consumer 
7    interest representative's evidence or legal argument is 
8    relevant to issues in the proceeding under subparagraph 
9    (A) of paragraph (3) shall not be subject to 
10    reconsideration. Any compensation awarded shall be subject 
11    to review and reconciliation under subparagraph (C) of 
12    this paragraph. Payments made after the issuance of a 
13    final order in the relevant docketed case do not require 
14    the reconciliation.    
15        (B) If the Commission does not find the participation 
16    to be immaterial adopts a material recommendation related 
17    to a significant issue in the docket and participation 
18    caused a financial hardship to the participant, then the 
19    consumer interest representative shall be allowed payment 
20    for some or all of the consumer interest representative's 
21    reasonable attorney's or advocate's fees, reasonable 
22    expert witness fees, and other reasonable costs of 
23    preparation for and participation in a hearing or 
24    proceeding. Expenses related to travel or meals shall not 
25    be compensable. Expenses incurred by participation in 
26    workshops or other informal processes outside a docketed 
 
 
10400SB0025ham003- 617 -LRB104 07069 AAS 29208 a

1    proceeding shall not be compensable. Attorneys and expert 
2    witnesses who represent or testify for more than one party 
3    in the same docketed proceeding and perform essentially 
4    the same work on behalf of the parties shall not be 
5    compensated more than once for those same services 
6    rendered in that proceeding.    
7        (C) The consumer interest representative shall submit 
8    an itemized request for compensation to the Consumer 
9    Intervenor Compensation Fund, including the advocate's or 
10    attorney's reasonable fee rate, the number of hours 
11    expended, reasonable expert and expert witness fees, and 
12    other reasonable costs for the preparation for and 
13    participation in the hearing and briefing within 30 days 
14    after of the Commission's final order or the Commission's    
15    after denial or decision on rehearing, if any, whichever 
16    is later. If compensation is provided prior to the entry 
17    of a final order in a docketed case, such compensation 
18    shall be adjusted following the final order to reconcile 
19    the difference between actual eligible expenses incurred 
20    and the amount of compensation provided prior to the entry 
21    of the final order. The reconciliation adjustment shall 
22    ensure that the total compensation awarded to the 
23    applicant is no more and no less than the actual eligible 
24    expenses incurred. Payments made after the issuance of a 
25    final order in the relevant docketed case do not require 
26    the reconciliation.    
 
 
10400SB0025ham003- 618 -LRB104 07069 AAS 29208 a

1        (7) Administration of the Fund.
2        (A) The Consumer Intervenor Compensation Fund is 
3    created as a special fund in the State treasury. All 
4    disbursements from the Consumer Intervenor Compensation 
5    Fund shall be made only upon warrants of the Comptroller 
6    drawn upon the Treasurer as custodian of the Fund upon 
7    vouchers signed by the Executive Director of the 
8    Commission or by the person or persons designated by the 
9    Director for that purpose. The Comptroller is authorized 
10    to draw the warrant upon vouchers so signed. The Treasurer 
11    shall accept all warrants so signed and shall be released 
12    from liability for all payments made on those warrants. 
13    The Consumer Intervenor Compensation Fund shall be 
14    administered by an Administrator that is a person or 
15    entity that is independent of the Commission. The 
16    administrator will be responsible for the prudent 
17    management of the Consumer Intervenor Compensation Fund 
18    and for recommendations for the award of consumer 
19    intervenor compensation from the Consumer Intervenor 
20    Compensation Fund. The Commission shall issue a request 
21    for qualifications for a third-party program administrator 
22    to administer the Consumer Intervenor Compensation Fund. 
23    The third-party administrator shall be chosen through a 
24    competitive bid process based on selection criteria and 
25    requirements developed by the Commission. The Illinois 
26    Procurement Code does not apply to the hiring or payment 
 
 
10400SB0025ham003- 619 -LRB104 07069 AAS 29208 a

1    of the Administrator. All Administrator costs may be paid 
2    for using monies from the Consumer Intervenor Compensation 
3    Fund, but the Program Administrator shall strive to 
4    minimize costs in the implementation of the program.
5        (B) The computation of compensation awarded from the 
6    fund shall take into consideration the market rates paid 
7    to persons of comparable training and experience who offer 
8    similar services, but may not exceed the comparable market 
9    rate for services paid by the public utility as part of its 
10    rate case expense.
11        (C)(1) Recommendations on the award of compensation by 
12    the administrator shall include consideration of whether 
13    the participation was material Commission adopted a 
14    material recommendation related to a significant issue in 
15    the docket and whether participation caused a financial 
16    hardship to the participant and the payment of 
17    compensation is fair, just and reasonable.
18        (2) Recommendations on the award of compensation by 
19    the administrator shall be submitted to the Commission for 
20    approval within 30 days after when the application for 
21    funding is submitted to the administrator. Unless the 
22    Commission initiates an investigation within 60 45 days 
23    after an application for funding is submitted to the 
24    administrator, the Commission shall within 90 days after 
25    the application is submitted to the administrator, or as 
26    soon as practicable thereafter, award funding to the 
 
 
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1    applicant. Notice of the administrator's award 
2    recommendation the notice to the Commission, the award of 
3    compensation shall be allowed 45 days after notice to the 
4    Commission. Such notice shall be given by filing with the 
5    Commission on the Commission's e-docket system, and 
6    keeping open for public inspection the award for 
7    compensation proposed by the Administrator. The Commission 
8    shall have power, and it is hereby given authority, either 
9    upon complaint or upon its own initiative without 
10    complaint, at once, and if it so orders, without answer or 
11    other formal pleadings, but upon reasonable notice, to 
12    enter upon a hearing concerning the propriety of the 
13    award.
14        (3) A consumer interest representative who performed 
15    work or otherwise incurred expenses in an eligible 
16    proceeding before the Commission prior to the effective 
17    date of this amendatory Act of the 104th General Assembly 
18    and after September 15, 2021 (the effective date of Public 
19    Act 102-662) and who, due to a denied application or 
20    otherwise, was not awarded compensation for the entirety 
21    of the incurred expenses from the Consumer Intervenor 
22    Compensation Fund may seek compensation from the Consumer 
23    Intervenor Compensation Fund pursuant to this Section. 
24    Nothing in this Section shall prohibit retroactive awards 
25    to eligible participants for work performed or expenses 
26    incurred in eligible proceedings prior to the effective 
 
 
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1    date of this amendatory Act of the 104th General Assembly 
2    and after September 15, 2021 (the effective date of Public 
3    Act 102-662). The retroactive awards shall not include 
4    additional costs directly or indirectly incurred due to 
5    the prior denial of an application for an eligible 
6    proceeding. Applications for a retroactive award shall be 
7    subject to the revised eligibility standards enacted 
8    pursuant to this amendatory Act of the 104th General 
9    Assembly. The applications may be submitted at any time 
10    within one calendar year after the effective date of this 
11    amendatory Act of the 104th General Assembly.    
12    (c) The Commission may adopt rules to implement this 
13Section.
14(Source: P.A. 102-662, eff. 9-15-21; 103-605, eff. 7-1-24.)
 
15    (220 ILCS 5/16-105.17)
16    Sec. 16-105.17. Multi-Year Integrated Grid Plan.
17    (a) The General Assembly finds that ensuring alignment of 
18regulated utility operations, expenditures, and investments 
19with public benefit goals, including safety, reliability, 
20resiliency, affordability, equity, emissions reductions, and 
21expansion of clean distributed energy resources, is critical 
22to maximizing the benefits of the interconnected utility grid 
23and cost-effective utility expenditures on the grid. It is the 
24policy of the State to promote inclusive, comprehensive, 
25transparent, cost-effective distribution system planning and 
 
 
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1disclosures processes that minimize long-term costs for 
2Illinois customers and support the achievement of State 
3renewable energy development and other clean energy, public 
4health, and environmental policy goals. Utility distribution 
5system expenditures, programs, investments, and policies must 
6be evaluated in coordination with these goals. In particular, 
7the General Assembly finds that:
8        (1) Investment in infrastructure to support and enable 
9    existing and new distributed energy resources creates 
10    significant economic development, environmental, and 
11    public health benefits in the State.
12        (2) Illinois' electricity distribution system must 
13    cost-effectively integrate renewable energy resources, 
14    including utility-scale renewable energy resources, 
15    community renewable generation, and distributed renewable 
16    energy resources, support beneficial electrification, 
17    including electric vehicle use and adoption, promote 
18    opportunities for third-party investment in 
19    nontraditional, grid-related technologies and resources 
20    such as batteries, solar photovoltaic panels, and smart 
21    thermostats, reduce energy usage generally and especially 
22    during times of greatest reliance on fossil fuels, and 
23    enhance customer engagement opportunities.
24        (3) Inclusive distribution system planning is an 
25    essential tool for the Commission, public utilities, and 
26    stakeholders to effectively coordinate environmental, 
 
 
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1    consumer, reliability, and equity goals at fair and 
2    reasonable costs, and for ensuring transparent utility 
3    accountability for meeting those goals.
4        (4) Any planning process should advance Illinois 
5    energy policy goals while ensuring utility investments are 
6    cost-effective. Such a process should maximize the sharing 
7    of information, minimize overlap with existing filing 
8    requirements to ensure robust stakeholder participation, 
9    and recognize the responsibility of the utility to manage 
10    the grid in a safe, reliable manner.
11        (5) The General Assembly is concerned that, in the 
12    absence of a transparent, meaningful distribution system 
13    planning process, utility investments may not always serve 
14    customers' best interests, appropriately promote the 
15    expansion of clean distributed energy resources, and 
16    advance equity and environmental justice.
17        (6) The General Assembly is also encouraged by the 
18    opportunities presented by nontraditional solutions to 
19    utility, customer, and grid needs that may be more 
20    efficient and cost-effective, and less environmentally 
21    harmful than traditional solutions. Nontraditional 
22    solutions include distributed energy resources owned or 
23    implemented by customers and independent third parties, 
24    controllable load, beneficial electrification, or rate 
25    design that encourages efficient energy use.
26        (7) The General Assembly finds that Illinois 
 
 
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1    utilities' current processes for planning their 
2    distribution system should be made more accessible and 
3    transparent to individuals and communities, and that more 
4    inclusive and accessible distribution system planning 
5    processes would be in the interests of all Illinois 
6    residents.
7        (8) The General Assembly finds it would be beneficial 
8    to require utilities to demonstrate how their spending 
9    promotes identified State clean energy goals, such as 
10    integrating renewable energy, empowering customers to make 
11    informed choices, supporting electric vehicles, beneficial 
12    electrification, and energy storage, achieving equity 
13    goals, enhancing resilience, and maintaining reliability.
14    The General Assembly therefore directs the utilities to 
15implement distribution system planning as described in this 
16Section in order to accelerate progress on Illinois clean 
17energy and environmental goals and hold electric utilities 
18publicly accountable for their performance.
19    (b) Unless otherwise specified, the terms used in this 
20Section shall have the same meanings as defined in Sections 
2116-102 and 16-107.6. As used in this Section:
22    "Demand response" means measures that decrease peak 
23electricity demand or shift demand from peak to off-peak 
24periods.
25    "Distributed energy resources" or "DER" means a wide range 
26of technologies that are connected to the grid, including 
 
 
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1those that are located on the customer side of the customer's 
2electric meter and can provide value to the distribution 
3system, including, but not limited to, distributed generation, 
4energy storage, electric vehicles, and demand response 
5technologies.
6    "Environmental justice communities" means the definition 
7of that term based on existing methodologies and findings, 
8used and as may be updated by the Illinois Power Agency and its 
9Program Administrator in the Illinois Solar for All Program.
10    (c) This Section applies to electric utilities serving 
11more than 500,000 retail customers in the State.
12    (d) The Multi-Year Integrated Grid Plan ("the Plan") shall 
13be designed to:
14        (1) ensure coordination of the State's renewable 
15    energy goals, climate and environmental goals with the 
16    utility's distribution system investments, and programs 
17    and policies over a 5-year planning horizon to maximize 
18    the benefits of each while ensuring utility expenditures 
19    are cost-effective;
20        (2) optimize utilization of electricity grid assets 
21    and resources to minimize total system costs;
22        (3) support efforts to bring the benefits of grid 
23    modernization and clean energy, including, but not limited 
24    to, deployment of distributed energy resources, to all 
25    retail customers, and support efforts to bring at least 
26    40% of the benefits of those benefits to Equity Investment 
 
 
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1    Eligible Communities. Nothing in this paragraph is meant 
2    to require a specific amount of spending in a particular 
3    geographic area;
4        (4) enable greater customer engagement, empowerment, 
5    and options for energy services;
6        (5) reduce grid congestion, minimize the time and 
7    expense associated with interconnection, and increase the 
8    capacity of the distribution grid to host increasing 
9    levels of distributed energy resources, to facilitate 
10    availability and development of distributed energy 
11    resources, particularly in locations that enhance consumer 
12    and environmental benefits;
13        (6) ensure opportunities for robust public 
14    participation through open, transparent planning 
15    processes.
16        (7) provide for the analysis of the cost-effectiveness 
17    of proposed system investments, which takes into account 
18    environmental costs and benefits;
19        (8) to the maximum extent practicable, achieve or 
20    support the achievement of Illinois environmental goals, 
21    including those described in Section 9.10 of the 
22    Environmental Protection Act and Section 1-75 of the 
23    Illinois Power Agency Act, and emissions reductions 
24    required to improve the health, safety, and prosperity of 
25    all Illinois residents;
26        (9) support existing Illinois policy goals promoting 
 
 
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1    the long-term growth of energy efficiency, demand 
2    response, and investments in renewable energy resources;
3        (10) provide sufficient public information to the 
4    Commission, stakeholders, and market participants in order 
5    to enable nonemitting customer-owned or third-party 
6    distributed energy resources, acting individually or in 
7    aggregate, to seamlessly and easily connect to the grid, 
8    provide grid benefits, support grid services, and achieve 
9    environmental outcomes, without necessarily requiring 
10    utility ownership or controlling interest over those 
11    resources, and enable those resources to act as 
12    alternatives to utility capital investments; and
13        (11) provide delivery services at rates that are 
14    affordable to all customers, including low-income 
15    customers.
16    (e) Plan Development Stakeholder Process.
17        (1) To promote the transparency of utility 
18    distributions system planned investments and the planning 
19    process for those investments, the Commission shall 
20    convene a workshop process, over a period of no less than 5 
21    months, for each such utility for the purpose of 
22    establishing an open, inclusive, and cooperative forum 
23    regarding such investments. The workshops shall be 
24    facilitated by an independent, third-party facilitator 
25    selected by the Commission. Data and projections provided 
26    through the workshop process shall be designed to provide 
 
 
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1    participants with information about the electric utility's 
2    (i) historic distribution system investments for at least 
3    the 5 years prior to the year in which the workshop is held 
4    and (ii) planned investments for the 5-year period 
5    following the year in which the workshop is held. The 
6    workshop process shall recognize that estimates for later 
7    years will be less reliable and indicative of future 
8    conduct than estimates for earlier years and that the 
9    electric utility is subject to financial and system 
10    planning processes. No later than January 1, 2022, the 
11    facilitator shall initiate a series of workshops for each 
12    electric utility subject to this Section. The series of 
13    workshops shall include no fewer than 6 workshops and 
14    shall conclude no later than June 1, 2022.
15        (2) The workshops shall be designed to achieve the 
16    following objectives:
17            (A) review utilities' planned capital investments 
18        and supporting data;
19            (B) review how utilities plan to invest in their 
20        distribution system in order to meet the system's 
21        projected needs;
22            (C) review system and locational data on 
23        reliability, resiliency, DER, and service quality 
24        provided by the utilities;
25            (D) solicit and consider input from diverse 
26        stakeholders, including representatives from 
 
 
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1        environmental justice communities, geographically 
2        diverse communities, low-income representatives, 
3        consumer representatives, environmental 
4        representatives, organized labor representatives, 
5        third-party technology providers, and utilities;
6            (E) consider proposals from utilities and 
7        stakeholders on programs and policies necessary to 
8        achieve the objectives in subsection (d) of this 
9        Section;
10            (F) consider proposals applicable to each 
11        component of the utilities' Multi-Year Integrated Grid 
12        Plan filings under paragraph (2) of subsection (f) of 
13        this Section;
14            (G) educate and equip interested stakeholders so 
15        that they can effectively and efficiently provide 
16        feedback and input to the electric utility; and
17            (H) review planned capital investment to ensure 
18        that delivery services are provided at rates that are 
19        affordable to all customers, including low-income 
20        customers.
21        (3) To the extent any of the information in 
22    subparagraphs (A) through (H) of paragraph (2) of this 
23    subsection is designated as confidential and proprietary 
24    under the Commission's rules, the proponent of the 
25    designation shall have the burden of making the requisite 
26    showing under the Commission's rules. For data that is 
 
 
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1    determined to be confidential or that includes personally 
2    identifiable information, the Commission may develop 
3    procedures and processes to enable data sharing with 
4    parties and stakeholders while ensuring the 
5    confidentiality of the information.
6        (4) Workshops should be organized and facilitated in a 
7    manner that encourages representation from diverse 
8    stakeholders, ensuring equitable opportunities for 
9    participation, without requiring formal intervention or 
10    representation by an attorney. Workshops should be held 
11    during both day and evening hours, in a variety of 
12    locations within each electric utility's service 
13    territory, and should allow remote participation.
14        (5) It is a goal of the State that this workshop 
15    process will provide a forum for interested stakeholders 
16    to effectively and efficiently provide feedback and input 
17    to the electric utility. It is also a goal of the State 
18    that stakeholder participation in this process will 
19    prepare stakeholders to more capably participate in 
20    Multi-Year Rate Plan proceedings conducted pursuant to 
21    Section 16-108.18 of this Act, if they so elect. As part of 
22    the workshop process, the electric utility shall submit to 
23    the Commission the electric utility's capital investments 
24    proposal, and supporting data described in subparagraphs 
25    (A) through (C) of paragraph (2) of this subsection (e) 
26    before the start of workshops to allow interested 
 
 
10400SB0025ham003- 631 -LRB104 07069 AAS 29208 a

1    stakeholders to reasonably review data before attending 
2    workshops. The Commission shall make public the utility 
3    capital investments proposal by posting it on the 
4    Commission's website and set the location and time of any 
5    workshop to be held as part of the workshop process, and 
6    establish a data request process, consistent with the 
7    Commission's rules, that affords workshop participants 
8    opportunities to submit data requests to the utility, and 
9    receive responses in accordance with the utility's 
10    obligations under the law, prior to the workshop, 
11    regarding the information described in this paragraph (5). 
12    Upon the written request of a workshop participant, the 
13    utility shall also present at a given workshop at least 
14    one appropriate company representative who can address the 
15    specific written questions or written categories of 
16    questions identified in advance by the workshop 
17    participant regarding issues related to the utility's 
18    Multi-Year Integrated Grid Plan. To facilitate public 
19    feedback, the administrator facilitating the workshops 
20    shall, throughout the workshop process, develop questions 
21    for stakeholder input on topics being considered. This may 
22    include, but is not limited to: design of the workshop 
23    process, locational data and information provided by 
24    utilities, alignment of plans, programs, investments and 
25    objectives, and other topics as deemed appropriate by the 
26    Commission facilitation staff. Stakeholder feedback shall 
 
 
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1    not be limited to these questions. The information 
2    provided as part of the workshop process pursuant to this 
3    subsection (e) is intended to be informational and to 
4    provide a preliminary view of costs and investments, which 
5    may change. Accordingly, the information provided pursuant 
6    to this subsection (e) shall not be binding on the utility 
7    and shall not be the sole basis for a finding in any 
8    Commission proceeding of imprudence, unreasonableness, or 
9    lack of use or usefulness of any individual or aggregate 
10    level of utility plant or other investment or expenditure 
11    addressed; however, information contained in the plan may 
12    be used in a proceeding before the Commission, with weight 
13    of such evidence to be determined by the Commission.
14        (6) Workshops shall not be considered settlement 
15    negotiations, compromise negotiations, or offers to 
16    compromise for the purposes of Illinois Rule of Evidence 
17    408. All materials shared as a part of the workshop 
18    process, and that are not determined to be confidential as 
19    described in paragraph (3) of this subsection (e), shall 
20    be made publicly available on a website made available by 
21    the Commission.
22        (7) On conclusion of the workshops, the Commission 
23    shall open a comment period that allows interested and 
24    diverse stakeholders to submit comments and 
25    recommendations regarding the utility's Multi-Year 
26    Integrated Grid Plan filing. Based on the workshop process 
 
 
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1    and stakeholder comments and recommendations offered 
2    verbally or in writing during the workshops and in writing 
3    during the comment period following the workshops, the 
4    independent third-party facilitator shall prepare a 
5    report, to be submitted to the Commission no later than 
6    July 1, 2022, describing the stakeholders, discussions, 
7    proposals, and areas of consensus and disagreement from 
8    the workshop process, and making recommendations to the 
9    Commission regarding the utility's Multi-Year Integrated 
10    Grid Plan. Interested stakeholders shall have an 
11    opportunity to provide comment on the independent 
12    third-party facilitator report.
13        (8) Based on discussions in the workshops, the 
14    independent third-party facilitator report, and 
15    stakeholder comments and recommendations made during and 
16    following the workshop process, the Commission shall issue 
17    initiating orders no later than August 1, 2022, requiring 
18    the electric utilities subject to this Section to file the 
19    first Multi-Year Integrated Grid Plan no later than 
20    January 20, 2023. The initiating orders shall specify the 
21    requirements applicable to the utilities' Multi-Year 
22    Integrated Grid Plans, which shall supplement and not 
23    replace those requirements described in subsection (f) of 
24    this Section.
25    (f) Multi-Year Integrated Grid Plan.
26        (1) Pursuant to this subsection (f) and the initiating 
 
 
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1    orders of the Commission, each electric utility subject to 
2    this Section shall, no later than January 20, 2023, submit 
3    its first Multi-Year Integrated Grid Plan. No later than 
4    January 20, 2026, and every 4 years thereafter, the 
5    utility shall submit its subsequent Plan. Each Plan shall:
6            (A) incorporate requirements established by the 
7        Commission in its initiating order; and
8            (B) propose distribution system investment 
9        programs, policies, and plans designed to optimize 
10        achievement of the objectives set forth in subsection 
11        (d) of this Section and achieve the metrics approved 
12        by the Commission pursuant to Section 16-108.18 of 
13        this Act.
14        To the extent practicable and reasonable, all 
15    programs, policies, and initiatives proposed by the 
16    utility in its plan should be informed by stakeholder 
17    input received during the workshop process pursuant to 
18    subsection (e) of this Section. Where specific stakeholder 
19    input has not been incorporated in proposed programs, 
20    policies, and plans, the electric utility shall provide an 
21    explanation as to why that input was not incorporated.
22        (2) In order to ensure electric utilities' ability to 
23    meet the goals and objectives set forth in this Section, 
24    the Multi-Year Integrated Grid Plans must include, at 
25    minimum, the following information:
26            (A) A description of the utility's distribution 
 
 
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1        system planning process, including:
2                (i) the overview of the process, including 
3            frequency and duration of the process, roles, and 
4            responsibilities of utility personnel and 
5            departments involved;
6                (ii) a summary of the meetings with 
7            stakeholders conducted prior to filing of the plan 
8            with the Commission.
9                (iii) the description of any coordination of 
10            the processes with any other planning process 
11            internal or external to the utility, including 
12            those required by a regional transmission 
13            operator.
14            (B) A detailed description of the current 
15        operating conditions for the distribution system 
16        separately presented for each of the utility's 
17        operating areas, where possible, including a detailed 
18        description, with supporting data, of system 
19        conditions, including baseline data regarding the 
20        utility's distribution system from the utility's 
21        annual report to the Commission, total distribution 
22        system substation capacity in kVa, total miles of 
23        primary overhead distribution wire, and total miles of 
24        primary underground distribution cable, distributed 
25        energy resource deployment by type, size, customer 
26        class, and geographic dispersion as to those DERs that 
 
 
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1        have completed the interconnection process, the most 
2        current distribution line loss study, current and 
3        expected System Average Interruption Frequency Index 
4        and Customer Average Interruption Duration Index data 
5        for the system, identification of the system model 
6        software currently used and planned software 
7        deployments, and other data needs as requested by the 
8        Commission or as determined through Commission rules. 
9        The description shall also include the utility's most 
10        recent system load and peak demand forecast for at 
11        least the next 5 years, and up to 10 years if 
12        available, a discussion of how the forecast was 
13        prepared and how distributed energy resources and 
14        energy efficiency were factored into the forecast, and 
15        identification of the forecasting software currently 
16        used and planned software deployments.
17            (C) Financial Data.
18                (i) For each of the preceding 5 years, the 
19            utility's distribution system investments by the 
20            investment categories tracked by the utility, 
21            including, but not limited to, new business, 
22            facility relocation, capacity expansion, system 
23            performance, preventive maintenance, corrective 
24            maintenance, the total amount of investments 
25            associated with the integration of DERs, the total 
26            amount of charges to DER developers and retail 
 
 
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1            customers for interconnection of DERs to the 
2            distribution system, and a list of each major 
3            investment category the utility used to maintain 
4            its routine standing operational activities and 
5            the associated plant in service amount for each 
6            category in which the plant in service amount is 
7            at least $2,000,000;
8                (ii) For each of the preceding 5 years, data 
9            on and a discussion of the utility's distribution 
10            system operation and maintenance expenses;
11                (iii) A 5-year long-range forecast of 
12            distribution system capital investments and 
13            operational and maintenance expenses, including a 
14            discussion of any projections for expenses for the 
15            categories listed in subparagraph (i) of this item 
16            (C).
17            (D) System data on DERs on the utility's 
18        distribution system, including the total number and 
19        nameplate capacity of DERs that completed 
20        interconnection in the prior year, current DER 
21        deployment by type, size, and geographic dispersion, 
22        to the extent that granular geographic information 
23        does not disclose personally identifiable information, 
24        and other data as requested by the Commission or 
25        determined by Commission rules.
26            (E) Hosting Capacity and Interconnection 
 
 
10400SB0025ham003- 638 -LRB104 07069 AAS 29208 a

1        Requirements.
2                (i) The utility shall make available on its 
3            website the hosting capacity analysis results that 
4            shall include mapping and GIS capability, as well 
5            as any other requirements requested by the 
6            Commission or determined through Commission rules. 
7            The plan shall identify where the hosting capacity 
8            analysis results shall be made publicly available. 
9            This shall also include an assessment of the 
10            impact of utility investments over the next 5 
11            years on hosting capacity and a narrative 
12            discussion of how the hosting capacity analysis 
13            advances customer-sited distributed energy 
14            resources, including electric vehicles, energy 
15            storage systems, and photovoltaic resources, and 
16            how the identification of interconnection points 
17            on the distribution system will support the 
18            continued development of distributed energy 
19            resources.
20                (ii) Discussion of the utility's 
21            interconnection requirements and how they comply 
22            with the Commission's applicable regulations.
23            (F) Identification and discussion of the scenarios 
24        considered in the development of the utility's 
25        Multi-Year Integrated Grid Plan, including DER 
26        scenarios, and discussion of base-case and alternative 
 
 
10400SB0025ham003- 639 -LRB104 07069 AAS 29208 a

1        scenarios, how the scenarios were developed and 
2        selected, and how the scenarios include a reasonable 
3        mix of DERs scenarios, types, and geographic 
4        dispersion. Scenarios shall at least consider the 
5        5-year forecast horizon of the Multi-Year Integrated 
6        Grid Plan, but may also consider longer-term scenarios 
7        where data is available. The plan shall also include 
8        requirements requested by the Commission or determined 
9        through Commission rules.
10            (G) An evaluation of the short-term and long-run 
11        benefits and costs of distributed energy resources 
12        located on the distribution system, including, but not 
13        limited to, the locational, temporal, and 
14        performance-based benefits and costs of distributed 
15        energy resources. The utility shall use the results of 
16        this evaluation to inform its analysis of Solution 
17        Sourcing Opportunities, including nonwires 
18        alternatives, under subparagraph (K) of paragraph (2) 
19        subsection (f) of this Section. The Commission may use 
20        the data produced through this evaluation to, among 
21        other use-cases, inform the Commission's investigation 
22        and establishment of tariffs and compensation for 
23        distributed energy resources interconnecting to the 
24        utility's distribution system, including rebates 
25        provided by the electric utility pursuant to Section 
26        16-107.6 of this Act.
 
 
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1            (H) Long-term Distribution System Investment Plan.
2                (i) The utility's planned distribution capital 
3            investments for the period covered by the planning 
4            process required by this Section, by the 
5            investment categories used by the utility, and 
6            with discussion of any individual planned projects 
7            with a planned total investment gross amount of 
8            $3,000,000 or more and of the alternatives 
9            considered by the utility to such individual 
10            projects including any non-traditional 
11            alternatives and DER alternatives, and supporting 
12            data. This shall provide sufficiently detailed 
13            explanations of how the planned investments shall 
14            support the goals in subsection (d) of this 
15            Section.
16                (ii) Discussion of how the utility's capital 
17            investments plan is consistent with Commission 
18            orders regarding the procurement of renewable 
19            resources as discussed in Section 16-111.5 of this 
20            Act, energy efficiency plans as discussed in 
21            Section 8-103B, distributed generation rebates as 
22            discussed in Section 16-107.6, and any other 
23            Commission order affecting the goals described in 
24            subsection (d) of this Section.
25                (iii) A plan for achieving the applicable 
26            metrics that were approved by the Commission for 
 
 
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1            the utility pursuant to subsection (e) of Section 
2            16-108.18 of this Act.
3                (iv) A narrative discussion of the utility's 
4            vision for the distribution system over the next 5 
5            years.
6                (v) Any additional information requested by 
7            the Commission or determined through Commission 
8            rules.
9            (I) A detailed description of historic 
10        distribution system operations and maintenance 
11        expenditures for the preceding 5 years and of planned 
12        or projected operations and maintenance expenditures 
13        for the period covered by the planning process 
14        required by this Section, as well as the data, 
15        reasoning and explanation supporting planned or 
16        projected expenditures. Any additional information 
17        requested by the Commission or determined through 
18        Commission rules.
19            (J) A detailed plan for achieving the applicable 
20        metrics that were approved by the Commission for the 
21        utility pursuant to subsection (e) of Section 
22        16-108.18 of this Act, including, but not limited to, 
23        the following:
24                (i) A description of, exclusive of low-income 
25            rate relief programs and other income-qualified 
26            programs, how the utility is supporting efforts to 
 
 
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1            bring 40% of benefits from programs, policies, and 
2            initiatives proposed in their Multi-Year 
3            Integrated Grid Plan to ratepayers in low-income 
4            and environmental justice communities. This shall 
5            also include any information requested by the 
6            Commission or determined through Commission rules. 
7            Nothing in this subparagraph is meant to require a 
8            specific amount of spending in a particular 
9            geographic area.
10                (ii) A detailed analysis of current and 
11            projected flexible resources, including resource 
12            type, size (in MW and MWh), location and 
13            environmental impact, as well as anticipated needs 
14            that can be met using flexible resources, to meet 
15            the goals described in subsection (d) of this 
16            Section, to meet the applicable metrics that were 
17            approved by the Commission for the utility 
18            pursuant to subsection (e) of Section 16-108.18 of 
19            this Act, and any other Commission order affecting 
20            the goals described in subsection (d) of this 
21            Section.
22                (iii) Any additional information requested by 
23            the Commission or determined through Commission 
24            rules.
25            (K) Identification of potential cost-effective 
26        solutions from nontraditional and third-party owned 
 
 
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1        investments that could meet anticipated grid needs, 
2        including, but not limited to, distributed energy 
3        resources procurements, tariffs or contracts, 
4        programmatic solutions, rate design options, 
5        technologies or programs that facilitate load 
6        flexibility, nonwires alternatives, and other 
7        solutions that are intended to meet the objectives 
8        described at subsection (d). It is the policy of this 
9        State that cost-effective third-party or 
10        customer-owned distributed energy resources create 
11        robust competition and customer choice and shall be 
12        considered as appropriate. The Commission shall 
13        establish rules determining data or methods for 
14        Solution Sourcing Opportunities.
15            (L) A detailed description of the utility's 
16        interoperability plan, which must describe the manner 
17        in which the electric utility's current and planned 
18        distribution system investments will work together and 
19        exchange information and data, the extent to which the 
20        utility is implementing open standards and interfaces 
21        with third-party distributed energy resource owners 
22        and aggregators, and the utility's plan for 
23        interoperability testing and certification.
24            (M) For plans that include a time period that is 
25        after January 1, 2029, a description of efforts to 
26        support transportation electrification through the 
 
 
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1        following:
2                (i) make-ready investments and programs to 
3            facilitate the rapid deployment of charging 
4            equipment throughout this State, especially 
5            deployment that targets medium heavy duty 
6            electrification and multi-unit buildings;
7                (ii) the development and implementation of (1) 
8            time-of-use rates and their benefit for electric 
9            vehicle users and for all customers, (2) optimized 
10            charging programs to achieve identified savings, 
11            and (3) new contracts and compensation for 
12            services in the optimized charging programs, 
13            through signals that allow electric vehicle 
14            charging to respond to local system conditions, 
15            manage critical peak periods, serve as a demand 
16            response or peak resource, and maximize renewable 
17            energy use and integration into the grid; and
18                (iii) commercial tariffs utilizing 
19            alternatives to traditional demand-based rate 
20            structures that facilitate charging for 
21            light-duty, heavy-duty, and fleet electric 
22            vehicles.
23                For items (i) through (iii), the utility shall 
24            demonstrate methods of minimizing ratepayer 
25            impacts and exempting or minimizing, to the extent 
26            possible, low-income ratepayers from the costs 
 
 
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1            associated with facilitating the expansion of 
2            electric vehicle charging.    
3        (3) To the extent any information in utilities' 
4    Multi-Year Integrated Grid Plans is designated as 
5    confidential and proprietary under the Commission's rules, 
6    the proponent of the designation shall have the burden of 
7    making the requisite showing under the Commission's rules. 
8    For data that is determined to be confidential or that 
9    includes personally identifiable information, the 
10    Commission may develop procedures and processes to enable 
11    data sharing with parties and stakeholders while ensuring 
12    the confidentiality of the information. All confidential 
13    information exchanged, submitted, or shared by a utility 
14    pursuant to this Section shall be protected from 
15    intentional and accidental dissemination. The Commission 
16    shall have authority to supervise, protect, and restrict 
17    access to all confidential, commercially sensitive, or 
18    system security related information and data, and shall be 
19    authorized to take all necessary steps to protect that 
20    information from unauthorized disclosure. This paragraph 
21    shall not be interpreted to require a utility to make 
22    publicly available any information or data that could 
23    compromise the physical or cyber security of a utility's 
24    distribution system. Any party that accidentally 
25    disseminates confidential information obtained pursuant to 
26    a proceeding initiated in accordance with this Section, or 
 
 
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1    is the victim of a cyber-security breach, must notify the 
2    affected utility, the Illinois Attorney General, and the 
3    Commission staff with 24 hours of knowledge of such 
4    dissemination or breach. Any party that fails to provide 
5    required notification of such a breach shall be subject to 
6    remedies available to the Commission and the Illinois 
7    Attorney General.
8        (4) It is the policy of this State that holistic 
9    consideration of all related investments, planning 
10    processes, tariffs, rate design options, programs, and 
11    other utility policies and plans shall be required. To 
12    that end, the Commission shall consider, comprehensively, 
13    the impact of all related plans, tariffs, programs, and 
14    policies on the Plan and on each other, including:
15            (A) time-of-use pricing program pursuant to 
16        Section 16-107.7 of this Act, hourly pricing program 
17        pursuant to Section 16-107 of this Act, and any other 
18        time-variant or dynamic pricing program;
19            (B) distributed generation rebate pursuant to 
20        Section 16-107.6 of this Act;
21            (C) net electricity metering, pursuant to Section 
22        16-107.5 of this Act;
23            (D) energy efficiency programs pursuant to Section 
24        8-103B of this Act;
25            (E) beneficial electrification programs pursuant 
26        to Section 16-107.8 of this Act;
 
 
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1            (F) Equitable Energy Upgrade Program pursuant to 
2        Section 16-111.10 of this Act;
3            (G) renewable energy programs and procurements set 
4        forth in the Illinois Power Agency Act, including, but 
5        not limited to, those set forth in the long-term 
6        renewable resources procurement plan developed 
7        pursuant to Section 1-20 of that Act; and
8            (H) other plans, programs, and policies that are 
9        relevant to distribution grid investments, costs, 
10        planning, and other categories as requested by the 
11        Commission.
12        The Plan shall comprehensively detail the relationship 
13    between these plans, tariffs, and programs and to the 
14    electric utility's achievement of the objectives in 
15    subsection (d). The Plan shall be designed to coordinate 
16    each of these plans, programs, and tariffs with the 
17    electric utility's long-term distribution system 
18    investment planning in order to maximize the benefits of 
19    each.
20        (5) The initiating order for the initial Multi-Year 
21    Integrated Grid Plan, as well as each electric utility's 
22    subsequent Integrated Grid Plans under subsection (g), 
23    shall begin a contested proceeding as described in 
24    subsection (d) of Section 10-101.1 of this Act.
25            (A) In evaluating a utility's Plan, the Commission 
26        shall consider, at minimum, whether the Plan:
 
 
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1                (1) meets the objectives of this Section;
2                (2) includes the components in paragraph (2) 
3            of subsection (f) of this Section;
4                (3) considers and incorporates, where 
5            practicable, input from interested stakeholders, 
6            including parties and people who offer public 
7            comment without legal representation;
8                (4) considers nontraditional, including 
9            third-party owned, investment alternatives that 
10            can meet grid needs and provide additional 
11            benefits (including consumer, economic, and 
12            environmental benefits) beyond comparable, 
13            traditional utility-planned capital investments;
14                (5) equitably benefits environmental justice 
15            communities; and
16                (6) maximizes consumer, environmental, 
17            economic, and community benefits over a 10-year 
18            horizon.
19            (B) The Commission, after notice and hearing, 
20        shall modify each electric utility's Plan as necessary 
21        to comply with the objectives of this Section. The 
22        Commission may approve, or modify and approve, a Plan 
23        only if it finds that the Plan is reasonable, complies 
24        with the objectives and requirements of this Section, 
25        and reasonably incorporates input from parties. The 
26        Commission may reject each electric utility's Plan if 
 
 
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1        it finds that the Plan does not comply with the 
2        objectives and requirements of this Section. If the 
3        Commission enters an order rejecting a Plan, the 
4        utility must refile a Plan within 3 months after that 
5        order, and until the Commission approves a Plan, the 
6        utility's existing Plan will remain in effect.
7            (C) For the initial Integrated Grid Plan filings, 
8        the Commission shall enter an order approving, 
9        modifying, or rejecting the Plan no later than 
10        December 15, 2023. For subsequent Integrated Grid Plan 
11        filings, the Commission shall enter an order 
12        approving, modifying, or rejecting the Plan no later 
13        than December 15 of the year in which it was filed.
14            (D) Each electric utility shall file its proposed 
15        Initial Multi-Year Integrated Grid Plan no later than 
16        January 20, 2023. Prior to that date and following the 
17        initiating order, the Commission shall initiate a case 
18        management conference and shall take any appropriate 
19        steps to begin meaningful consideration of issues, 
20        including enabling interested parties to begin 
21        conducting discovery.
22        (6) As part of its order approving a utility's 
23    Multi-Year Integrated Grid Plan, including any 
24    modifications required, the Commission may create a 
25    subsequent implementation plan docket, or multiple 
26    implementation plan dockets, if the Commission determines 
 
 
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1    that multiple dockets would be preferable, to consider a 
2    utility's detailed plan or plans, as directed in the 
3    Commission's order.
4    (g) No later than January 20, 2026 and every 4 years 
5thereafter, each electric utility subject to this Section 
6shall file a new Multi-Year Integrated Grid Plan for the 
7subsequent 4 delivery years after the completion of the 
8then-effective Plan. Each Plan shall meet the requirements 
9described in subsection (f) of this Section, and shall be 
10preceded by a workshop process which meets the same 
11requirements described in subsection (e). If appropriate, the 
12Commission may require additional implementation dockets to 
13follow Subsequent Multi-Year Integrated Grid Plan filings.
14    (h) During the period leading to approval of the first 
15Multi-Year Integrated Grid Plan, each electric utility will 
16necessarily continue to invest in its distribution grid. Those 
17investments will be subject to a determination of prudence and 
18reasonableness consistent with Commission practice and law. 
19Any failure of such investments to conform to the Multi-Year 
20Integrated Grid Plan ultimately approved shall not imply 
21imprudence or unreasonableness.
22    (i) The Commission shall adopt rules to carry out the 
23provisions of this Section under the emergency rulemaking 
24provisions set forth in Section 5-45 of the Illinois 
25Administrative Procedure Act, and such emergency rules may be 
26effective no later than 90 days after the effective date of 
 
 
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1this amendatory Act of the 102nd General Assembly.
2(Source: P.A. 102-662, eff. 9-15-21.)
 
3    (220 ILCS 5/16-107.5)
4    Sec. 16-107.5. Net electricity metering.
5    (a) The General Assembly finds and declares that a program 
6to provide net electricity metering, as defined in this 
7Section, for eligible customers can encourage private 
8investment in renewable energy resources, stimulate economic 
9growth, enhance the continued diversification of Illinois' 
10energy resource mix, and protect the Illinois environment. 
11Further, to achieve the goals of this Act that robust options 
12for customer-site distributed generation and storage continue 
13to thrive in Illinois, the General Assembly finds that a 
14predictable transition must be ensured for customers between 
15full net metering at the retail electricity rate to the 
16distribution generation rebate described in Section 16-107.6. 
17    (b) As used in this Section: ,    
18        (i) "Community community renewable generation project" 
19    shall have the meaning set forth in Section 1-10 of the 
20    Illinois Power Agency Act. ;    
21        (ii) "Eligible eligible customer" means a retail 
22    customer that owns, hosts, or operates, including any 
23    third-party owned systems, a solar, wind, or other 
24    eligible renewable electrical generating facility or an 
25    eligible storage device that is located on the customer's 
 
 
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1    premises or customer's side of the billing meter and is 
2    intended primarily to offset the customer's own current or 
3    future electrical requirements. ;    
4        (iii) "Electricity electricity provider" means an 
5    electric utility or alternative retail electric supplier. ;    
6        (iv) "Eligible eligible renewable electrical 
7    generating facility" means a generator, which may include 
8    the colocation co-location of an energy storage system, 
9    that is interconnected under rules adopted by the 
10    Commission and is powered by solar electric energy, wind, 
11    dedicated crops grown for electricity generation, 
12    agricultural residues, untreated and unadulterated wood 
13    waste, livestock manure, anaerobic digestion of livestock 
14    or food processing waste, fuel cells or microturbines 
15    powered by renewable fuels, or hydroelectric energy. ;    
16        (v) "Net net electricity metering" (or "net metering") 
17    means the measurement, during the billing period 
18    applicable to an eligible customer, of the net amount of 
19    electricity supplied by an electricity provider to the 
20    customer or provided to the electricity provider by the 
21    customer or subscriber. ;    
22        (vi) "Subscriber subscriber" shall have the meaning as 
23    set forth in Section 1-10 of the Illinois Power Agency 
24    Act. ;    
25        (vii) "Subscription subscription" shall have the 
26    meaning set forth in Section 1-10 of the Illinois Power 
 
 
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1    Agency Act. ;    
2        (viii) "Energy energy storage system" means 
3    commercially available technology that is capable of 
4    absorbing energy and storing it for a period of time for 
5    use at a later time, including, but not limited to, 
6    electrochemical, thermal, and electromechanical 
7    technologies, and may be interconnected behind the 
8    customer's meter or interconnected behind its own meter. ; 
9    and    
10        (ix) "Future future electrical requirements" means 
11    modeled electrical requirements upon occupation of a new 
12    or vacant property, and other reasonable expectations of 
13    future electrical use, as well as, for occupied 
14    properties, a reasonable approximation of the annual load 
15    of 2 electric vehicles and, for non-electric heating 
16    customers, a reasonable approximation of the incremental 
17    electric load associated with fuel switching. The 
18    approximations shall be applied to the appropriate net 
19    metering tariff and do not need to be unique to each 
20    individual eligible customer. The utility shall submit 
21    these approximations to the Commission for review, 
22    modification, and approval.
23        (x) "Vehicle storage system" means a vehicle that when 
24    connected to an electric utility's distribution system is 
25    capable of being an energy storage system, as defined in 
26    Section 16-107.6.    
 
 
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1    (c) A net metering facility shall be equipped with 
2metering equipment that can measure the flow of electricity in 
3both directions at the same rate.
4        (1) For eligible customers whose electric service has 
5    not been declared competitive pursuant to Section 16-113 
6    of this Act as of July 1, 2011 and whose electric delivery 
7    service is provided and measured on a kilowatt-hour basis 
8    and electric supply service is not provided based on 
9    hourly pricing, this shall typically be accomplished 
10    through use of a single, bi-directional meter. If the 
11    eligible customer's existing electric revenue meter does 
12    not meet this requirement, the electricity provider shall 
13    arrange for the local electric utility or a meter service 
14    provider to install and maintain a new revenue meter at 
15    the electricity provider's expense, which may be the smart 
16    meter described by subsection (b) of Section 16-108.5 of 
17    this Act.
18        (2) For eligible customers whose electric service has 
19    not been declared competitive pursuant to Section 16-113 
20    of this Act as of July 1, 2011 and whose electric delivery 
21    service is provided and measured on a kilowatt demand 
22    basis and electric supply service is not provided based on 
23    hourly pricing, this shall typically be accomplished 
24    through use of a dual channel meter capable of measuring 
25    the flow of electricity both into and out of the 
26    customer's facility at the same rate and ratio. If such 
 
 
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1    customer's existing electric revenue meter does not meet 
2    this requirement, then the electricity provider shall 
3    arrange for the local electric utility or a meter service 
4    provider to install and maintain a new revenue meter at 
5    the electricity provider's expense, which may be the smart 
6    meter described by subsection (b) of Section 16-108.5 of 
7    this Act.
8        (3) For all other eligible customers, until such time 
9    as the local electric utility installs a smart meter, as 
10    described by subsection (b) of Section 16-108.5 of this 
11    Act, the electricity provider may arrange for the local 
12    electric utility or a meter service provider to install 
13    and maintain metering equipment capable of measuring the 
14    flow of electricity both into and out of the customer's 
15    facility at the same rate and ratio, typically through the 
16    use of a dual channel meter. If the eligible customer's 
17    existing electric revenue meter does not meet this 
18    requirement, then the costs of installing such equipment 
19    shall be paid for by the customer. 
20    (d) An electricity provider shall measure and charge or 
21credit for the net electricity supplied to eligible customers 
22or provided by eligible customers whose electric service has 
23not been declared competitive pursuant to Section 16-113 of 
24this Act as of July 1, 2011 and whose electric delivery service 
25is provided and measured on a kilowatt-hour basis and electric 
26supply service is not provided based on hourly pricing in the 
 
 
10400SB0025ham003- 656 -LRB104 07069 AAS 29208 a

1following manner:
2        (1) If the amount of electricity used by the customer 
3    during the billing period exceeds the amount of 
4    electricity produced by the customer, the electricity 
5    provider shall charge the customer for the net electricity 
6    supplied to and used by the customer as provided in 
7    subsection (e-5) of this Section.
8        (2) If the amount of electricity produced by a 
9    customer during the billing period exceeds the amount of 
10    electricity used by the customer during that billing 
11    period, the electricity provider supplying that customer 
12    shall apply a 1:1 kilowatt-hour credit to a subsequent 
13    bill for service to the customer for the net electricity 
14    supplied to the electricity provider. The electricity 
15    provider shall continue to carry over any excess 
16    kilowatt-hour credits earned and apply those credits to 
17    subsequent billing periods to offset any 
18    customer-generator consumption in those billing periods 
19    until all credits are used or until the end of the 
20    annualized period.
21        (3) At the end of the year or annualized over the 
22    period that service is supplied by means of net metering, 
23    or in the event that the retail customer terminates 
24    service with the electricity provider prior to the end of 
25    the year or the annualized period, any remaining credits 
26    in the customer's account shall expire.
 
 
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1    (d-5) An electricity provider shall measure and charge or 
2credit for the net electricity supplied to eligible customers 
3or provided by eligible customers whose electric service has 
4not been declared competitive pursuant to Section 16-113 of 
5this Act as of July 1, 2011 and whose electric delivery service 
6is provided and measured on a kilowatt-hour basis and electric 
7supply service is provided based on hourly pricing or 
8time-of-use rates in the following manner:
9        (1) If the amount of electricity used by the customer 
10    during any hourly period or time-of-use period exceeds the 
11    amount of electricity produced by the customer, the 
12    electricity provider shall charge the customer for the net 
13    electricity supplied to and used by the customer according 
14    to the terms of the contract or tariff to which the same 
15    customer would be assigned to or be eligible for if the 
16    customer was not a net metering customer.
17        (2) If the amount of electricity produced by a 
18    customer during any hourly period or time-of-use period 
19    exceeds the amount of electricity used by the customer 
20    during that hourly period or time-of-use period, the 
21    energy provider shall apply a credit for the net 
22    kilowatt-hours produced in such period. The credit shall 
23    consist of an energy credit and a delivery service credit. 
24    The energy credit shall be valued at the same price per 
25    kilowatt-hour as the electric service provider would 
26    charge for kilowatt-hour energy sales during that same 
 
 
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1    hourly period or time-of-use period. The delivery credit 
2    shall be equal to the net kilowatt-hours produced in such 
3    hourly period or time-of-use period times a credit that 
4    reflects all kilowatt-hour based charges in the customer's 
5    electric service rate, excluding energy charges. 
6    (e) An electricity provider shall measure and charge or 
7credit for the net electricity supplied to eligible customers 
8whose electric service has not been declared competitive 
9pursuant to Section 16-113 of this Act as of July 1, 2011 and 
10whose electric delivery service is provided and measured on a 
11kilowatt demand basis and electric supply service is not 
12provided based on hourly pricing in the following manner:
13        (1) If the amount of electricity used by the customer 
14    during the billing period exceeds the amount of 
15    electricity produced by the customer, then the electricity 
16    provider shall charge the customer for the net electricity 
17    supplied to and used by the customer as provided in 
18    subsection (e-5) of this Section. The customer shall 
19    remain responsible for all taxes, fees, and utility 
20    delivery charges that would otherwise be applicable to the 
21    net amount of electricity used by the customer.
22        (2) If the amount of electricity produced by a 
23    customer during the billing period exceeds the amount of 
24    electricity used by the customer during that billing 
25    period, then the electricity provider supplying that 
26    customer shall apply a 1:1 kilowatt-hour credit that 
 
 
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1    reflects the kilowatt-hour based charges in the customer's 
2    electric service rate to a subsequent bill for service to 
3    the customer for the net electricity supplied to the 
4    electricity provider. The electricity provider shall 
5    continue to carry over any excess kilowatt-hour credits 
6    earned and apply those credits to subsequent billing 
7    periods to offset any customer-generator consumption in 
8    those billing periods until all credits are used or until 
9    the end of the annualized period.
10        (3) At the end of the year or annualized over the 
11    period that service is supplied by means of net metering, 
12    or in the event that the retail customer terminates 
13    service with the electricity provider prior to the end of 
14    the year or the annualized period, any remaining credits 
15    in the customer's account shall expire.
16    (e-5) An electricity provider shall provide electric 
17service to eligible customers who utilize net metering at 
18non-discriminatory rates that are identical, with respect to 
19rate structure, retail rate components, and any monthly 
20charges, to the rates that the customer would be charged if not 
21a net metering customer. An electricity provider shall not 
22charge net metering customers any fee or charge or require 
23additional equipment, insurance, or any other requirements not 
24specifically authorized by interconnection standards 
25authorized by the Commission, unless the fee, charge, or other 
26requirement would apply to other similarly situated customers 
 
 
10400SB0025ham003- 660 -LRB104 07069 AAS 29208 a

1who are not net metering customers. The customer will remain 
2responsible for all taxes, fees, and utility delivery charges 
3that would otherwise be applicable to the net amount of 
4electricity used by the customer. Subsections (c) through (e) 
5of this Section shall not be construed to prevent an 
6arms-length agreement between an electricity provider and an 
7eligible customer that sets forth different prices, terms, and 
8conditions for the provision of net metering service, 
9including, but not limited to, the provision of the 
10appropriate metering equipment for non-residential customers.
11    (f) Notwithstanding the requirements of subsections (c) 
12through (e-5) of this Section, an electricity provider must 
13require dual-channel metering for customers operating eligible 
14renewable electrical generating facilities to whom the 
15provisions of neither subsection (d), (d-5), nor (e) of this 
16Section apply. In such cases, electricity charges and credits 
17shall be determined as follows: 
18        (1) The electricity provider shall assess and the 
19    customer remains responsible for all taxes, fees, and 
20    utility delivery charges that would otherwise be 
21    applicable to the gross amount of kilowatt-hours supplied 
22    to the eligible customer by the electricity provider.
23        (2) Each month that service is supplied by means of 
24    dual-channel metering, the electricity provider shall 
25    compensate the eligible customer for any excess 
26    kilowatt-hour credits at the electricity provider's 
 
 
10400SB0025ham003- 661 -LRB104 07069 AAS 29208 a

1    avoided cost of electricity supply over the monthly period 
2    or as otherwise specified by the terms of a power-purchase 
3    agreement negotiated between the customer and electricity 
4    provider.
5        (3) For all eligible net metering customers taking 
6    service from an electricity provider under contracts or 
7    tariffs employing hourly or time-of-use rates, any monthly 
8    consumption of electricity shall be calculated according 
9    to the terms of the contract or tariff to which the same 
10    customer would be assigned to or be eligible for if the 
11    customer was not a net metering customer. When those same 
12    customer-generators are net generators during any discrete 
13    hourly or time-of-use period, the net kilowatt-hours 
14    produced shall be valued at the same price per 
15    kilowatt-hour as the electric service provider would 
16    charge for retail kilowatt-hour sales during that same 
17    time-of-use period. 
18    (g) For purposes of federal and State laws providing 
19renewable energy credits or greenhouse gas credits, the 
20eligible customer shall be treated as owning and having title 
21to the renewable energy attributes, renewable energy credits, 
22and greenhouse gas emission credits related to any electricity 
23produced by the qualified generating unit. The electricity 
24provider may not condition participation in a net metering 
25program on the signing over of a customer's renewable energy 
26credits; provided, however, this subsection (g) shall not be 
 
 
10400SB0025ham003- 662 -LRB104 07069 AAS 29208 a

1construed to prevent an arms-length agreement between an 
2electricity provider and an eligible customer that sets forth 
3the ownership or title of the credits.
4    (h) Within 120 days after the effective date of this 
5amendatory Act of the 95th General Assembly, the Commission 
6shall establish standards for net metering and, if the 
7Commission has not already acted on its own initiative, 
8standards for the interconnection of eligible renewable 
9generating equipment to the utility system. The 
10interconnection standards shall address any procedural 
11barriers, delays, and administrative costs associated with the 
12interconnection of customer-generation while ensuring the 
13safety and reliability of the units and the electric utility 
14system. The Commission shall consider the Institute of 
15Electrical and Electronics Engineers (IEEE) Standard 1547 and 
16the issues of (i) reasonable and fair fees and costs, (ii) 
17clear timelines for major milestones in the interconnection 
18process, (iii) nondiscriminatory terms of agreement, and (iv) 
19any best practices for interconnection of distributed 
20generation.
21    (h-5) Within 90 days after the effective date of this 
22amendatory Act of the 102nd General Assembly, the Commission 
23shall: 
24        (1) establish an Interconnection Working Group. The 
25    working group shall include representatives from electric 
26    utilities, developers of renewable electric generating 
 
 
10400SB0025ham003- 663 -LRB104 07069 AAS 29208 a

1    facilities, other industries that regularly apply for 
2    interconnection with the electric utilities, 
3    representatives of distributed generation customers, the 
4    Commission Staff, and such other stakeholders with a 
5    substantial interest in the topics addressed by the 
6    Interconnection Working Group. The Interconnection Working 
7    Group shall address at least the following issues:
8            (A) cost and best available technology for 
9        interconnection and metering, including the 
10        standardization and publication of standard costs;
11            (B) transparency, accuracy and use of the 
12        distribution interconnection queue and hosting 
13        capacity maps;
14            (C) distribution system upgrade cost avoidance 
15        through use of advanced inverter functions;
16            (D) predictability of the queue management process 
17        and enforcement of timelines;
18            (E) benefits and challenges associated with group 
19        studies and cost sharing;
20            (F) minimum requirements for application to the 
21        interconnection process and throughout the 
22        interconnection process to avoid queue clogging 
23        behavior;
24            (G) process and customer service for 
25        interconnecting customers adopting distributed energy 
26        resources, including energy storage;
 
 
10400SB0025ham003- 664 -LRB104 07069 AAS 29208 a

1            (H) options for metering distributed energy 
2        resources, including energy storage;
3            (I) interconnection of new technologies, including 
4        smart inverters and energy storage;
5            (J) collect, share, and examine data on Level 1 
6        interconnection costs, including cost and type of 
7        upgrades required for interconnection, and use this 
8        data to inform the final standardized cost of Level 1 
9        interconnection; and
10            (K) such other technical, policy, and tariff 
11        issues related to and affecting interconnection 
12        performance and customer service as determined by the 
13        Interconnection Working Group. 
14        The Commission may create subcommittees of the 
15    Interconnection Working Group to focus on specific issues 
16    of importance, as appropriate. The Interconnection Working 
17    Group shall report to the Commission on recommended 
18    improvements to interconnection rules and tariffs and 
19    policies as determined by the Interconnection Working 
20    Group at least every 6 months. Such reports shall include 
21    consensus recommendations of the Interconnection Working 
22    Group and, if applicable, additional recommendations for 
23    which consensus was not reached. The Commission shall use 
24    the report from the Interconnection Working Group to 
25    determine whether processes should be commenced to 
26    formally codify or implement the recommendations;
 
 
10400SB0025ham003- 665 -LRB104 07069 AAS 29208 a

1        (2) create or contract for an Ombudsman to resolve 
2    interconnection disputes through non-binding arbitration. 
3    The Ombudsman may be paid in full or in part through fees 
4    levied on the initiators of the dispute; and
5        (3) determine a single standardized cost for Level 1 
6    interconnections, which shall not exceed $200. 
7    (i) All electricity providers shall begin to offer net 
8metering no later than April 1, 2008.
9    (j) An electricity provider shall provide net metering to 
10eligible customers according to subsections (d), (d-5), and 
11(e). Eligible renewable electrical generating facilities for 
12which eligible customers registered for net metering before 
13January 1, 2025 shall continue to receive net metering 
14services according to subsections (d), (d-5), and (e) of this 
15Section for the lifetime of the system, regardless of whether 
16those retail customers change electricity providers or whether 
17the retail customer benefiting from the system changes. On and 
18after January 1, 2025, any eligible customer that applies for 
19net metering and previously would have qualified under 
20subsections (d), (d-5), or (e) shall only be eligible for net 
21metering as described in subsection (n). 
22    (k) Each electricity provider shall maintain records and 
23report annually to the Commission the total number of net 
24metering customers served by the provider, as well as the 
25type, capacity, and energy sources of the generating systems 
26used by the net metering customers. Nothing in this Section 
 
 
10400SB0025ham003- 666 -LRB104 07069 AAS 29208 a

1shall limit the ability of an electricity provider to request 
2the redaction of information deemed by the Commission to be 
3confidential business information.
4    (l)(1) Notwithstanding the definition of "eligible 
5customer" in item (ii) of subsection (b) of this Section, each 
6electricity provider shall allow net metering as set forth in 
7this subsection (l) and for the following projects, provided 
8that only electric utilities serving more than 200,000 
9customers as of January 1, 2021 shall provide net metering for 
10projects that are eligible for subparagraph (C) of this 
11paragraph (1) and have energized after the effective date of 
12this amendatory Act of the 102nd General Assembly: 
13        (A) properties owned or leased by multiple customers 
14    that contribute to the operation of an eligible renewable 
15    electrical generating facility through an ownership or 
16    leasehold interest of at least 200 watts in such facility, 
17    such as a community-owned wind project, a community-owned 
18    biomass project, a community-owned solar project, or a 
19    community methane digester processing livestock waste from 
20    multiple sources, provided that the facility is also 
21    located within the utility's service territory; 
22        (B) individual units, apartments, or properties 
23    located in a single building that are owned or leased by 
24    multiple customers and collectively served by a common 
25    eligible renewable electrical generating facility, such as 
26    an office or apartment building, a shopping center or 
 
 
10400SB0025ham003- 667 -LRB104 07069 AAS 29208 a

1    strip mall served by photovoltaic panels on the roof; and 
2        (C) subscriptions to community renewable generation 
3    projects, including community renewable generation 
4    projects on the customer's side of the billing meter of a 
5    host facility and partially used for the customer's own 
6    load.
7    In addition, the nameplate capacity of the eligible 
8renewable electric generating facility that serves the demand 
9of the properties, units, or apartments identified in 
10paragraphs (1) and (2) of this subsection (l) shall not exceed 
115,000 kilowatts in nameplate capacity in total. Any eligible 
12renewable electrical generating facility or community 
13renewable generation project that is powered by photovoltaic 
14electric energy and installed after the effective date of this 
15amendatory Act of the 99th General Assembly must be installed 
16by a qualified person in compliance with the requirements of 
17Section 16-128A of the Public Utilities Act and any rules or 
18regulations adopted thereunder.
19    (2) Notwithstanding anything to the contrary, an 
20electricity provider shall provide credits for the electricity 
21produced by the projects described in paragraph (1) of this 
22subsection (l). The electricity provider shall provide credits 
23that include at least energy supply, capacity, transmission, 
24and, if applicable, the purchased energy adjustment on the 
25subscriber's monthly bill equal to the subscriber's share of 
26the production of electricity from the project, as determined 
 
 
10400SB0025ham003- 668 -LRB104 07069 AAS 29208 a

1by paragraph (3) of this subsection (l). For customers with 
2transmission or capacity charges not charged on a 
3kilowatt-hour basis, the electricity provider shall prepare a 
4reasonable approximation of the kilowatt-hour equivalent value 
5and provide that value as a monetary credit. The electricity 
6provider shall submit these approximation methodologies to the 
7Commission for review, modification, and approval. 
8Notwithstanding anything to the contrary, customers on payment 
9plans or participating in budget billing programs shall have 
10credits applied on a monthly basis. 
11    (3) Notwithstanding anything to the contrary and 
12regardless of whether a subscriber to an eligible community 
13renewable generation project receives power and energy service 
14from the electric utility or an alternative retail electric 
15supplier, for projects eligible under paragraph (C) of 
16subparagraph (1) of this subsection (l), electric utilities 
17serving more than 200,000 customers as of January 1, 2021 
18shall provide the monetary credits to a subscriber's 
19subsequent bill for the electricity produced by community 
20renewable generation projects. The electric utility shall 
21provide monetary credits to a subscriber's subsequent bill at 
22the utility's total price to compare equal to the subscriber's 
23share of the production of electricity from the project, as 
24determined by paragraph (5) of this subsection (l). For the 
25purposes of this subsection, "total price to compare" means 
26the rate or rates published by the Illinois Commerce 
 
 
10400SB0025ham003- 669 -LRB104 07069 AAS 29208 a

1Commission for energy supply for eligible customers receiving 
2supply service from the electric utility, and shall include 
3energy, capacity, transmission, and the purchased energy 
4adjustment. Notwithstanding anything to the contrary, 
5customers on payment plans or participating in budget billing 
6programs shall have credits applied on a monthly basis. Any 
7applicable credit or reduction in load obligation from the 
8production of the community renewable generating projects 
9receiving a credit under this subsection shall be credited to 
10the electric utility to offset the cost of providing the 
11credit. To the extent that the credit or load obligation 
12reduction does not completely offset the cost of providing the 
13credit to subscribers of community renewable generation 
14projects as described in this subsection, the electric utility 
15may recover the remaining costs through its Multi-Year Rate 
16Plan. All electric utilities serving 200,000 or fewer 
17customers as of January 1, 2021 shall only provide the 
18monetary credits to a subscriber's subsequent bill for the 
19electricity produced by community renewable generation 
20projects if the subscriber receives power and energy service 
21from the electric utility. Alternative retail electric 
22suppliers providing power and energy service to a subscriber 
23located within the service territory of an electric utility 
24not subject to Sections 16-108.18 and 16-118 shall provide the 
25monetary credits to the subscriber's subsequent bill for the 
26electricity produced by community renewable generation 
 
 
10400SB0025ham003- 670 -LRB104 07069 AAS 29208 a

1projects.
2    (4) If requested by the owner or operator of a community 
3renewable generating project, an electric utility serving more 
4than 200,000 customers as of January 1, 2021 shall enter into a 
5net crediting agreement with the owner or operator to include 
6a subscriber's subscription fee on the subscriber's monthly 
7electric bill and provide the subscriber with a net credit 
8equivalent to the total bill credit value for that generation 
9period minus the subscription fee, provided the subscription 
10fee is structured as a fixed percentage of bill credit value. 
11The net crediting agreement shall set forth payment terms from 
12the electric utility to the owner or operator of the community 
13renewable generating project, and the electric utility may 
14charge a net crediting fee to the owner or operator of a 
15community renewable generating project that may not exceed 1%    
162% of the subscription fee bill credit value. Notwithstanding 
17anything to the contrary, an electric utility serving 200,000 
18customers or fewer as of January 1, 2021 shall not be obligated 
19to enter into a net crediting agreement with the owner or 
20operator of a community renewable generating project. An 
21electric utility shall use the same net crediting format for 
22subscribers on payment plans and subscribers participating in 
23budget billing programs. For the purposes of this paragraph 
24(4), "net crediting" means a program offered by an electric 
25utility under which the electric utility, upon authorization 
26by or on behalf of a subscriber, remits the cash value of the 
 
 
10400SB0025ham003- 671 -LRB104 07069 AAS 29208 a

1subscription fee to the owner or operator of the community 
2renewable generation facility without regard to whether the 
3subscriber has paid the subscriber's monthly electric bill and 
4places the cash value of the remaining bill credit on the 
5subscriber's bill.    
6    (5) For the purposes of facilitating net metering, the 
7owner or operator of the eligible renewable electrical 
8generating facility or community renewable generation project 
9shall be responsible for determining the amount of the credit 
10that each customer or subscriber participating in a project 
11under this subsection (l) is to receive in the following 
12manner: 
13        (A) The owner or operator shall, on a monthly basis, 
14    provide to the electric utility the kilowatthours of 
15    generation attributable to each of the utility's retail 
16    customers and subscribers participating in projects under 
17    this subsection (l) in accordance with the customer's or 
18    subscriber's share of the eligible renewable electric 
19    generating facility's or community renewable generation 
20    project's output of power and energy for such month. The 
21    owner or operator shall electronically transmit such 
22    calculations and associated documentation to the electric 
23    utility, in a format or method set forth in the applicable 
24    tariff, on a monthly basis so that the electric utility 
25    can reflect the monetary credits on customers' and 
26    subscribers' electric utility bills. The electric utility 
 
 
10400SB0025ham003- 672 -LRB104 07069 AAS 29208 a

1    shall be permitted to revise its tariffs to implement the 
2    provisions of this amendatory Act of the 102nd General 
3    Assembly. The owner or operator shall separately provide 
4    the electric utility with the documentation detailing the 
5    calculations supporting the credit in the manner set forth 
6    in the applicable tariff. 
7        (B) For those participating customers and subscribers 
8    who receive their energy supply from an alternative retail 
9    electric supplier, the electric utility shall remit to the 
10    applicable alternative retail electric supplier the 
11    information provided under subparagraph (A) of this 
12    paragraph (3) for such customers and subscribers in a 
13    manner set forth in such alternative retail electric 
14    supplier's net metering program, or as otherwise agreed 
15    between the utility and the alternative retail electric 
16    supplier. The alternative retail electric supplier shall 
17    then submit to the utility the amount of the charges for 
18    power and energy to be applied to such customers and 
19    subscribers, including the amount of the credit associated 
20    with net metering. 
21        (C) A participating customer or subscriber may provide 
22    authorization as required by applicable law that directs 
23    the electric utility to submit information to the owner or 
24    operator of the eligible renewable electrical generating 
25    facility or community renewable generation project to 
26    which the customer or subscriber has an ownership or 
 
 
10400SB0025ham003- 673 -LRB104 07069 AAS 29208 a

1    leasehold interest or a subscription. Such information 
2    shall be limited to the components of the net metering 
3    credit calculated under this subsection (l), including the 
4    bill credit rate, total kilowatthours, and total monetary 
5    credit value applied to the customer's or subscriber's 
6    bill for the monthly billing period. 
7    (l-5) Within 90 days after the effective date of this 
8amendatory Act of the 102nd General Assembly, each electric 
9utility subject to this Section shall file a tariff or tariffs 
10to implement the provisions of subsection (l) of this Section, 
11which shall, consistent with the provisions of subsection (l), 
12describe the terms and conditions under which owners or 
13operators of qualifying properties, units, or apartments may 
14participate in net metering. The Commission shall approve, or 
15approve with modification, the tariff within 120 days after 
16the effective date of this amendatory Act of the 102nd General 
17Assembly. 
18    (l-10) Within 30 days after the effective date of this 
19amendatory Act of the 104th General Assembly, each electricity 
20provider shall modify its tariffs to allow net metering as set 
21forth in this subsection for an energy storage system or 
22vehicle storage system energized after the effective date of 
23this amendatory Act of the 104th General Assembly with a 
24nameplate capacity of not more than 5,000 kilowatts. If the 
25Commission chooses to suspend the modified tariffs, the 
26Commission shall issue a final order approving, or approving 
 
 
10400SB0025ham003- 674 -LRB104 07069 AAS 29208 a

1with modification, the modified tariffs no later than 90 days 
2after the utility files its tariffs.    
3    An energy storage system or vehicle storage system 
4eligible for net metering under this subsection may be 
5interconnected behind the meter of a retail customer or at the 
6distribution system level of an electric utility as follows:
7        (A) if the energy storage system or vehicle storage 
8    system is interconnected behind the meter of a retail 
9    customer, in order to receive net metering under this 
10    subsection, the eligible customer behind whose meter the 
11    energy storage system is interconnected must receive 
12    service from an electricity provider under an hourly 
13    supply tariff, a time-of-use supply tariff, or a 
14    time-of-use contract with an alternative retail electric 
15    supplier; or
16        (B) if the energy storage system or vehicle storage 
17    system is interconnected at the distribution system level 
18    of an electric utility and not behind the meter of a retail 
19    customer, the energy storage system or vehicle storage 
20    system must receive service from an electricity provider 
21    as a retail customer under an hourly supply tariff 
22    authorized by Section 16-107, a supply tariff or contract 
23    on substantially similar terms and conditions with an 
24    alternative retail electric supplier, a time-of-use supply 
25    tariff, or a time-of-use supply contract with an 
26    alternative retail electric supplier.
 
 
10400SB0025ham003- 675 -LRB104 07069 AAS 29208 a

1    If the energy storage system or vehicle storage system is 
2interconnected behind the meter of an eligible customer, the 
3eligible customer shall receive net metering based on hourly 
4or time-of-use rates in accordance with the terms of 
5subsection (d-5) or (f) or paragraph (2) of subsection (n) of 
6this Section, as applicable to the eligible customer. If the 
7energy storage system or vehicle storage system is 
8interconnected at the distribution system level of an electric 
9utility and not behind the meter of a retail customer, then the 
10energy storage system or vehicle storage system shall receive 
11net metering pursuant to the terms of subsection (f) of this 
12Section.    
13    (m) Nothing in this Section shall affect the right of an 
14electricity provider to continue to provide, or the right of a 
15retail customer to continue to receive service pursuant to a 
16contract for electric service between the electricity provider 
17and the retail customer in accordance with the prices, terms, 
18and conditions provided for in that contract. Either the 
19electricity provider or the customer may require compliance 
20with the prices, terms, and conditions of the contract. 
21    (n) On and after January 1, 2025, the net metering 
22services described in subsections (d), (d-5), and (e) of this 
23Section shall no longer be offered, except as to those 
24eligible renewable electrical generating facilities for which 
25retail customers are receiving net metering service under 
26these subsections at the time the net metering services under 
 
 
10400SB0025ham003- 676 -LRB104 07069 AAS 29208 a

1those subsections are no longer offered; those systems shall 
2continue to receive net metering services described in 
3subsections (d), (d-5), and (e) of this Section for the 
4lifetime of the system, regardless of if those retail 
5customers change electricity providers or whether the retail 
6customer benefiting from the system changes. The electric 
7utility serving more than 200,000 customers as of January 1, 
82021 is responsible for ensuring the billing credits continue 
9without lapse for the lifetime of systems, as required in 
10subsection (o). Those retail customers that begin taking net 
11metering service after the date that net metering services are 
12no longer offered under such subsections shall be subject to 
13the provisions set forth in the following paragraphs (1) 
14through (3) of this subsection (n):
15        (1) An electricity provider shall charge or credit for 
16    the net electricity supplied to eligible customers or 
17    provided by eligible customers whose electric supply 
18    service is not provided based on hourly pricing in the 
19    following manner:
20            (A) If the amount of electricity used by the 
21        customer during the monthly billing period exceeds the 
22        amount of electricity produced by the customer, then 
23        the electricity provider shall charge the customer for 
24        the net kilowatt-hour based electricity charges 
25        reflected in the customer's electric service rate 
26        supplied to and used by the customer as provided in 
 
 
10400SB0025ham003- 677 -LRB104 07069 AAS 29208 a

1        paragraph (3) of this subsection (n).
2            (B) If the amount of electricity produced by a 
3        customer during the monthly billing period exceeds the 
4        amount of electricity used by the customer during that 
5        billing period, then the electricity provider 
6        supplying that customer shall apply a 1:1 
7        kilowatt-hour energy or monetary credit kilowatt-hour 
8        supply charges to the customer's subsequent bill. The 
9        customer shall choose between 1:1 kilowatt-hour or 
10        monetary credit at the time of application. For the 
11        purposes of this subsection, "kilowatt-hour supply 
12        charges" means the kilowatt-hour equivalent values for 
13        energy, capacity, transmission, and the purchased 
14        energy adjustment, if applicable. Notwithstanding 
15        anything to the contrary, customers on payment plans 
16        or participating in budget billing programs shall have 
17        credits applied on a monthly basis. The electricity 
18        provider shall continue to carry over any excess 
19        kilowatt-hour or monetary energy credits earned and 
20        apply those credits to subsequent billing periods. For 
21        customers with transmission or capacity charges not 
22        charged on a kilowatt-hour basis, the electricity 
23        provider shall prepare a reasonable approximation of 
24        the kilowatt-hour equivalent value and provide that 
25        value as a monetary credit. The electricity provider 
26        shall submit these approximation methodologies to the 
 
 
10400SB0025ham003- 678 -LRB104 07069 AAS 29208 a

1        Commission for review, modification, and approval.
2            (C) (Blank).
3        (2) An electricity provider shall charge or credit for 
4    the net electricity supplied to eligible customers or 
5    provided by eligible customers whose electric supply 
6    service is provided based on hourly pricing in the 
7    following manner:
8            (A) If the amount of electricity used by the 
9        customer during any hourly period exceeds the amount 
10        of electricity produced by the customer, then the 
11        electricity provider shall charge the customer for the 
12        net electricity supplied to and used by the customer 
13        as provided in paragraph (3) of this subsection (n).
14            (B) If the amount of electricity produced by a 
15        customer during any hourly period exceeds the amount 
16        of electricity used by the customer during that hourly 
17        period, the energy provider shall calculate an energy 
18        credit for the net kilowatt-hours produced in such 
19        period, and shall apply that credit as a monetary 
20        credit to the customer's subsequent bill. The value of 
21        the energy credit shall be calculated using the same 
22        price per kilowatt-hour as the electric service 
23        provider would charge for kilowatt-hour energy sales 
24        during that same hourly period and shall also include 
25        values for capacity and transmission. For customers 
26        with transmission or capacity charges not charged on a 
 
 
10400SB0025ham003- 679 -LRB104 07069 AAS 29208 a

1        kilowatt-hour basis, the electricity provider shall 
2        prepare a reasonable approximation of the 
3        kilowatt-hour equivalent value and provide that value 
4        as a monetary credit. The electricity provider shall 
5        submit these approximation methodologies to the 
6        Commission for review, modification, and approval. 
7        Notwithstanding anything to the contrary, customers on 
8        payment plans or participating in budget billing 
9        programs shall have credits applied on a monthly 
10        basis. 
11        (3) An electricity provider shall provide electric 
12    service to eligible customers who utilize net metering at 
13    non-discriminatory rates that are identical, with respect 
14    to rate structure, retail rate components, and any monthly 
15    charges, to the rates that the customer would be charged 
16    if not a net metering customer. An electricity provider 
17    shall charge the customer for the net electricity supplied 
18    to and used by the customer according to the terms of the 
19    contract or tariff to which the same customer would be 
20    assigned or be eligible for if the customer was not a net 
21    metering customer. An electricity provider shall not 
22    charge net metering customers any fee or charge or require 
23    additional equipment, insurance, or any other requirements 
24    not specifically authorized by interconnection standards 
25    authorized by the Commission, unless the fee, charge, or 
26    other requirement would apply to other similarly situated 
 
 
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1    customers who are not net metering customers. The customer 
2    remains responsible for the gross amount of delivery 
3    services charges, supply-related charges that are kilowatt 
4    based, and all taxes and fees related to such charges. The 
5    customer also remains responsible for all taxes and fees 
6    that would otherwise be applicable to the net amount of 
7    electricity used by the customer. Paragraphs (1) and (2) 
8    of this subsection (n) shall not be construed to prevent 
9    an arms-length agreement between an electricity provider 
10    and an eligible customer that sets forth different prices, 
11    terms, and conditions for the provision of net metering 
12    service, including, but not limited to, the provision of 
13    the appropriate metering equipment for non-residential 
14    customers. Nothing in this paragraph (3) shall be 
15    interpreted to mandate that a utility that is only 
16    required to provide delivery services to a given customer 
17    must also sell electricity to such customer. 
18    (o) Within 90 days after the effective date of this 
19amendatory Act of the 102nd General Assembly, each electric 
20utility subject to this Section shall file a tariff, which 
21shall, consistent with the provisions of this Section, propose 
22the terms and conditions under which a customer may 
23participate in net metering. The tariff for electric utilities 
24serving more than 200,000 customers as of January 1, 2021 
25shall also provide a streamlined and transparent bill 
26crediting system for net metering to be managed by the 
 
 
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1electric utilities. The terms and conditions shall include, 
2but are not limited to, that an electric utility shall manage 
3and maintain billing of net metering credits and charges 
4regardless of if the eligible customer takes net metering 
5under an electric utility or alternative retail electric 
6supplier. The electric utility serving more than 200,000 
7customers as of January 1, 2021 shall process and approve all 
8net metering applications, even if an eligible customer is 
9served by an alternative retail electric supplier; and the 
10utility shall forward application approval to the appropriate 
11alternative retail electric supplier. Eligibility for net 
12metering shall remain with the owner of the utility billing 
13address such that, if an eligible renewable electrical 
14generating facility changes ownership, the net metering 
15eligibility transfers to the new owner. The electric utility 
16serving more than 200,000 customers as of January 1, 2021 
17shall manage net metering billing for eligible customers to 
18ensure full crediting occurs on electricity bills, including, 
19but not limited to, ensuring net metering crediting begins 
20upon commercial operation date, net metering billing transfers 
21immediately if an eligible customer switches from an electric 
22utility to alternative retail electric supplier or vice versa, 
23and net metering billing transfers between ownership of a 
24valid billing address. All transfers referenced in the 
25preceding sentence shall include transfer of all banked 
26credits. All electric utilities serving 200,000 or fewer 
 
 
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1customers as of January 1, 2021 shall manage net metering 
2billing for eligible customers receiving power and energy 
3service from the electric utility to ensure full crediting 
4occurs on electricity bills, ensuring net metering crediting 
5begins upon commercial operation date, net metering billing 
6transfers immediately if an eligible customer switches from an 
7electric utility to alternative retail electric supplier or 
8vice versa, and net metering billing transfers between 
9ownership of a valid billing address. Alternative retail 
10electric suppliers providing power and energy service to 
11eligible customers located within the service territory of an 
12electric utility serving 200,000 or fewer customers as of 
13January 1, 2021 shall manage net metering billing for eligible 
14customers to ensure full crediting occurs on electricity 
15bills, including, but not limited to, ensuring net metering 
16crediting begins upon commercial operation date, net metering 
17billing transfers immediately if an eligible customer switches 
18from an electric utility to alternative retail electric 
19supplier or vice versa, and net metering billing transfers 
20between ownership of a valid billing address. 
21(Source: P.A. 102-662, eff. 9-15-21.)
 
22    (220 ILCS 5/16-107.6)
23    Sec. 16-107.6. Distributed generation and storage rebate.
24    (a) In this Section:
25    "Additive services" means the services that distributed 
 
 
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1energy resources provide to the energy system and society that 
2are described in Section 16-107.9 not (1) already included in 
3the base rebates for system-wide grid services; or (2) 
4otherwise already compensated. Additive services may reflect, 
5but shall not be limited to, any geographic, time-based, 
6performance-based, and other benefits of distributed energy 
7resources, as well as the present and future technological 
8capabilities of distributed energy resources and present and 
9future grid needs. 
10    "Distributed energy resource" means a wide range of 
11technologies that are located on the customer side of the 
12customer's electric meter, including, but not limited to, 
13distributed generation, energy storage, electric vehicles, and 
14demand response technologies. 
15    "Distributed storage" means energy storage systems that 
16are interconnected behind the customer's meter to the 
17distribution system or interconnected behind the storage 
18system's own meter to the distribution system.    
19    "Energy storage system" means commercially available 
20technology that is capable of absorbing energy and storing it 
21for a period of time for use at a later time, including, but 
22not limited to, electrochemical, thermal, and 
23electromechanical technologies, and may be interconnected 
24behind the customer's meter or interconnected behind its own 
25meter. 
26    "Smart inverter" means a device that converts direct 
 
 
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1current into alternating current and meets the IEEE 1547-2018 
2equipment standards. Until devices that meet the IEEE 
31547-2018 standard are available, devices that meet the UL 
41741 SA standard are acceptable.
5    "Subscriber" has the meaning set forth in Section 1-10 of 
6the Illinois Power Agency Act.
7    "Subscription" has the meaning set forth in Section 1-10 
8of the Illinois Power Agency Act.
9    "System-wide grid services" means the benefits that a 
10distributed energy resource provides to the distribution grid 
11for a period of no less than 25 years. System-wide grid 
12services do not vary by location, time, or the performance 
13characteristics of the distributed energy resource. 
14System-wide grid services include, but are not limited to, 
15avoided or deferred distribution capacity costs, resilience 
16and reliability benefits, avoided or deferred distribution 
17operation and maintenance costs, distribution voltage and 
18power quality benefits, and line loss reductions. 
19    "Threshold date" means the date 2 years after the 
20effective date of this amendatory Act of the 104th General 
21Assembly December 31, 2024 or the date on which the utility's 
22tariff or tariffs authorized by Section 16-107.9 setting the 
23new compensation values established under subsection (e) take 
24effect, whichever is later.
25    (b) An electric utility that serves more than 200,000 
26customers in the State shall file a petition with the 
 
 
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1Commission requesting approval of the utility's tariff to 
2provide a rebate to the owner or operator of distributed 
3generation, including third-party owned systems, that meets 
4the following criteria:
5        (1) has a nameplate generating capacity no greater 
6    than 5,000 kilowatts and is primarily used to offset a 
7    customer's electricity load;
8        (2) is located on the customer's side of the billing 
9    meter and for the customer's own use;
10        (3) is interconnected to electric distribution 
11    facilities owned by the electric utility under rules 
12    adopted by the Commission by means of one or more 
13    inverters or smart inverters required by this Section, as 
14    applicable.
15    For purposes of this Section, "distributed generation" 
16shall satisfy the definition of distributed renewable energy 
17generation device set forth in Section 1-10 of the Illinois 
18Power Agency Act to the extent such definition is consistent 
19with the requirements of this Section. 
20    In addition, any new photovoltaic distributed generation 
21that is installed after June 1, 2017 (the effective date of 
22Public Act 99-906) must be installed by a qualified person, as 
23defined by subsection (i) of Section 1-56 of the Illinois 
24Power Agency Act. 
25    The tariff shall include a base rebate that compensates 
26distributed generation for the system-wide grid services 
 
 
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1associated with distributed generation and, after the 
2proceeding described in subsection (e) of this Section, an 
3additional payment or payments for any the additive services 
4identified by the Commission under Section 16-107.9. The 
5distributed generation and storage tariff shall provide that 
6the smart inverter or smart inverters associated with the 
7distributed generation shall provide autonomous response to 
8grid conditions through its default settings as approved by 
9the Commission. Default settings may not be changed after the 
10execution of the interconnection agreement except by mutual 
11agreement between the utility and the owner or operator of the 
12distributed generation. Nothing in this Section shall negate 
13or supersede Institute of Electrical and Electronics Engineers 
14equipment standards or other similar standards or 
15requirements. The tariff shall not limit the ability of the 
16smart inverter or smart inverters or other distributed energy 
17resource to provide wholesale market products such as 
18regulation, demand response, or other services, or limit the 
19ability of the owner of the smart inverter or the other 
20distributed energy resource to receive compensation for 
21providing those wholesale market products or services.
22    (b-5) Within 30 days after the effective date of this 
23amendatory Act of the 102nd General Assembly, each electric 
24public utility with 3,000,000 or more retail customers shall 
25file a tariff with the Commission that further compensates any 
26retail customer that installs or has installed photovoltaic 
 
 
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1facilities paired with energy storage facilities on or 
2adjacent to its premises for the benefits the facilities 
3provide to the distribution grid. The tariff shall provide 
4that, in addition to the other rebates identified in this 
5Section, the electric utility shall rebate to such retail 
6customer (i) the previously incurred and future costs of 
7installing interconnection facilities and related 
8infrastructure to enable full participation in the PJM 
9Interconnection, LLC or its successor organization frequency 
10regulation market; and (ii) all wholesale demand charges 
11incurred after the effective date of this amendatory Act of 
12the 102nd General Assembly. The Commission shall approve, or 
13approve with modification, the tariff within 120 days after 
14the utility's filing. 
15    To be eligible for a rebate described in this subsection 
16(b-5), the owner or operator of the distributed generation 
17shall provide proof of participation in the frequency 
18regulation market. Upon providing proof of participation, the 
19retail customer shall be entitled to a rebate equal to the cost 
20of the interconnection facilities paid to ComEd, regardless of 
21whether the retail customer would have incurred the 
22interconnection costs in the absence of participating in the 
23frequency regulation market, plus the cost of software, 
24telecommunications hardware, and telemetry paid to enable 
25communication with PJM for purposes of participating in the 
26frequency regulation market. A utility providing rebates 
 
 
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1described in this subsection (b-5) shall be entitled to 
2recover the costs of the rebates as provided for in subsection 
3(h) of this Section. To the extent the electric utility's 
4tariff shall be modified to comply with this subsection (b-5), 
5it shall file a revised tariff with the Commission within 120 
6days after the effective date of this amendatory Act of the 
7104th General Assembly, and the Commission shall approve, or 
8approve with modification, the tariff within 240 days after 
9the utility's filing.    
10    (c) The proposed tariff authorized by subsection (b) of 
11this Section shall include the following participation terms 
12for rebates to be applied under this Section for distributed 
13generation that satisfies the criteria set forth in subsection 
14(b) of this Section:
15        (1) The owner or operator of distributed generation or 
16    distributed storage that services customers not eligible 
17    for net metering under subsection (d), (d-5), or (e) of 
18    Section 16-107.5 of this Act may apply for a rebate as 
19    provided for in this Section. The Until the threshold 
20    date, the value of the rebate shall be $250 per kilowatt of 
21    nameplate generating capacity, measured as nominal DC 
22    power output, of that customer's distributed generation. 
23    To the extent the distributed generation also has an 
24    associated energy storage, then until the threshold date 
25    for systems other than community renewable generation 
26    projects paired with an energy storage system, the energy 
 
 
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1    storage system shall be separately compensated with a base    
2    rebate of $250 per kilowatt-hour of nameplate capacity. To 
3    the extent that a community renewable generation project 
4    is paired with an energy storage system or an energy 
5    storage system that is paired with distributed generation, 
6    the energy storage system shall be separately compensated 
7    with a rebate of $250 per kilowatt-hour of nameplate 
8    capacity. Any distributed generation device that is 
9    compensated for storage in this subsection (1) after the 
10    effective date of this amendatory Act of the 104th General 
11    Assembly before the threshold date shall participate in 
12    one or more programs authorized by paragraph (1) of 
13    subsection (e). Compensation determined through the 
14    Multi-Year Integrated Grid Planning process that are 
15    designed to meet peak reduction and flexibility. After the 
16    threshold date, the value of the base rebate and 
17    additional compensation for any additive services shall be 
18    as determined by the Commission in the proceeding 
19    described in Section 16-107.9 subsection (e) of this 
20    Section, provided that the value of the base rebate for 
21    system-wide grid services shall not be lower than $250 per 
22    kilowatt of nameplate generating capacity of distributed 
23    generation or community renewable generation project. To 
24    the extent that an electric utility's tariffs are 
25    inconsistent with the requirements of this paragraph (1) 
26    as modified by this amendatory Act of the 104th General 
 
 
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1    Assembly, the electric utility shall, within 60 days after 
2    the effective date of this amendatory Act of the 104th 
3    General Assembly, file modified tariffs consistent with 
4    the requirements of this paragraph (1). If the Commission 
5    chooses to suspend the modified tariffs following notice 
6    and hearing, the Commission shall issue an order 
7    approving, or approving with modification, the modified 
8    tariffs no later than 90 days after the utility files its 
9    tariff.    
10        (2) The owner or operator of distributed generation 
11    that, before the threshold date, would have been eligible 
12    for net metering under subsection (d), (d-5), or (e) of 
13    Section 16-107.5 of this Act and that has not previously 
14    received a distributed generation rebate, may apply for a 
15    rebate as provided for in this Section. Until December 31, 
16    2029 the threshold date, the value of the base rebate 
17    shall be $300 per kilowatt of nameplate generating 
18    capacity, measured as nominal DC power output, of the 
19    distributed generation. On or after January 1, 2030, the 
20    value of the base rebate shall be $250 per kilowatt of 
21    nameplate generating capacity, measured as nominal DC 
22    power output, of the distributed generation. The owner or 
23    operator of distributed generation that, before the 
24    threshold date, is eligible for net metering under 
25    subsection (d), (d-5), or (e) of Section 16-107.5 of this 
26    Act may apply for a base rebate for an associated energy 
 
 
10400SB0025ham003- 691 -LRB104 07069 AAS 29208 a

1    storage device behind the same retail customer meter as 
2    the distributed generation, regardless of whether the 
3    distributed generation applies for a rebate for the 
4    distributed generation device. An The energy storage 
5    system, whether or not paired with distributed generation,    
6    shall be separately compensated at a base payment of $300 
7    per kilowatt-hour of nameplate capacity until the 
8    threshold date. Any distributed generation device that is 
9    compensated for storage in this subsection (2) has the 
10    option to before the threshold date shall participate in 
11    either an a peak time rebate program, hourly pricing 
12    program, or time-of-use rate program and any distributed 
13    generation device that is compensated for storage in this 
14    subsection (2) after the effective date of this amendatory 
15    Act of the 104th General Assembly shall participate in a 
16    scheduled dispatch program set forth in paragraph (1) of 
17    subsection (e) when it becomes available offered by the 
18    applicable electric utility. Compensation After the 
19    threshold date, the value of the base rebate and 
20    additional compensation for any additive services or other 
21    programs shall be as determined by the Commission in the 
22    proceeding described in Section 16-107.9 subsection (e) of 
23    this Section, provided that, prior to December 31, 2029, 
24    the value of the base rebate for system-wide services 
25    shall not be lower than $300 per kilowatt of nameplate 
26    generating capacity of distributed generation, after which 
 
 
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1    it shall not be lower than $250 per kilowatt of nameplate 
2    capacity. The eligibility of energy storage devices that 
3    are interconnected behind the same retail customer meter 
4    as the distributed generation shall not be limited to 
5    energy storage devices interconnected after the effective 
6    date of this amendatory Act of the 103rd General Assembly. 
7    To the extent that an electric utility's tariffs are 
8    inconsistent with the requirements of this paragraph (2) 
9    as modified by this amendatory Act of the 104th General 
10    Assembly this amendatory Act of the 103rd General 
11    Assembly, such electric utility shall, within 60 30 days, 
12    file modified tariffs consistent with the requirements of 
13    this paragraph (2). 
14        (3) Upon approval of a rebate application submitted 
15    under this subsection (c), the retail customer shall no 
16    longer be entitled to receive any delivery service credits 
17    for the excess electricity generated by its facility and 
18    shall be subject to the provisions of subsection (n) of 
19    Section 16-107.5 of this Act unless the owner or operator 
20    receives a rebate only for an energy storage device and 
21    not for the distributed generation device.
22        (4) To be eligible for a rebate described in this 
23    subsection (c), the owner or operator of the distributed 
24    generation must have a smart inverter installed and in 
25    operation on the distributed generation.
26        (5) The owner or operator of any distributed 
 
 
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1    generation or distributed storage system whose electric 
2    service has not been declared competitive under Section 
3    16-113 as of July 1, 2011 or the owner or operator of a 
4    community renewable generation project participating in 
5    the Adjustable Block Program as a community-driven 
6    community solar project as defined in item (v) of 
7    subparagraph (K) of paragraph (1) of subsection (c) of 
8    Section 1-75 of the Illinois Power Agency Act and that has 
9    an interconnection agreement dated after the effective 
10    date of this amendatory Act of the 104th General Assembly 
11    shall be eligible for an additional payment or payments to 
12    the applicable rebate under paragraphs (1) or (2) of this 
13    subsection (c) in an amount set by tariff and approved by 
14    the Commission if located in an equity investment eligible 
15    community, as defined in Section 1-10 of the Illinois 
16    Power Agency Act, at the time the interconnection 
17    agreement is signed.    
18    (d) The Commission shall review the proposed tariff 
19authorized by subsection (b) of this Section and may make 
20changes to the tariff that are consistent with this Section 
21and with the Commission's authority under Article IX of this 
22Act, subject to notice and hearing. Following notice and 
23hearing, the Commission shall issue an order approving, or 
24approving with modification, such tariff no later than 240 
25days after the utility files its tariff. Upon the effective 
26date of this amendatory Act of the 102nd General Assembly, an 
 
 
10400SB0025ham003- 694 -LRB104 07069 AAS 29208 a

1electric utility shall file a petition with the Commission to 
2amend and update any existing tariffs to comply with 
3subsections (b) and (c). 
4    (e) By no later than June 30, 2026 June 30, 2023, the 
5Commission shall establish a scheduled dispatch virtual power 
6plant program in which customers that own or operate an energy 
7storage system that receive a rebate for the distributed 
8storage portion under paragraphs (1) and (2) of subsection (c) 
9are required to participate open an independent, statewide 
10investigation into the value of, and compensation for, 
11distributed energy resources. The Commission shall conduct the 
12investigation, but may arrange for experts or consultants 
13independent of the utilities and selected by the Commission to 
14assist with the investigation. The cost of the investigation 
15shall be shared by the utilities filing tariffs under 
16subsection (b) of this Section but may be recovered as an 
17expense through normal ratemaking procedures.
18        (1) The scheduled dispatch virtual power plant program 
19    shall require an enrollment period of 5 years and require 
20    each participating system to commit to dispatch each 
21    weekday during the months of June, July, August, and 
22    September from 4 p.m. to 6 p.m. for systems interconnected 
23    behind the meter of a retail customer and from 4 p.m. to 7 
24    p.m. for systems interconnected on the distribution system 
25    of an electric utility and not behind the meter of a retail 
26    customer. Upon petition by the applicable electric utility 
 
 
10400SB0025ham003- 695 -LRB104 07069 AAS 29208 a

1    or on its own motion, the Commission may approve different 
2    dispatch schedules provided that dispatch events do not 
3    exceed 80 days and shall not exceed 2 hours for systems 
4    interconnected behind the meter of a retail customer or 3 
5    hours for systems interconnected on the distribution 
6    system of an electric utility and not behind the meter of a 
7    retail customer. The Commission shall ensure that the 
8    investigation includes, at minimum, diverse sets of 
9    stakeholders; a review of best practices in calculating 
10    the value of distributed energy resource benefits; a 
11    review of the full value of the distributed energy 
12    resources and the manner in which each component of that 
13    value is or is not otherwise compensated; and assessments 
14    of how the value of distributed energy resources may 
15    evolve based on the present and future technological 
16    capabilities of distributed energy resources and based on 
17    present and future grid needs.    
18        (2) The scheduled dispatch virtual power plant program 
19    shall be open to all customer classes with eligible 
20    distributed energy resources and shall measure performance 
21    based on combined export of paired resources if the 
22    eligible device is inverter-based renewables paired with 
23    storage through at least December 31, 2030 and until such 
24    time as the Commission approves and the utility implements 
25    a tariff under subsection (d) of Section 16-107.9 of this 
26    Act, at which time such customers shall be transitioned to 
 
 
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1    that tariff in a manner prescribed in the tariff. The 
2    scheduled dispatch virtual power plant program shall be 
3    required for all community renewable generation projects 
4    paired with distributed energy resources without regard to 
5    the threshold date. The Commission's final order 
6    concluding this investigation shall establish an annual 
7    process and formula for the compensation of distributed 
8    generation and energy storage systems, and an initial set 
9    of inputs for that formula. The Commission's final order 
10    concluding this investigation shall establish base rebates 
11    that compensate distributed generation, community 
12    renewable generation projects and energy storage systems 
13    for the system-wide grid services that they provide. Those 
14    base rebate values shall be consistent across the state, 
15    and shall not vary by customer, customer class, customer 
16    location, or any other variable. With respect to rebates 
17    for distributed generation or community renewable 
18    generation projects, that rebate shall not be lower than 
19    $250 per kilowatt of nameplate generating capacity of the 
20    distributed generation or community renewable generation 
21    project. The Commission's final order concluding this 
22    proceeding shall also direct the utilities to update the 
23    formula, on an annual basis, with inputs derived from 
24    their integrated grid plans developed pursuant to Section 
25    16-105.17. The base rebate shall be updated annually based 
26    on the annual updates to the formula inputs, but, with 
 
 
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1    respect to rebates for distributed generation or community 
2    renewable generation projects, shall be no lower than $250 
3    per kilowatt of nameplate generating capacity of the 
4    distributed generation or community renewable generation 
5    project.
6        (3) Compensation shall be set by the Commission but 
7    shall not be less than $10 per kilowatt of average 
8    dispatch during identified hours, paid to enrolled 
9    customers or project owners at end of program year. For 
10    distributed generation interconnected to an electric 
11    utility's distribution system and not behind the meter of 
12    a retail customer, dispatch to determine compensation 
13    shall be measured at point of interconnection. For 
14    distributed generation and storage interconnected behind 
15    the meter of a retail customer, dispatch to determine 
16    compensation shall be measured at the inverter connected 
17    to the storage device. The Commission shall also 
18    determine, as a part of its investigation under this 
19    subsection, whether distributed energy resources can 
20    provide any additive services. Those additive services may 
21    include services that are provided through 
22    utility-controlled responses to grid conditions. If the 
23    Commission determines that distributed energy resources 
24    can provide additive grid services, the Commission shall 
25    determine the terms and conditions for the operation and 
26    compensation of those services. That compensation shall be 
 
 
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1    above and beyond the base rebate that the distributed 
2    energy generation, community renewable generation project 
3    and energy storage system receives. Compensation for 
4    additive services may vary by location, time, performance 
5    characteristics, technology types, or other variables.
6        (4) No later than June 1, 2026, each public utility 
7    shall file an initial scheduled dispatch virtual power 
8    plant tariff. The Commission shall approve, or approve 
9    with modifications, the initial scheduled dispatch virtual 
10    power plant tariff for each utility not later than June 
11    30, 2026. The Commission shall ensure that compensation 
12    for distributed energy resources, including base rebates 
13    and any payments for additive services, shall reflect all 
14    reasonably known and measurable values of the distributed 
15    generation over its full expected useful life. 
16    Compensation for additive services shall reflect, but 
17    shall not be limited to, any geographic, time-based, 
18    performance-based, and other benefits of distributed 
19    generation, as well as the present and future 
20    technological capabilities of distributed energy resources 
21    and present and future grid needs.
22        (5) The Commission, by its own motion or by petition 
23    by an electric utility, may establish other additive 
24    services programs in addition to the virtual power plant 
25    program under Section 16-107.9. Nothing in this Section is 
26    intended to preempt or delay the implementation of other 
 
 
10400SB0025ham003- 699 -LRB104 07069 AAS 29208 a

1    utility programs for devices that are not a part of the 
2    scheduled dispatch virtual power plant program that the 
3    Commission or utility may propose or require. The 
4    Commission shall consider the electric utility's 
5    integrated grid plan developed pursuant to Section 
6    16-105.17 of this Act to help identify the value of 
7    distributed energy resources for the purpose of 
8    calculating the compensation described in this subsection.    
9        (6) No later than December 31, 2028, the utilities 
10    shall file with the Commission a report that includes 
11    information on the following: (A) the number of 
12    participants in the scheduled dispatch program; (B) 
13    impacts to energy supply prices and wholesale market 
14    activities; (C) impacts on distribution system investments 
15    and planning; and (D) any potential pathways by which the 
16    virtual power plan program described in Section 16-107.9 
17    may be designed to capture wholesale market value through 
18    participation in the wholesale market and apply that 
19    wholesale market revenue to reduce utility distribution or 
20    electric supply rates for customers. The Commission shall 
21    determine additional compensation for distributed energy 
22    resources that creates savings and value on the 
23    distribution system by being co-located or in close 
24    proximity to electric vehicle charging infrastructure in 
25    use by medium-duty and heavy-duty vehicles, primarily 
26    serving environmental justice communities, as outlined in 
 
 
10400SB0025ham003- 700 -LRB104 07069 AAS 29208 a

1    the utility integrated grid planning process under Section 
2    16-105.17 of this Act.    
3    No later than 60 days after the Commission enters its 
4final order under this subsection (e), each utility shall file 
5its updated tariff or tariffs in compliance with the order, 
6including new tariffs for the recovery of costs incurred under 
7this subsection (e) that shall provide for volumetric-based 
8cost recovery, and the Commission shall approve, or approve 
9with modification, the tariff or tariffs within 240 days after 
10the utility's filing.    
11    (f) Notwithstanding any provision of this Act to the 
12contrary, the owner or operator of a community renewable 
13generation project as defined in Section 1-10 of the Illinois 
14Power Agency Act whether or not a paired energy storage system 
15or the owner or operator of an energy storage system that is 
16eligible for net metering under subsection (l-10) of Section 
1716-107.5 shall also be eligible to apply for the rebate 
18described in this Section. The owner or operator of the 
19community renewable generation project whether or not a paired 
20energy storage system or the owner or operator of an energy 
21storage system that is eligible for net metering under 
22subsection (l-10) of Section 16-107.5 may apply for a rebate 
23only if the owner or operator, or previous owner or operator, 
24of the community renewable generation project whether or not a 
25paired energy storage system or the owner or operator of an 
26energy storage system that is eligible for net metering under 
 
 
10400SB0025ham003- 701 -LRB104 07069 AAS 29208 a

1subsection (l-10) of Section 16-107.5 has not already 
2submitted an application, and, regardless of whether the 
3subscriber is a residential or non-residential customer, may 
4be allowed the amount identified in paragraph (1) of 
5subsection (c) applicable on the date that the application is 
6submitted.
7    (g) The owner of a distributed storage system, whether or 
8not paired with distributed generation, the distributed 
9generation or community renewable generation project may apply 
10for the rebate or rebates approved under this Section at the 
11time of execution of an interconnection agreement with the 
12distribution utility and shall receive the value available at 
13that time of execution of the interconnection agreement, 
14provided the project reaches mechanical completion within 24 
15months after execution of the interconnection agreement. If 
16the project has not reached mechanical completion within 24 
17months after execution, the owner may reapply for the rebate 
18or rebates approved under this Section available at the time 
19of application and shall receive the value available at the 
20time of application. The utility shall issue the rebate no 
21later than 60 days after the project is energized. In the event 
22the application is incomplete or the utility is otherwise 
23unable to calculate the payment based on the information 
24provided by the owner, the utility shall issue the payment no 
25later than 60 days after the application is complete or all 
26requested information is received.
 
 
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1    (h) An electric utility shall recover from its retail 
2customers all of the costs of the rebates made under a tariff 
3or tariffs approved under subsection (d) of this Section, 
4including, but not limited to, the value of the rebates and all 
5costs incurred by the utility to comply with and implement 
6subsections (b), (b-5), and (c), and (e) of this Section, but 
7not including costs incurred by the utility to comply with and 
8implement subsection (e) of this Section, consistent with the 
9following provisions:
10        (1) The utility shall defer the full amount of its 
11    costs as a regulatory asset. The total costs deferred as a 
12    regulatory asset shall be amortized over a 15-year period. 
13    The unamortized balance shall be recognized as of December 
14    31 for a given year. The utility shall also earn a return 
15    on the total of the unamortized balance of the regulatory 
16    assets, less any deferred taxes related to the unamortized 
17    balance, at an annual rate equal to the utility's weighted 
18    average cost of capital that includes, based on a year-end 
19    capital structure, the utility's actual cost of debt for 
20    the applicable calendar year and a cost of equity, which 
21    shall be equal to the baseline cost of equity approved by 
22    the Commission for the utility's electric distribution 
23    rates case effective during the applicable year, whether 
24    those rates are set pursuant to Section 9-201, 
25    subparagraph (B) of paragraph (3) of subsection (d) of 
26    Section 16-108.18, or any successor electric distribution 
 
 
10400SB0025ham003- 703 -LRB104 07069 AAS 29208 a

1    ratemaking paradigm calculated as the sum of (i) the 
2    average for the applicable calendar year of the monthly 
3    average yields of 30-year U.S. Treasury bonds published by 
4    the Board of Governors of the Federal Reserve System in 
5    its weekly H.15 Statistical Release or successor 
6    publication; and (ii) 580 basis points, including a 
7    revenue conversion factor calculated to recover or refund 
8    all additional income taxes that may be payable or 
9    receivable as a result of that return.
10        When an electric utility creates a regulatory asset 
11    under the provisions of this paragraph (1) of subsection 
12    (h), the costs are recovered over a period during which 
13    customers also receive a benefit, which is in the public 
14    interest. Accordingly, it is the intent of the General 
15    Assembly that an electric utility that elects to create a 
16    regulatory asset under the provisions of this paragraph 
17    (1) shall recover all of the associated costs, including, 
18    but not limited to, its cost of capital as set forth in 
19    this paragraph (1). After the Commission has approved the 
20    prudence and reasonableness of the costs that comprise the 
21    regulatory asset, the electric utility shall be permitted 
22    to recover all such costs, and the value and 
23    recoverability through rates of the associated regulatory 
24    asset shall not be limited, altered, impaired, or reduced. 
25    To enable the financing of the incremental capital 
26    expenditures, including regulatory assets, for electric 
 
 
10400SB0025ham003- 704 -LRB104 07069 AAS 29208 a

1    utilities that serve less than 3,000,000 retail customers 
2    but more than 500,000 retail customers in the State, the 
3    utility's actual year-end capital structure that includes 
4    a common equity ratio, excluding goodwill, of up to and 
5    including 50% of the total capital structure shall be 
6    deemed reasonable and used to set rates.
7        (2) The utility, at its election, may recover all of 
8    the costs as part of a filing for a general increase in 
9    rates under Article IX of this Act, as part of an annual 
10    filing to update a performance-based formula rate under 
11    Section 16-108.18 subsection (d) of Section 16-108.5 of 
12    this Act, or through an automatic adjustment clause 
13    tariff, provided that nothing in this paragraph (2) 
14    permits the double recovery of such costs from customers. 
15    If the utility elects to recover the costs it incurs under 
16    subsections (b), (b-5), and (c), and (e) through an 
17    automatic adjustment clause tariff, the utility may file 
18    its proposed tariff together with the tariff it files 
19    under subsection (b) of this Section or at a later time. 
20    The proposed tariff shall provide for an annual 
21    reconciliation, less any deferred taxes related to the 
22    reconciliation, with interest at an annual rate of return 
23    equal to the utility's weighted average cost of capital as 
24    calculated under paragraph (1) of this subsection (h), 
25    including a revenue conversion factor calculated to 
26    recover or refund all additional income taxes that may be 
 
 
10400SB0025ham003- 705 -LRB104 07069 AAS 29208 a

1    payable or receivable as a result of that return, of the 
2    revenue requirement reflected in rates for each calendar 
3    year, beginning with the calendar year in which the 
4    utility files its automatic adjustment clause tariff under 
5    this subsection (h), with what the revenue requirement 
6    would have been had the actual cost information for the 
7    applicable calendar year been available at the filing 
8    date. The Commission shall review the proposed tariff and 
9    may make changes to the tariff that are consistent with 
10    this Section and with the Commission's authority under 
11    Article IX of this Act, subject to notice and hearing. 
12    Following notice and hearing, the Commission shall issue 
13    an order approving, or approving with modification, such 
14    tariff no later than 240 days after the utility files its 
15    tariff.
16    (i) (Blank). An electric utility shall recover from its 
17retail customers, on a volumetric basis, all of the costs of 
18the rebates made under a tariff or tariffs placed into effect 
19under subsection (e) of this Section, including, but not 
20limited to, the value of the rebates and all costs incurred by 
21the utility to comply with and implement subsection (e) of 
22this Section, consistent with the following provisions:
23        (1) The utility may defer a portion of its costs as a 
24    regulatory asset. The Commission shall determine the 
25    portion that may be appropriately deferred as a regulatory 
26    asset. Factors that the Commission shall consider in 
 
 
10400SB0025ham003- 706 -LRB104 07069 AAS 29208 a

1    determining the portion of costs that shall be deferred as 
2    a regulatory asset include, but are not limited to: (i) 
3    whether and the extent to which a cost effectively 
4    deferred or avoided other distribution system operating 
5    costs or capital expenditures; (ii) the extent to which a 
6    cost provides environmental benefits; (iii) the extent to 
7    which a cost improves system reliability or resilience; 
8    (iv) the electric utility's distribution system plan 
9    developed pursuant to Section 16-105.17 of this Act; (v) 
10    the extent to which a cost advances equity principles; and 
11    (vi) such other factors as the Commission deems 
12    appropriate. The remainder of costs shall be deemed an 
13    operating expense and shall be recoverable if found 
14    prudent and reasonable by the Commission.    
15        The total costs deferred as a regulatory asset shall 
16    be amortized over a 15-year period. The unamortized 
17    balance shall be recognized as of December 31 for a given 
18    year. The utility shall also earn a return on the total of 
19    the unamortized balance of the regulatory assets, less any 
20    deferred taxes related to the unamortized balance, at an 
21    annual rate equal to the utility's weighted average cost 
22    of capital that includes, based on a year-end capital 
23    structure, the utility's actual cost of debt for the 
24    applicable calendar year and a cost of equity, which shall 
25    be calculated as the sum of: (I) the average for the 
26    applicable calendar year of the monthly average yields of 
 
 
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1    30-year U.S. Treasury bonds published by the Board of 
2    Governors of the Federal Reserve System in its weekly H.15 
3    Statistical Release or successor publication; and (II) 580 
4    basis points, including a revenue conversion factor 
5    calculated to recover or refund all additional income 
6    taxes that may be payable or receivable as a result of that 
7    return.
8        (2) The utility may recover all of the costs through 
9    an automatic adjustment clause tariff, on a volumetric 
10    basis. The utility may file its proposed cost-recovery 
11    tariff together with the tariff it files under subsection 
12    (e) of this Section or at a later time. The proposed tariff 
13    shall provide for an annual reconciliation, less any 
14    deferred taxes related to the reconciliation, with 
15    interest at an annual rate of return equal to the 
16    utility's weighted average cost of capital as calculated 
17    under paragraph (1) of this subsection (i), including a 
18    revenue conversion factor calculated to recover or refund 
19    all additional income taxes that may be payable or 
20    receivable as a result of that return, of the revenue 
21    requirement reflected in rates for each calendar year, 
22    beginning with the calendar year in which the utility 
23    files its automatic adjustment clause tariff under this 
24    subsection (i), with what the revenue requirement would 
25    have been had the actual cost information for the 
26    applicable calendar year been available at the filing 
 
 
10400SB0025ham003- 708 -LRB104 07069 AAS 29208 a

1    date. The Commission shall review the proposed tariff and 
2    may make changes to the tariff that are consistent with 
3    this Section and with the Commission's authority under 
4    Article IX of this Act, subject to notice and hearing. 
5    Following notice and hearing, the Commission shall issue 
6    an order approving, or approving with modification, such 
7    tariff no later than 240 days after the utility files its 
8    tariff.    
9    (j) No later than 90 days after the Commission enters an 
10order, or order on rehearing, whichever is later, approving an 
11electric utility's proposed tariff under this Section, the 
12electric utility shall provide notice of the availability of 
13rebates under this Section.
14    (k) No later than January 1, 2030, the utilities shall 
15file with the Commission a report that includes:
16        (1) the number and geographic distribution of 
17    participants receiving rebates pursuant to this Section;
18        (2) impacts to energy supply prices and wholesale 
19    market activities;
20        (3) impacts on distribution system investments and 
21    planning; and
22        (4) any other values deemed relevant by the 
23    Commission.
24    (l) Upon petition by the applicable electric utility or on 
25its own motion, the Commission may adjust rebate levels for 
26new customers and make other appropriate changes to the rebate 
 
 
10400SB0025ham003- 709 -LRB104 07069 AAS 29208 a

1program in a manner that is consistent with the State's clean 
2energy goals and the public interest.    
3(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22; 
4103-1066, eff. 2-20-25.)
 
5    (220 ILCS 5/16-107.8 new)
6    Sec. 16-107.8. Time-of-use pricing.
7    (a) The General Assembly finds that market-based 
8time-of-use rates and pricing plans can reduce costs and help 
9the State achieve its energy policy goals by improving load 
10shape, encouraging energy conservation, and shifting usage 
11away from periods where fossil fuels are used. By providing 
12consumers information relating the costs of service to the 
13time of energy usage, time-of-use rates can help consumers 
14reduce energy bills by using electricity when it is less 
15costly.
16    (b) An electric utility shall offer at least one 
17market-based rate option for eligible retail customers, 
18including, but not limited to, customers participating in net 
19electricity metering under the terms of Section 16-107.5, who 
20choose to take power and energy supply service from the 
21utility. The provisions of Section 16-107.5 notwithstanding, 
22energy credits for net-metering customers shall be valued at 
23the same price per kilowatt-hour as the price per 
24kilowatt-hour that the electric service provider would charge 
25for kilowatt-hour energy sales during the same hourly 
 
 
10400SB0025ham003- 710 -LRB104 07069 AAS 29208 a

1time-of-use period. The utility shall file its time-of-use 
2rate tariff no later than 120 days after the effective date of 
3this amendatory Act of the 104th General Assembly. The tariff 
4or tariffs shall be subject to the following requirements:
5        (1) If more than one tariff is proposed, at least one 
6    tariff shall include at least the following 3 time blocks:
7            (A) a peak time block of consecutive hours best 
8        reflecting the average consecutive highest system 
9        power and energy use per hour in a calendar day;
10            (B) an off-peak time block, which reflects the 
11        next highest system power and energy demands in a 
12        calendar day; and
13            (C) a super-off-peak time block, defined as all 
14        other hours in a calendar day.
15            Time blocks shall reflect the hour and weekday for 
16        which the costs of services outlined in paragraphs (2) 
17        and (3) of this subsection (b) are charged.
18        (2) The tariff or tariffs shall describe the 
19    methodology for determining the prices for each time block 
20    using the applicable average zonal and capacity prices of 
21    the PJM Interconnection, LLC (PJM) and the Midcontinent 
22    Independent System Operator (MISO) and describe the manner 
23    in which customers who elect time-of-use pricing will be 
24    provided with the time blocks, associated block pricing, 
25    and day-ahead energy prices. Costs for electric capacity 
26    shall be determined in a manner that recovers the capacity 
 
 
10400SB0025ham003- 711 -LRB104 07069 AAS 29208 a

1    obligation costs incurred by the electric utility.
2        (3) The time-of-use rate shall include the costs of 
3    transmission services and the charges for network 
4    integration transmission service, transmission 
5    enhancement, and locational reliability, as these terms 
6    are defined in the PJM and MISO Open Access Transmission 
7    Tariffs and manuals. If the Open Access Transmission 
8    Tariff or the manuals subsequently rename those terms, the 
9    services reflected under those terms shall continue to be 
10    included in the time-of-use rate described in this 
11    paragraph (3).
12        (4) Adjustments to the charges set by the tariff may 
13    be made on a monthly basis and adjustments to the time 
14    blocks may be made on an annual basis. A utility shall 
15    submit to the Commission, through a supplemental 
16    information sheet, a tariff schedule. Customers shall be 
17    provided at least 2 weeks advance notice of any changes to 
18    charges or time blocks.
19        (5) A purchased energy adjustment shall be calculated 
20    to fully recover costs to supply power and energy. A 
21    utility shall procure power and energy in the applicable 
22    day-ahead market.
23    (c) The Commission shall approve or approve with 
24modifications the tariff or tariffs after notice and hearing. 
25A proceeding under this subsection (c) may not exceed 240 days 
26in length.
 
 
10400SB0025ham003- 712 -LRB104 07069 AAS 29208 a

1    (d) An electric utility shall submit an annual report to 
2the Commission no later than April 1 of each year that 
3describes the operation and results of the rate option, 
4including information concerning the number and types of 
5customers using the rate option, changes in customers' energy 
6use patterns, an assessment of the value of the rate option to 
7both participants and nonparticipants, and recommendations 
8concerning modification of the rate option and the tariff or 
9tariffs filed under this Section. The report shall be made 
10available to the public on the Commission's website.
11    (e) Once a tariff or tariffs has been in effect, the 
12Commission may, upon complaint, petition, or its own 
13initiative, open a proceeding to investigate whether changes 
14or modifications, consistent with the requirements of this 
15Section, to the tariff or tariffs, rate option administration, 
16or any other rate option element is necessary to achieve the 
17goals described in subsection (a). Such a proceeding may not 
18last more than 180 days from the date upon which the 
19investigation was opened.
20    (f) An electric utility shall be entitled to recover 
21prudent and reasonable costs incurred in complying with this 
22Section from its eligible retail customers.
23    (g) An electric utility's tariff or tariffs filed under 
24this Section shall be subject to the provisions of Article IX 
25as long as such provisions do not conflict with this Section.
26    (h) This Section does not apply to an electric utility 
 
 
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1that provides service to 100,000 or fewer customers.    
 
2    (220 ILCS 5/16-107.9 new)
3    Sec. 16-107.9. Virtual power plant program.
4    (a) As used in this Section:
5    "Aggregator" means a third-party entity that participates 
6in the program, other than the electric utility or its 
7affiliate, that (i) represents and aggregates the load of 
8participating customers who collectively have the ability to 
9deploy 100 kilowatts or more of deployment of eligible devices 
10and (ii) is responsible for performance of the aggregation in 
11the program.
12    "Battery" means a behind-the-meter energy storage device 
13and associated equipment that operate together to fulfill 
14program requirements.
15    "Commission" means the Illinois Commerce Commission.
16    "Customer" means an active electric service account holder 
17of a utility.
18    "Direct participant" means a customer that enrolls in the 
19program directly with the utility, rather than participating 
20in the program through an aggregator.
21    "Distributed energy resource" has the meaning set forth in 
22Section 16-107.6.
23    "Distributed energy resources management system" means a 
24platform that may be used by distribution system operators or 
25utilities to integrate grid resources, such as distributed 
 
 
10400SB0025ham003- 714 -LRB104 07069 AAS 29208 a

1energy resources, into system operations.
2    "Eligible device" means a customer or third party-owned 
3distributed energy resource that satisfies the requirements 
4for participation in the program as specified in the relevant 
5program rider. "Eligible device" also means any device that 
6can be controlled to respond to pricing, provide services, 
7including decrease peak electricity demand or shift demand 
8from peak to off-peak periods, or inject power to the grid. 
9"Eligible device" includes, but is not limited to, 
10behind-the-meter energy storage systems, smart thermostats, 
11electric vehicle batteries, including fleets, and distributed 
12renewable energy devices paired with one or more energy 
13storage systems.
14    "Emergency event" means an event called by the utility 
15with fewer than 24 hours notice.
16    "Energy storage system" has the meaning set forth in 
17subsection (a) of Section 16-107.6.
18    "Enrolled customer" means a customer that participates in 
19the program through either an aggregator or as a direct 
20participant.
21    "Enrolled device" means an enrolled customer's eligible 
22device, as specified in the relevant tariff.
23    "Enterprise distributed energy resources management 
24system" means a platform operated by the electric utility that 
25interfaces with a grid-edge distributed energy resources 
26management system to integrate distributed energy resources 
 
 
10400SB0025ham003- 715 -LRB104 07069 AAS 29208 a

1into utility electric system operations.
2    "Grid-edge distributed energy resources management system" 
3means a platform owned by a party other than the electric 
4utility that may be used to integrate distributed energy 
5resources.
6    "Grid event" means a grid condition for which the utility 
7schedules or remotely dispatches enrolled devices to respond 
8to, as specified in the grid service opportunities for each 
9tariff.
10    "Grid service" means a capacity, energy, or ancillary 
11service that supports grid operations.
12    "Participating customer" means an aggregator or a direct 
13retail customer, as defined in Section 16-102, with one or 
14more eligible devices.
15    "Performance payment" means a payment made to the 
16participant based on the performance of an enrolled device 
17providing a grid service during a grid event.
18    "Performance payment rate" means the compensation rate 
19paid to participants for providing a particular grid service 
20during a grid event.
21    "Smart inverter" has the meaning set forth in subsection 
22(a) of Section 16-107.6.
23    "Upfront payment" means a one-time payment made at the 
24time of enrollment.
25    "Virtual power plant" means an aggregation of 
26behind-the-meter distributed energy resources operated in 
 
 
10400SB0025ham003- 716 -LRB104 07069 AAS 29208 a

1coordination to provide one or more grid services.
2    (b) The General Assembly finds that:
3        (1) virtual power plants are dynamic load management 
4    and energy supply resources that can support grid 
5    operations, reduce ratepayer costs, and achieve other 
6    important public policy goals;
7        (2) virtual power plants can reduce demand for grid 
8    supplied electricity during peak periods, shift 
9    electricity consumption out of peak periods, make 
10    renewable energy generated during off-peak periods 
11    available for use during peak periods, supply energy to 
12    the grid at desired times, provide frequency regulation, 
13    voltage support, and other ancillary services, reduce 
14    strain on the distribution system, manage localized peaks, 
15    improve system resiliency and reliability, and provide 
16    other grid services;
17        (3) virtual power plants can facilitate and optimize 
18    the utilization of electrical generation from wind and 
19    solar energy to help utilities increase hosting capacity 
20    and integrate more renewable energy resources;
21        (4) virtual power plants can reduce costs to 
22    ratepayers by utilizing customer-sited resources to 
23    provide grid services, avoiding or reducing reliance on 
24    fossil-fuel fired peaker plants, avoiding or deferring the 
25    need to construct new and more costly grid scale 
26    resources, optimizing the use of existing assets, and 
 
 
10400SB0025ham003- 717 -LRB104 07069 AAS 29208 a

1    avoiding or deferring distribution and transmission system 
2    upgrades and other grid investments;
3        (5) virtual power plants can promote equity by 
4    reducing costs for all ratepayers, expanding access to 
5    distributed energy resources among low-income and 
6    moderate-income customers through improved distributed 
7    energy resource finance ability, and providing other 
8    important co-benefits, including reduction in emissions of 
9    greenhouse gases and other pollutants, especially in 
10    environmental justice and other disadvantaged communities 
11    that host fossil fuel generation plants;
12        (6) the United States Department of Energy estimates 
13    that the United States could deploy 80 to 160 gigawatts of 
14    virtual power plants by 2030, a tripling of current 
15    levels, to support the rapid electrification of vehicles 
16    and homes and provide on the order of $10,000,000,000 in 
17    ratepayer savings annually. The deployment of virtual 
18    power plants can provide energy cost savings and other 
19    benefits to the people of Illinois;
20        (7) there are significant barriers to deployment and 
21    operation of virtual power plants, including the need for 
22    statutory and regulatory guidance and support, greater 
23    consistency in virtual power plant programs across 
24    regulatory jurisdictions, and for utility commitments to 
25    incorporate the use of virtual power plants into system 
26    operations and long-term resource planning;
 
 
10400SB0025ham003- 718 -LRB104 07069 AAS 29208 a

1        (8) it is in the public interest to advance customer 
2    choice and leverage the expertise of private, non-utility 
3    entities to advance innovation and implement 
4    cost-effective clean energy solutions; and
5        (9) the policy of Illinois shall be to maximize the 
6    use of virtual power plants comprised of customer-owned 
7    and third party-owned distributed energy resources to 
8    deliver system services and other benefits through utility 
9    administered virtual power plant programs in accordance 
10    with the provisions of this amendatory Act of the 104th 
11    General Assembly.
12    (c) No later than December 31, 2028, the Commission shall 
13approve at least one virtual power plant tariff for each 
14electric utility serving more than 300,000 customers in the 
15State as of January 1, 2023. Each utility shall file a tariff 
16or tariffs for approval no later than December 31, 2027 to 
17allow retail customers in the electric utility's service areas 
18to participate in a virtual power plant program proposal 
19consistent with the provisions of this Section. The Commission 
20shall provide opportunities for stakeholders to provide input 
21on the virtual power plant programs proposed for 
22implementation by each utility, which the Commission shall 
23take into consideration in its review of each utility's 
24filing. No later than one year after the utility's filing, the 
25Commission shall approve or modify and approve each utility's 
26virtual power plant program proposal for immediate 
 
 
10400SB0025ham003- 719 -LRB104 07069 AAS 29208 a

1implementation by the utility.
2    (d) The virtual power plant program filed under subsection 
3(c) shall be developed for implementation through a tariff 
4offering with standard terms and conditions for participation. 
5The virtual power plant program tariff shall allow for 
6customers with battery storage, non-battery storage and 
7electric vehicle technologies to enroll the devices in the 
8program through aggregators or directly with the utility. The 
9virtual power plant program tariff shall:
10        (1) provide a mechanism to incorporate existing 
11    programs, such as smart thermostat demand-response or 
12    electric vehicle charging programs currently offered by 
13    the utility, under the virtual power plant program 
14    framework;
15        (2) provide grid services opportunities for each 
16    eligible technology that customers and aggregators may 
17    provide, which shall include, at minimum, reducing the 
18    utility's applicable capacity and transmission obligations 
19    and capturing daily wholesale energy arbitrage 
20    opportunities through provision of grid services;
21        (3) provide additional functions and grid service 
22    opportunities that the Commission determines are 
23    supportive of efficient planning and operation of the 
24    electrical grid, including:
25            (A) minimizing the use of fossil fuels at peak 
26        times;
 
 
10400SB0025ham003- 720 -LRB104 07069 AAS 29208 a

1            (B) local peak demand reductions;
2            (C) locational value;
3            (D) the avoidance or deferral of local 
4        transmission or distribution upgrades or capacity 
5        expansion;
6            (E) voltage support and other ancillary services; 
7        and
8            (F) emergency grid services;
9        (4) provide operational parameters, which shall 
10    include, at a minimum:
11            (A) minimum and maximum numbers of grid events for 
12        which the utility may require dispatch from the 
13        enrolled distributed energy resources;
14            (B) months of the year that grid events may occur;
15            (C) days of the week that grid events may occur;
16            (D) times of day that grid events may occur;
17            (E) maximum duration of grid events; and
18            (F) minimum day-ahead advance notification 
19        requirement of grid events, except for emergency 
20        events, as applicable;
21        (5) include provisions for aggregators to participate 
22    in the virtual power plant program, participate in the 
23    utility's distributed energy resource management system as 
24    available, automatically enroll and manage their 
25    customers' participation, receive dispatch signals and 
26    other communications from the utility, deliver performance 
 
 
10400SB0025ham003- 721 -LRB104 07069 AAS 29208 a

1    measurement and verification data to the utility, and 
2    receive virtual power plant program payments directly from 
3    the utility;
4        (6) include provisions that provide a standardized 
5    process for any eligible aggregator to enroll in the 
6    program and authorize the eligible aggregators to manage 
7    individual customer device participation without 
8    additional authorizations from the utility;
9        (7) include provisions that allow a participating 
10    customer with multiple eligible devices to enroll the 
11    technologies either directly without an aggregator or 
12    through one or more aggregators in applicable programs 
13    under the tariff approved under this Section, provided 
14    that no particular device is accounted for more than once;
15        (8) include provisions for direct participant 
16    customers to participate with the utility's distributed 
17    energy resource management system as available, receive 
18    dispatch signals and other communications from the 
19    utility, deliver performance measurement and verification 
20    data to the utility, and receive virtual power plant 
21    program payments directly from the utility. Any provisions 
22    implementing this subpart that necessitate the 
23    installation of equipment to enable direct participation 
24    via the utility shall apply to customers who elect to 
25    participate as a direct participant and shall not be 
26    required of customers who participate via an aggregator or 
 
 
10400SB0025ham003- 722 -LRB104 07069 AAS 29208 a

1    to customers who do not participate in the virtual power 
2    plant program;
3        (9) provide for measurement and verification of 
4    battery non-battery, and electric vehicle technologies 
5    performance directly at the device without the requirement 
6    for the installation of an additional meter;
7        (10) include upfront payment or performance payment 
8    compensation mechanisms for the peak reduction service, as 
9    well as for non-battery and electric vehicle technologies 
10    as the Commission deems appropriate. The performance 
11    payment shall be based on the average capacity provided 
12    during grid events. The Commission shall approve 
13    additional compensation mechanisms as it determines 
14    appropriate for other grid services provided under the 
15    battery, non-battery and electric vehicle riders. The 
16    virtual power plant program shall not assess penalties for 
17    non-performance; provided, however, that the Commission 
18    may approve reasonable mechanisms to disenroll customers 
19    for continued non-performance;
20        (11) enable low-to-moderate income customers, 
21    community-driven community solar projects, and customers 
22    whose electric service has not been declared competitive 
23    pursuant to Section 16-113 as of July 1, 2011 located in 
24    equity investment eligible investment communities to 
25    receive a higher upfront enrollment payment. The 
26    Commission shall coordinate with State energy officials 
 
 
10400SB0025ham003- 723 -LRB104 07069 AAS 29208 a

1    and departments to make funding from federal programs and 
2    such other sources as may be available for use in 
3    providing higher upfront payments to customers classes as 
4    may be approved by the Commission in accordance with this 
5    subsection;
6        (12) provide that the performance payment rate 
7    applicable at the time of enrollment shall be for 5 years, 
8    after which time the participant may reenroll at the then 
9    applicable performance payment rate for an additional 
10    5-year term;
11        (13) provide for a transition of customers from the 
12    scheduled dispatch program described in Section 16-107.6 
13    to the virtual power plant program; and
14        (14) allow enrolled customers to participate in other 
15    applicable interconnection tariffs and grid service 
16    programs outside the virtual power plant program, so long 
17    as it does not result in double-counting of benefits for 
18    the same grid services.
19    (e) The Commission may adopt other reasonable requirements 
20for participation consistent with this subsection, provided 
21that collateral from an aggregator shall not be required for 
22participation.
23    (f) The utility may contract with a third party-owned 
24distributed energy resource management system provider to 
25assist with program implementation; however, implementation 
26shall not be delayed due to the lack of utility-owned 
 
 
10400SB0025ham003- 724 -LRB104 07069 AAS 29208 a

1distributed energy resource management system capabilities or 
2third party-owned distributed energy resource management 
3system capabilities.
4    (g) The utility shall not send or receive dispatch signals 
5directly to or from any participating customer represented by 
6an aggregator for an event under the virtual power plant 
7program described in this Section.
8    (h) Participating aggregators shall have capabilities to 
9receive event signals from utilities or utility-contracted 
10distributed energy resources management system providers.
11    (i) Utilities shall recover reasonably and prudently 
12incurred costs to facilitate the virtual power plant program 
13approved under subsection (c), including, but not limited to, 
14distributed energy resource management systems provider and 
15other service contract costs, operations and maintenance 
16expenses, information technology costs, and other costs, 
17expenses, and investments that the Commission finds necessary 
18and prudent for the development and implementation of the 
19program. The utility shall recover the cost of virtual power 
20plant program upfront payments and performance payments and 
21such other payments made to participants through the tariff 
22filed pursuant to subsection (h) of Section 16-107.6.
23    (j) No later than January 31 of each year, each utility 
24shall file an annual report that includes, but is not limited 
25to:
26        (1) the total capacity enrolled in each program rider 
 
 
10400SB0025ham003- 725 -LRB104 07069 AAS 29208 a

1    developed in accordance with the requirements of Section, 
2    broken down by technology type, customer class, and 
3    aggregator and direct participant status for each grid 
4    service opportunity offered in the prior calendar year;
5        (2) recommendations to increase participation in the 
6    virtual power plant program; and
7        (3) any other information that the Commission may 
8    require.
9    (k) Each utility shall amend existing tariffs and 
10procedures that limit the ability of customers to participate 
11in providing grid services under the program, such as 
12limitations on charging energy storage devices with grid 
13energy or exporting energy to the grid from battery discharge.
14    (l) The tariffs approved by the Commission shall not 
15reflect any additional charges, fees, or insurance 
16requirements imposed on those owning or operating 
17demand-response technologies beyond those imposed on similarly 
18situated customers that do not own or operate demand-response 
19technologies.    
20    (m) As a condition of participating in the programs 
21described in this Section, prior to enrollment of a customer 
22by an aggregator, the aggregator shall disclose the following:
23        (1) the payments, expressed as an amount or a formula, 
24    to be provided to the customer;
25        (2) between the aggregator and customer, who is 
26    responsible for paying penalties or fees; and
 
 
10400SB0025ham003- 726 -LRB104 07069 AAS 29208 a

1        (3) between the aggregator and customer, who is 
2    responsible for posting collateral, if required.
3    Any tariff authorized by this Section shall incorporate 
4the requirements under this subsection and shall require the 
5electric utility to establish a complaint and Commission 
6notification process and, on order of the Commission, suspend 
7any aggregator repeatedly or egregiously violating such 
8requirements.    
 
9    (220 ILCS 5/16-108)
10    Sec. 16-108. Recovery of costs associated with the 
11provision of delivery and other services.
12    (a) An electric utility shall file a delivery services 
13tariff with the Commission at least 210 days prior to the date 
14that it is required to begin offering such services pursuant 
15to this Act. An electric utility shall provide the components 
16of delivery services that are subject to the jurisdiction of 
17the Federal Energy Regulatory Commission at the same prices, 
18terms and conditions set forth in its applicable tariff as 
19approved or allowed into effect by that Commission. The 
20Commission shall otherwise have the authority pursuant to 
21Article IX to review, approve, and modify the prices, terms 
22and conditions of those components of delivery services not 
23subject to the jurisdiction of the Federal Energy Regulatory 
24Commission, including the authority to determine the extent to 
25which such delivery services should be offered on an unbundled 
 
 
10400SB0025ham003- 727 -LRB104 07069 AAS 29208 a

1basis. In making any such determination the Commission shall 
2consider, at a minimum, the effect of additional unbundling on 
3(i) the objective of just and reasonable rates, (ii) electric 
4utility employees, and (iii) the development of competitive 
5markets for electric energy services in Illinois.
6    (b) The Commission shall enter an order approving, or 
7approving as modified, the delivery services tariff no later 
8than 30 days prior to the date on which the electric utility 
9must commence offering such services. The Commission may 
10subsequently modify such tariff pursuant to this Act.
11    (c) The electric utility's tariffs shall define the 
12classes of its customers for purposes of delivery services 
13charges. Delivery services shall be priced and made available 
14to all retail customers electing delivery services in each 
15such class on a nondiscriminatory basis regardless of whether 
16the retail customer chooses the electric utility, an affiliate 
17of the electric utility, or another entity as its supplier of 
18electric power and energy. Charges for delivery services shall 
19be cost based, and shall allow the electric utility to recover 
20the costs of providing delivery services through its charges 
21to its delivery service customers that use the facilities and 
22services associated with such costs. Such costs shall include 
23the costs of owning, operating and maintaining transmission 
24and distribution facilities. The Commission shall also be 
25authorized to consider whether, and if so to what extent, the 
26following costs are appropriately included in the electric 
 
 
10400SB0025ham003- 728 -LRB104 07069 AAS 29208 a

1utility's delivery services rates: (i) the costs of that 
2portion of generation facilities used for the production and 
3absorption of reactive power in order that retail customers 
4located in the electric utility's service area can receive 
5electric power and energy from suppliers other than the 
6electric utility, and (ii) the costs associated with the use 
7and redispatch of generation facilities to mitigate 
8constraints on the transmission or distribution system in 
9order that retail customers located in the electric utility's 
10service area can receive electric power and energy from 
11suppliers other than the electric utility. Nothing in this 
12subsection shall be construed as directing the Commission to 
13allocate any of the costs described in (i) or (ii) that are 
14found to be appropriately included in the electric utility's 
15delivery services rates to any particular customer group or 
16geographic area in setting delivery services rates.
17    (d) The Commission shall establish charges, terms and 
18conditions for delivery services that are just and reasonable 
19and shall take into account customer impacts when establishing 
20such charges. In establishing charges, terms and conditions 
21for delivery services, the Commission shall take into account 
22voltage level differences. A retail customer shall have the 
23option to request to purchase electric service at any delivery 
24service voltage reasonably and technically feasible from the 
25electric facilities serving that customer's premises provided 
26that there are no significant adverse impacts upon system 
 
 
10400SB0025ham003- 729 -LRB104 07069 AAS 29208 a

1reliability or system efficiency. A retail customer shall also 
2have the option to request to purchase electric service at any 
3point of delivery that is reasonably and technically feasible 
4provided that there are no significant adverse impacts on 
5system reliability or efficiency. Such requests shall not be 
6unreasonably denied.
7    (e) Electric utilities shall recover the costs of 
8installing, operating or maintaining facilities for the 
9particular benefit of one or more delivery services customers, 
10including without limitation any costs incurred in complying 
11with a customer's request to be served at a different voltage 
12level, directly from the retail customer or customers for 
13whose benefit the costs were incurred, to the extent such 
14costs are not recovered through the charges referred to in 
15subsections (c) and (d) of this Section.
16    (f) An electric utility shall be entitled but not required 
17to implement transition charges in conjunction with the 
18offering of delivery services pursuant to Section 16-104. If 
19an electric utility implements transition charges, it shall 
20implement such charges for all delivery services customers and 
21for all customers described in subsection (h), but shall not 
22implement transition charges for power and energy that a 
23retail customer takes from cogeneration or self-generation 
24facilities located on that retail customer's premises, if such 
25facilities meet the following criteria:    
26        (i) the cogeneration or self-generation facilities 
 
 
10400SB0025ham003- 730 -LRB104 07069 AAS 29208 a

1    serve a single retail customer and are located on that 
2    retail customer's premises (for purposes of this 
3    subparagraph and subparagraph (ii), an industrial or 
4    manufacturing retail customer and a third party contractor 
5    that is served by such industrial or manufacturing 
6    customer through such retail customer's own electrical 
7    distribution facilities under the circumstances described 
8    in subsection (vi) of the definition of "alternative 
9    retail electric supplier" set forth in Section 16-102, 
10    shall be considered a single retail customer);    
11        (ii) the cogeneration or self-generation facilities 
12    either (A) are sized pursuant to generally accepted 
13    engineering standards for the retail customer's electrical 
14    load at that premises (taking into account standby or 
15    other reliability considerations related to that retail 
16    customer's operations at that site) or (B) if the facility 
17    is a cogeneration facility located on the retail 
18    customer's premises, the retail customer is the thermal 
19    host for that facility and the facility has been designed 
20    to meet that retail customer's thermal energy requirements 
21    resulting in electrical output beyond that retail 
22    customer's electrical demand at that premises, comply with 
23    the operating and efficiency standards applicable to 
24    "qualifying facilities" specified in title 18 Code of 
25    Federal Regulations Section 292.205 as in effect on the 
26    effective date of this amendatory Act of 1999;    
 
 
10400SB0025ham003- 731 -LRB104 07069 AAS 29208 a

1        (iii) the retail customer on whose premises the 
2    facilities are located either has an exclusive right to 
3    receive, and corresponding obligation to pay for, all of 
4    the electrical capacity of the facility, or in the case of 
5    a cogeneration facility that has been designed to meet the 
6    retail customer's thermal energy requirements at that 
7    premises, an identified amount of the electrical capacity 
8    of the facility, over a minimum 5-year period; and    
9        (iv) if the cogeneration facility is sized for the 
10    retail customer's thermal load at that premises but 
11    exceeds the electrical load, any sales of excess power or 
12    energy are made only at wholesale, are subject to the 
13    jurisdiction of the Federal Energy Regulatory Commission, 
14    and are not for the purpose of circumventing the 
15    provisions of this subsection (f).
16If a generation facility located at a retail customer's 
17premises does not meet the above criteria, an electric utility 
18implementing transition charges shall implement a transition 
19charge until December 31, 2006 for any power and energy taken 
20by such retail customer from such facility as if such power and 
21energy had been delivered by the electric utility. Provided, 
22however, that an industrial retail customer that is taking 
23power from a generation facility that does not meet the above 
24criteria but that is located on such customer's premises will 
25not be subject to a transition charge for the power and energy 
26taken by such retail customer from such generation facility if 
 
 
10400SB0025ham003- 732 -LRB104 07069 AAS 29208 a

1the facility does not serve any other retail customer and 
2either was installed on behalf of the customer and for its own 
3use prior to January 1, 1997, or is both predominantly fueled 
4by byproducts of such customer's manufacturing process at such 
5premises and sells or offers an average of 300 megawatts or 
6more of electricity produced from such generation facility 
7into the wholesale market. Such charges shall be calculated as 
8provided in Section 16-102, and shall be collected on each 
9kilowatt-hour delivered under a delivery services tariff to a 
10retail customer from the date the customer first takes 
11delivery services until December 31, 2006 except as provided 
12in subsection (h) of this Section. Provided, however, that an 
13electric utility, other than an electric utility providing 
14service to at least 1,000,000 customers in this State on 
15January 1, 1999, shall be entitled to petition for entry of an 
16order by the Commission authorizing the electric utility to 
17implement transition charges for an additional period ending 
18no later than December 31, 2008. The electric utility shall 
19file its petition with supporting evidence no earlier than 16 
20months, and no later than 12 months, prior to December 31, 
212006. The Commission shall hold a hearing on the electric 
22utility's petition and shall enter its order no later than 8 
23months after the petition is filed. The Commission shall 
24determine whether and to what extent the electric utility 
25shall be authorized to implement transition charges for an 
26additional period. The Commission may authorize the electric 
 
 
10400SB0025ham003- 733 -LRB104 07069 AAS 29208 a

1utility to implement transition charges for some or all of the 
2additional period, and shall determine the mitigation factors 
3to be used in implementing such transition charges; provided, 
4that the Commission shall not authorize mitigation factors 
5less than 110% of those in effect during the 12 months ended 
6December 31, 2006. In making its determination, the Commission 
7shall consider the following factors: the necessity to 
8implement transition charges for an additional period in order 
9to maintain the financial integrity of the electric utility; 
10the prudence of the electric utility's actions in reducing its 
11costs since the effective date of this amendatory Act of 1997; 
12the ability of the electric utility to provide safe, adequate 
13and reliable service to retail customers in its service area; 
14and the impact on competition of allowing the electric utility 
15to implement transition charges for the additional period.
16    (g) The electric utility shall file tariffs that establish 
17the transition charges to be paid by each class of customers to 
18the electric utility in conjunction with the provision of 
19delivery services. The electric utility's tariffs shall define 
20the classes of its customers for purposes of calculating 
21transition charges. The electric utility's tariffs shall 
22provide for the calculation of transition charges on a 
23customer-specific basis for any retail customer whose average 
24monthly maximum electrical demand on the electric utility's 
25system during the 6 months with the customer's highest monthly 
26maximum electrical demands equals or exceeds 3.0 megawatts for 
 
 
10400SB0025ham003- 734 -LRB104 07069 AAS 29208 a

1electric utilities having more than 1,000,000 customers, and 
2for other electric utilities for any customer that has an 
3average monthly maximum electrical demand on the electric 
4utility's system of one megawatt or more, and (A) for which 
5there exists data on the customer's usage during the 3 years 
6preceding the date that the customer became eligible to take 
7delivery services, or (B) for which there does not exist data 
8on the customer's usage during the 3 years preceding the date 
9that the customer became eligible to take delivery services, 
10if in the electric utility's reasonable judgment there exists 
11comparable usage information or a sufficient basis to develop 
12such information, and further provided that the electric 
13utility can require customers for which an individual 
14calculation is made to sign contracts that set forth the 
15transition charges to be paid by the customer to the electric 
16utility pursuant to the tariff.
17    (h) An electric utility shall also be entitled to file 
18tariffs that allow it to collect transition charges from 
19retail customers in the electric utility's service area that 
20do not take delivery services but that take electric power or 
21energy from an alternative retail electric supplier or from an 
22electric utility other than the electric utility in whose 
23service area the customer is located. Such charges shall be 
24calculated, in accordance with the definition of transition 
25charges in Section 16-102, for the period of time that the 
26customer would be obligated to pay transition charges if it 
 
 
10400SB0025ham003- 735 -LRB104 07069 AAS 29208 a

1were taking delivery services, except that no deduction for 
2delivery services revenues shall be made in such calculation, 
3and usage data from the customer's class shall be used where 
4historical usage data is not available for the individual 
5customer. The customer shall be obligated to pay such charges 
6on a lump sum basis on or before the date on which the customer 
7commences to take service from the alternative retail electric 
8supplier or other electric utility, provided, that the 
9electric utility in whose service area the customer is located 
10shall offer the customer the option of signing a contract 
11pursuant to which the customer pays such charges ratably over 
12the period in which the charges would otherwise have applied.
13    (i) An electric utility shall be entitled to add to the 
14bills of delivery services customers charges pursuant to 
15Sections 9-221, 9-222 (except as provided in Section 9-222.1), 
16and Section 16-114 of this Act, Section 5-5 of the Electricity 
17Infrastructure Maintenance Fee Law, Section 6-5 of the 
18Renewable Energy, Energy Efficiency, and Coal Resources 
19Development Law of 1997, and Section 13 of the Energy 
20Assistance Act.
21    (i-5) An electric utility required to impose the Coal to 
22Solar and Energy Storage Initiative Charge provided for in 
23subsection (c-5) of Section 1-75 of the Illinois Power Agency 
24Act shall add such charge to the bills of its delivery services 
25customers pursuant to the terms of a tariff conforming to the 
26requirements of subsection (c-5) of Section 1-75 of the 
 
 
10400SB0025ham003- 736 -LRB104 07069 AAS 29208 a

1Illinois Power Agency Act and this subsection (i-5) and filed 
2with and approved by the Commission. The electric utility 
3shall file its proposed tariff with the Commission on or 
4before July 1, 2022 to be effective, after review and approval 
5or modification by the Commission, beginning January 1, 2023. 
6On or before December 1, 2022, the Commission shall review the 
7electric utility's proposed tariff, including by conducting a 
8docketed proceeding if deemed necessary by the Commission, and 
9shall approve the proposed tariff or direct the electric 
10utility to make modifications the Commission finds necessary 
11for the tariff to conform to the requirements of subsection 
12(c-5) of Section 1-75 of the Illinois Power Agency Act and this 
13subsection (i-5). The electric utility's tariff shall provide 
14for imposition of the Coal to Solar and Energy Storage 
15Initiative Charge on a per-kilowatthour basis to all 
16kilowatthours delivered by the electric utility to its 
17delivery services customers. The tariff shall provide for the 
18calculation of the Coal to Solar and Energy Storage Initiative 
19Charge to be in effect for the year beginning January 1, 2023 
20and each year beginning January 1 thereafter, sufficient to 
21collect the electric utility's estimated payment obligations 
22for the delivery year beginning the following June 1 under 
23contracts for purchase of renewable energy credits entered 
24into pursuant to subsection (c-5) of Section 1-75 of the 
25Illinois Power Agency Act and the obligations of the 
26Department of Commerce and Economic Opportunity, or any 
 
 
10400SB0025ham003- 737 -LRB104 07069 AAS 29208 a

1successor department or agency, which for purposes of this 
2subsection (i-5) shall be referred to as the Department, to 
3make grant payments during such delivery year from the Coal to 
4Solar and Energy Storage Initiative Fund pursuant to grant 
5contracts entered into pursuant to subsection (c-5) of Section 
61-75 of the Illinois Power Agency Act, and using the electric 
7utility's kilowatthour deliveries to its delivery services 
8customers during the delivery year ended May 31 of the 
9preceding calendar year. On or before November 1 of each year 
10beginning November 1, 2022, the Department shall notify the 
11electric utilities of the amount of the Department's estimated 
12obligations for grant payments during the delivery year 
13beginning the following June 1 pursuant to grant contracts 
14entered into pursuant to subsection (c-5) of Section 1-75 of 
15the Illinois Power Agency Act; and each electric utility shall 
16incorporate in the calculation of its Coal to Solar and Energy 
17Storage Initiative Charge the fractional portion of the 
18Department's estimated obligations equal to the electric 
19utility's kilowatthour deliveries to its delivery services 
20customers in the delivery year ended the preceding May 31 
21divided by the aggregate deliveries of both electric utilities 
22to delivery services customers in such delivery year. The 
23electric utility shall remit on a monthly basis to the State 
24Treasurer, for deposit in the Coal to Solar and Energy Storage 
25Initiative Fund provided for in subsection (c-5) of Section 
261-75 of the Illinois Power Agency Act, the electric utility's 
 
 
10400SB0025ham003- 738 -LRB104 07069 AAS 29208 a

1collections of the Coal to Solar and Energy Storage Initiative 
2Charge estimated to be needed by the Department for grant 
3payments pursuant to grant contracts entered into pursuant to 
4subsection (c-5) of Section 1-75 of the Illinois Power Agency 
5Act. The initial charge under the electric utility's tariff 
6shall be effective for kilowatthours delivered beginning 
7January 1, 2023, and thereafter shall be revised to be 
8effective January 1, 2024 and each January 1 thereafter, based 
9on the payment obligations for the delivery year beginning the 
10following June 1. The tariff shall provide for the electric 
11utility to make an annual filing with the Commission on or 
12before November 15 of each year, beginning in 2023, setting 
13forth the Coal to Solar and Energy Storage Initiative Charge 
14to be in effect for the year beginning the following January 1. 
15The electric utility's tariff shall also provide that the 
16electric utility shall make a filing with the Commission on or 
17before August 1 of each year beginning in 2024 setting forth a 
18reconciliation, for the delivery year ended the preceding May 
1931, of the electric utility's collections of the Coal to Solar 
20and Energy Storage Initiative Charge against actual payments 
21for renewable energy credits pursuant to contracts entered 
22into, and the actual grant payments by the Department pursuant 
23to grant contracts entered into, pursuant to subsection (c-5) 
24of Section 1-75 of the Illinois Power Agency Act. The tariff 
25shall provide that any excess or shortfall of collections to 
26payments shall be deducted from or added to, on a 
 
 
10400SB0025ham003- 739 -LRB104 07069 AAS 29208 a

1per-kilowatthour basis, the Coal to Solar and Energy Storage 
2Initiative Charge, over the 6-month period beginning October 1 
3of that calendar year. 
4    (j) If a retail customer that obtains electric power and 
5energy from cogeneration or self-generation facilities 
6installed for its own use on or before January 1, 1997, 
7subsequently takes service from an alternative retail electric 
8supplier or an electric utility other than the electric 
9utility in whose service area the customer is located for any 
10portion of the customer's electric power and energy 
11requirements formerly obtained from those facilities 
12(including that amount purchased from the utility in lieu of 
13such generation and not as standby power purchases, under a 
14cogeneration displacement tariff in effect as of the effective 
15date of this amendatory Act of 1997), the transition charges 
16otherwise applicable pursuant to subsections (f), (g), or (h) 
17of this Section shall not be applicable in any year to that 
18portion of the customer's electric power and energy 
19requirements formerly obtained from those facilities, 
20provided, that for purposes of this subsection (j), such 
21portion shall not exceed the average number of kilowatt-hours 
22per year obtained from the cogeneration or self-generation 
23facilities during the 3 years prior to the date on which the 
24customer became eligible for delivery services, except as 
25provided in subsection (f) of Section 16-110.
26    (k) The electric utility shall be entitled to recover 
 
 
10400SB0025ham003- 740 -LRB104 07069 AAS 29208 a

1through tariffed charges all of the costs associated with the 
2purchase of zero emission credits from zero emission 
3facilities to meet the requirements of subsection (d-5) of 
4Section 1-75 of the Illinois Power Agency Act and all of the 
5costs associated with the purchase of carbon mitigation 
6credits from carbon-free energy resources to meet the 
7requirements of subsection (d-10) of Section 1-75 of the 
8Illinois Power Agency Act. Such costs shall include the costs 
9of procuring the zero emission credits and carbon mitigation 
10credits from carbon-free energy resources, as well as the 
11reasonable costs that the utility incurs as part of the 
12procurement processes and to implement and comply with plans 
13and processes approved by the Commission under subsections 
14(d-5) and (d-10). The costs shall be allocated across all 
15retail customers through a single, uniform cents per 
16kilowatt-hour charge applicable to all retail customers, which 
17shall appear as a separate line item on each customer's bill. 
18The electric utility shall be entitled to recover through 
19tariffed charges approved by the Commission all of the prudent 
20and reasonable costs associated with energy storage resources 
21procurements to meet the energy storage system portfolio 
22standard of subsection (d-20) of Section 1-75 of the Illinois 
23Power Agency Act. Such costs shall include the contract costs 
24for the energy storage system resources and the prudent and 
25reasonable costs that the utility incurs as part of the 
26procurement processes and in implementing and complying with 
 
 
10400SB0025ham003- 741 -LRB104 07069 AAS 29208 a

1plans and processes approved by the Commission under 
2subsection (d-20). The costs associated with the purchase of 
3energy storage system resources shall be allocated across all 
4retail customers in proportion to the amount of energy storage 
5system resources the utility procures for such customers 
6through a single, uniform cents per kilowatt-hour charge 
7applicable to such retail customers, which shall appear as a 
8separate line item on each customer's bill. Beginning June 1, 
92017, the electric utility shall be entitled to recover 
10through tariffed charges all of the costs associated with the 
11purchase of renewable energy resources to meet the renewable 
12energy resource standards of subsection (c) of Section 1-75 of 
13the Illinois Power Agency Act, under procurement plans as 
14approved in accordance with that Section and Section 16-111.5 
15of this Act. Such costs shall include the costs of procuring 
16the renewable energy resources, as well as the reasonable 
17costs that the utility incurs as part of the procurement 
18processes and to implement and comply with plans and processes 
19approved by the Commission under such Sections. The costs 
20associated with the purchase of renewable energy resources 
21shall be allocated across all retail customers in proportion 
22to the amount of renewable energy resources the utility 
23procures for such customers through a single, uniform cents 
24per kilowatt-hour charge applicable to such retail customers, 
25which shall appear as a separate line item on each such 
26customer's bill. The credits, costs, and penalties associated 
 
 
10400SB0025ham003- 742 -LRB104 07069 AAS 29208 a

1with the self-direct renewable portfolio standard compliance 
2program described in subparagraph (R) of paragraph (1) of 
3subsection (c) of Section 1-75 of the Illinois Power Agency 
4Act shall be allocated to approved eligible self-direct 
5customers by the utility in a cents per kilowatt-hour credit, 
6cost, or penalty, which shall appear as a separate line item on 
7each such customer's bill. 
8    Notwithstanding whether the Commission has approved the 
9initial long-term renewable resources procurement plan as of 
10June 1, 2017, an electric utility shall place new tariffed 
11charges into effect beginning with the June 2017 monthly 
12billing period, to the extent practicable, to begin recovering 
13the costs of procuring renewable energy resources, as those 
14charges are calculated under the limitations described in 
15subparagraph (E) of paragraph (1) of subsection (c) of Section 
161-75 of the Illinois Power Agency Act. Notwithstanding the 
17date on which the utility places such new tariffed charges 
18into effect, the utility shall be permitted to collect the 
19charges under such tariff as if the tariff had been in effect 
20beginning with the first day of the June 2017 monthly billing 
21period. For the delivery years commencing June 1, 2017, June 
221, 2018, June 1, 2019, and each delivery year thereafter, the 
23electric utility shall deposit into a separate interest 
24bearing account of a financial institution the monies 
25collected under the tariffed charges. Money collected from 
26customers for the procurement of renewable energy resources in 
 
 
10400SB0025ham003- 743 -LRB104 07069 AAS 29208 a

1a given delivery year may be spent by the utility for the 
2procurement of renewable resources over any of the following 5 
3delivery years, after which unspent money shall be credited 
4back to retail customers. The electric utility shall spend all 
5money collected in earlier delivery years that has not yet 
6been returned to customers, first, before spending money 
7collected in later delivery years. Any interest earned shall 
8be credited back to retail customers under the reconciliation 
9proceeding provided for in this subsection (k), provided that 
10the electric utility shall first be reimbursed from the 
11interest for the administrative costs that it incurs to 
12administer and manage the account. Any taxes due on the funds 
13in the account, or interest earned on it, will be paid from the 
14account or, if insufficient monies are available in the 
15account, from the monies collected under the tariffed charges 
16to recover the costs of procuring renewable energy resources. 
17Monies deposited in the account shall be subject to the 
18review, reconciliation, and true-up process described in this 
19subsection (k) that is applicable to the funds collected and 
20costs incurred for the procurement of renewable energy 
21resources.
22    The electric utility shall be entitled to recover all of 
23the costs identified in this subsection (k) through automatic 
24adjustment clause tariffs applicable to all of the utility's 
25retail customers that allow the electric utility to adjust its 
26tariffed charges consistent with this subsection (k). The 
 
 
10400SB0025ham003- 744 -LRB104 07069 AAS 29208 a

1determination as to whether any excess funds were collected 
2during a given delivery year for the purchase of renewable 
3energy resources, and the crediting of any excess funds back 
4to retail customers, shall not be made until after the close of 
5the delivery year, which will ensure that the maximum amount 
6of funds is available to implement the approved long-term 
7renewable resources procurement plan during a given delivery 
8year. The amount of excess funds eligible to be credited back 
9to retail customers shall be reduced by an amount equal to the 
10payment obligations required by any contracts entered into by 
11an electric utility under contracts described in subsection 
12(b) of Section 1-56 and subsection (c) of Section 1-75 of the 
13Illinois Power Agency Act, even if such payments have not yet 
14been made and regardless of the delivery year in which those 
15payment obligations were incurred. Notwithstanding anything to 
16the contrary, including in tariffs authorized by this 
17subsection (k) in effect before the effective date of this 
18amendatory Act of the 102nd General Assembly, all unspent 
19funds as of May 31, 2021, excluding any funds credited to 
20customers during any utility billing cycle that commences 
21prior to the effective date of this amendatory Act of the 102nd 
22General Assembly, shall remain in the utility account and 
23shall on a first in, first out basis be used toward utility 
24payment obligations under contracts described in subsection 
25(b) of Section 1-56 and subsection (c) of Section 1-75 of the 
26Illinois Power Agency Act. The electric utility's collections 
 
 
10400SB0025ham003- 745 -LRB104 07069 AAS 29208 a

1under such automatic adjustment clause tariffs to recover the 
2costs of renewable energy resources, zero emission credits 
3from zero emission facilities, energy storage resources, and 
4carbon mitigation credits from carbon-free energy resources 
5shall be subject to separate annual review, reconciliation, 
6and true-up against actual costs by the Commission under a 
7procedure that shall be specified in the electric utility's 
8automatic adjustment clause tariffs and that shall be approved 
9by the Commission in connection with its approval of such 
10tariffs. The procedure shall provide that any difference 
11between the electric utility's collections for energy storage 
12resources, zero emission credits, and carbon mitigation 
13credits under the automatic adjustment charges for an annual 
14period and the electric utility's actual costs of energy 
15storage resources, zero emission credits from zero emission 
16facilities, and carbon mitigation credits from carbon-free 
17energy resources for that same annual period shall be refunded 
18to or collected from, as applicable, the electric utility's 
19retail customers in subsequent periods.
20    Nothing in this subsection (k) is intended to affect, 
21limit, or change the right of the electric utility to recover 
22the costs associated with the procurement of renewable energy 
23resources for periods commencing before, on, or after June 1, 
242017, as otherwise provided in the Illinois Power Agency Act. 
25    The funding available under this subsection (k), if any, 
26for the programs described under subsection (b) of Section 
 
 
10400SB0025ham003- 746 -LRB104 07069 AAS 29208 a

11-56 of the Illinois Power Agency Act shall not reduce the 
2amount of funding for the programs described in subparagraph 
3(O) of paragraph (1) of subsection (c) of Section 1-75 of the 
4Illinois Power Agency Act. If funding is available under this 
5subsection (k) for programs described under subsection (b) of 
6Section 1-56 of the Illinois Power Agency Act, then the 
7long-term renewable resources plan shall provide for the 
8Agency to procure contracts in an amount that does not exceed 
9the funding, and the contracts approved by the Commission 
10shall be executed by the applicable utility or utilities. 
11    (l) A utility that has terminated any contract executed 
12under subsection (d-5) or (d-10) of Section 1-75 of the 
13Illinois Power Agency Act shall be entitled to recover any 
14remaining balance associated with the purchase of zero 
15emission credits prior to such termination, and such utility 
16shall also apply a credit to its retail customer bills in the 
17event of any over-collection. 
18    (m)(1) An electric utility that recovers its costs of 
19procuring zero emission credits from zero emission facilities 
20through a cents-per-kilowatthour charge under subsection (k) 
21of this Section shall be subject to the requirements of this 
22subsection (m). Notwithstanding anything to the contrary, such 
23electric utility shall, beginning on April 30, 2018, and each 
24April 30 thereafter until April 30, 2026, calculate whether 
25any reduction must be applied to such cents-per-kilowatthour 
26charge that is paid by retail customers of the electric 
 
 
10400SB0025ham003- 747 -LRB104 07069 AAS 29208 a

1utility that have opted out of subsections (a) through (j) of 
2Section 8-103B of this Act under subsection (l) of Section 
38-103B. Such charge shall be reduced for such customers for 
4the next delivery year commencing on June 1 based on the amount 
5necessary, if any, to limit the annual estimated average net 
6increase for the prior calendar year due to the future energy 
7investment costs to no more than 1.3% of 5.98 cents per 
8kilowatt-hour, which is the average amount paid per 
9kilowatthour for electric service during the year ending 
10December 31, 2015 by Illinois industrial retail customers, as 
11reported to the Edison Electric Institute. 
12    The calculations required by this subsection (m) shall be 
13made only once for each year, and no subsequent rate impact 
14determinations shall be made. 
15    (2) For purposes of this Section, "future energy 
16investment costs" shall be calculated by subtracting the 
17cents-per-kilowatthour charge identified in subparagraph (A) 
18of this paragraph (2) from the sum of the 
19cents-per-kilowatthour charges identified in subparagraph (B) 
20of this paragraph (2): 
21        (A) The cents-per-kilowatthour charge identified in 
22    the electric utility's tariff placed into effect under 
23    Section 8-103 of the Public Utilities Act that, on 
24    December 1, 2016, was applicable to those retail customers 
25    that have opted out of subsections (a) through (j) of 
26    Section 8-103B of this Act under subsection (l) of Section 
 
 
10400SB0025ham003- 748 -LRB104 07069 AAS 29208 a

1    8-103B. 
2        (B) The sum of the following cents-per-kilowatthour 
3    charges applicable to those retail customers that have 
4    opted out of subsections (a) through (j) of Section 8-103B 
5    of this Act under subsection (l) of Section 8-103B, 
6    provided that if one or more of the following charges has 
7    been in effect and applied to such customers for more than 
8    one calendar year, then each charge shall be equal to the 
9    average of the charges applied over a period that 
10    commences with the calendar year ending December 31, 2017 
11    and ends with the most recently completed calendar year 
12    prior to the calculation required by this subsection (m): 
13            (i) the cents-per-kilowatthour charge to recover 
14        the costs incurred by the utility under subsection 
15        (d-5) of Section 1-75 of the Illinois Power Agency 
16        Act, adjusted for any reductions required under this 
17        subsection (m); and
18            (ii) the cents-per-kilowatthour charge to recover 
19        the costs incurred by the utility under Section 
20        16-107.6 of the Public Utilities Act. 
21        If no charge was applied for a given calendar year 
22    under item (i) or (ii) of this subparagraph (B), then the 
23    value of the charge for that year shall be zero. 
24    (3) If a reduction is required by the calculation 
25performed under this subsection (m), then the amount of the 
26reduction shall be multiplied by the number of years reflected 
 
 
10400SB0025ham003- 749 -LRB104 07069 AAS 29208 a

1in the averages calculated under subparagraph (B) of paragraph 
2(2) of this subsection (m). Such reduction shall be applied to 
3the cents-per-kilowatthour charge that is applicable to those 
4retail customers that have opted out of subsections (a) 
5through (j) of Section 8-103B of this Act under subsection (l) 
6of Section 8-103B beginning with the next delivery year 
7commencing after the date of the calculation required by this 
8subsection (m). 
9    (4) The electric utility shall file a notice with the 
10Commission on May 1 of 2018 and each May 1 thereafter until May 
111, 2026 containing the reduction, if any, which must be 
12applied for the delivery year which begins in the year of the 
13filing. The notice shall contain the calculations made 
14pursuant to this Section. By October 1 of each year beginning 
15in 2018, each electric utility shall notify the Commission if 
16it appears, based on an estimate of the calculation required 
17in this subsection (m), that a reduction will be required in 
18the next year. 
19(Source: P.A. 102-662, eff. 9-15-21.)
 
20    (220 ILCS 5/16-108.19)
21    Sec. 16-108.19. Division of Integrated Distribution 
22Planning.
23    (a) The Commission shall employ establish the Division of 
24Integrated Distribution Planning within the Bureau of Public 
25Utilities. The Division shall be staffed by no less than 13    
 
 
10400SB0025ham003- 750 -LRB104 07069 AAS 29208 a

1professionals, including engineers, rate analysts, 
2accountants, policy analysts, utility research and analysis 
3analysts, cybersecurity analysts, informational technology 
4specialists, and lawyers, and other personnel deemed necessary 
5and appropriate by the Executive Director to review and 
6evaluate Integrated Grid Plans, updates to Integrated Grid 
7Plans, audits, and other duties as assigned. The personnel may 
8be organized or assigned into departments, bureaus, sections, 
9or divisions as determined by the Executive Director pursuant 
10to the authority granted under this Section by the Chief of the 
11Public Utilities Bureau.
12    (b) The Division of Integrated Distribution Planning shall 
13be established by January 1, 2022. 
14(Source: P.A. 102-662, eff. 9-15-21.)
 
15    (220 ILCS 5/16-108.30)
16    Sec. 16-108.30. Energy Transition Assistance Fund.
17    (a) The Energy Transition Assistance Fund is hereby 
18created as a special fund in the State treasury Treasury. The 
19Energy Transition Assistance Fund is authorized to receive 
20moneys collected pursuant to this Section. Subject to 
21appropriation, the Department of Commerce and Economic 
22Opportunity shall use moneys from the Energy Transition 
23Assistance Fund consistent with the purposes of this Act.
24    (b) An electric utility serving more than 500,000 
25customers in the State shall assess an energy transition 
 
 
10400SB0025ham003- 751 -LRB104 07069 AAS 29208 a

1assistance charge on all its retail customers for the Energy 
2Transition Assistance Fund. The utility's total charge shall 
3be set based upon the value determined by the Department of 
4Commerce and Economic Opportunity pursuant to subsection (d) 
5or (e), as applicable, of Section 605-1075 of the Department 
6of Commerce and Economic Opportunity Law of the Civil 
7Administrative Code of Illinois. For each utility, the charge 
8shall be recovered through a single, uniform cents per 
9kilowatt-hour charge applicable to all retail customers. For 
10each utility, the charge shall not exceed 1.45% 1.3% of the 
11amount paid per kilowatthour by eligible retail customers 
12during the year ending May 31, 2009. Beginning January 1, 
132028, the limitation shall be increased by an additional 0.636 
14percentage points of the amount paid per kilowatt-hour by 
15eligible retail customers during the year ending May 31, 2009, 
16which would collect the equivalent of the average annual 
17budget of the programs administered by the utilities under 
18Section 45 of the Electric Vehicle Act for the years 2026 
19through 2028.    
20    (c) Within 75 days of the effective date of this 
21amendatory Act of the 102nd General Assembly, each electric 
22utility serving more than 500,000 customers in the State shall 
23file with the Illinois Commerce Commission tariffs 
24incorporating the energy transition assistance charge in other 
25charges stated in such tariffs, which energy transition 
26assistance charges shall become effective no later than the 
 
 
10400SB0025ham003- 752 -LRB104 07069 AAS 29208 a

1beginning of the first billing cycle that begins on or after 
2January 1, 2022. Each electric utility serving more than 
3500,000 customers in the State shall, prior to the beginning 
4of each calendar year starting with calendar year 2023, file 
5with the Illinois Commerce Commission tariff revisions to 
6incorporate annual revisions to the energy transition 
7assistance charge as prescribed by the Department of Commerce 
8and Economic Opportunity pursuant to Section 605-1075 of the 
9Department of Commerce and Economic Opportunity Law of the 
10Civil Administrative Code of Illinois so that such revision 
11becomes effective no later than the beginning of the first 
12billing cycle in each respective year.
13    (d) The energy transition assistance charge shall be 
14considered a charge for public utility service.
15    (e) By the 20th day of the month following the month in 
16which the charges imposed by this Section were collected, each 
17electric utility serving more than 500,000 customers in the 
18State shall remit to Department of Revenue all moneys received 
19as payment of the energy transition assistance charge on a 
20return prescribed and furnished by the Department of Revenue 
21showing such information as the Department of Revenue may 
22reasonably require. If a customer makes a partial payment, a 
23public utility may apply such partial payments first to 
24amounts owed to the utility. No customer may be subjected to 
25disconnection of his or her utility service for failure to pay 
26the energy transition assistance charge.
 
 
10400SB0025ham003- 753 -LRB104 07069 AAS 29208 a

1    If any payment provided for in this subsection exceeds the 
2electric utility's liabilities under this Act, as shown on an 
3original return, the Department may authorize the electric 
4utility to credit such excess payment against liability 
5subsequently to be remitted to the Department under this Act, 
6in accordance with reasonable rules adopted by the Department.
7    All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e, 
85f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13 
9of the Retailers' Occupation Tax Act that are not inconsistent 
10with this Act apply, as far as practicable, to the charge 
11imposed by this Act to the same extent as if those provisions 
12were included in this Act. References in the incorporated 
13Sections of the Retailers' Occupation Tax Act to retailers, to 
14sellers, or to persons engaged in the business of selling 
15tangible personal property mean persons required to remit the 
16charge imposed under this Act.
17    (f) The Department of Revenue shall deposit into the 
18Energy Transition Assistance Fund all moneys remitted to it in 
19accordance with this Section.
20    (g) The Department of Revenue may establish such rules as 
21it deems necessary to implement this Section.
22    (h) The Department of Commerce and Economic Opportunity 
23may establish such rules as it deems necessary to implement 
24this Section. 
25(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
 
 
 
10400SB0025ham003- 754 -LRB104 07069 AAS 29208 a

1    (220 ILCS 5/16-111.5)
2    Sec. 16-111.5. Provisions relating to procurement.
3    (a) An electric utility that on December 31, 2005 served 
4at least 100,000 customers in Illinois shall procure power and 
5energy for its eligible retail customers in accordance with 
6the applicable provisions set forth in Section 1-75 of the 
7Illinois Power Agency Act and this Section. Beginning with the 
8delivery year commencing on June 1, 2017, such electric 
9utility shall also procure zero emission credits from zero 
10emission facilities in accordance with the applicable 
11provisions set forth in Section 1-75 of the Illinois Power 
12Agency Act, and, for years beginning on or after June 1, 2017, 
13the utility shall procure renewable energy resources in 
14accordance with the applicable provisions set forth in Section 
151-75 of the Illinois Power Agency Act and this Section. 
16Beginning with the delivery year commencing on June 1, 2022, 
17an electric utility serving over 3,000,000 customers shall 
18also procure carbon mitigation credits from carbon-free energy 
19resources in accordance with the applicable provisions set 
20forth in Section 1-75 of the Illinois Power Agency Act and this 
21Section. Beginning with the delivery year commencing on June 
221, 2026, an electric utility serving more than 300,000 
23customers in the State as of January 1, 2019 shall also procure 
24energy storage resources in accordance with the applicable 
25provisions of subsection (d-20) of Section 1-75 of the 
26Illinois Power Agency Act and this Section. A small 
 
 
10400SB0025ham003- 755 -LRB104 07069 AAS 29208 a

1multi-jurisdictional electric utility that on December 31, 
22005 served less than 100,000 customers in Illinois may elect 
3to procure power and energy for all or a portion of its 
4eligible Illinois retail customers in accordance with the 
5applicable provisions set forth in this Section and Section 
61-75 of the Illinois Power Agency Act. This Section shall not 
7apply to a small multi-jurisdictional utility until such time 
8as a small multi-jurisdictional utility requests the Illinois 
9Power Agency to prepare a procurement plan for its eligible 
10retail customers. "Eligible retail customers" for the purposes 
11of this Section means those retail customers that purchase 
12power and energy from the electric utility under fixed-price 
13bundled service tariffs, other than those retail customers 
14whose service is declared or deemed competitive under Section 
1516-113 and those other customer groups specified in this 
16Section, including self-generating customers, customers 
17electing hourly pricing, or those customers who are otherwise 
18ineligible for fixed-price bundled tariff service. Except as 
19otherwise provided for in subsection (b-10), for For those 
20customers that are excluded from the procurement plan's 
21electric supply service requirements, and the utility shall 
22procure any supply requirements, including capacity, ancillary 
23services, and hourly priced energy, in the applicable markets 
24as needed to serve those customers, provided that the utility 
25may include in its procurement plan load requirements for the 
26load that is associated with those retail customers whose 
 
 
10400SB0025ham003- 756 -LRB104 07069 AAS 29208 a

1service has been declared or deemed competitive pursuant to 
2Section 16-113 of this Act to the extent that those customers 
3are purchasing power and energy during one of the transition 
4periods identified in subsection (b) of Section 16-113 of this 
5Act. 
6    (b) A procurement plan shall be prepared for each electric 
7utility consistent with the applicable requirements of the 
8Illinois Power Agency Act and this Section. For purposes of 
9this Section, Illinois electric utilities that are affiliated 
10by virtue of a common parent company are considered to be a 
11single electric utility. Small multi-jurisdictional utilities 
12may request a procurement plan for a portion of or all of its 
13Illinois load. Each procurement plan shall analyze the 
14projected balance of supply and demand for those retail 
15customers to be included in the plan's electric supply service 
16requirements over a 5-year period, with the first planning 
17year beginning on June 1 of the year following the year in 
18which the plan is filed. The plan shall specifically identify 
19the wholesale products to be procured following plan approval, 
20and shall follow all the requirements set forth in the Public 
21Utilities Act and all applicable State and federal laws, 
22statutes, rules, or regulations, as well as Commission orders. 
23Nothing in this Section precludes consideration of contracts 
24longer than 5 years and related forecast data. Unless 
25specified otherwise in this Section, in the procurement plan 
26or in the implementing tariff, any procurement occurring in 
 
 
10400SB0025ham003- 757 -LRB104 07069 AAS 29208 a

1accordance with this plan shall be competitively bid through a 
2request for proposals process. Approval and implementation of 
3the procurement plan shall be subject to review and approval 
4by the Commission according to the provisions set forth in 
5this Section. A procurement plan shall include each of the 
6following components:
7        (1) Hourly load analysis. This analysis shall include:
8            (i) multi-year historical analysis of hourly 
9        loads;
10            (ii) switching trends and competitive retail 
11        market analysis;
12            (iii) known or projected changes to future loads; 
13        and
14            (iv) growth forecasts by customer class.
15        (2) Analysis of the impact of any demand side and 
16    renewable energy initiatives. This analysis shall include:
17            (i) the impact of demand response programs and 
18        energy efficiency programs, both current and 
19        projected; for small multi-jurisdictional utilities, 
20        the impact of demand response and energy efficiency 
21        programs approved pursuant to Section 8-408 of this 
22        Act, both current and projected; and
23            (ii) supply side needs that are projected to be 
24        offset by purchases of renewable energy resources, if 
25        any.
26        (3) A plan for meeting the expected load requirements 
 
 
10400SB0025ham003- 758 -LRB104 07069 AAS 29208 a

1    that will not be met through preexisting contracts. This 
2    plan shall include:
3            (i) definitions of the different Illinois retail 
4        customer classes for which supply is being purchased;
5            (ii) the proposed mix of demand-response products 
6        for which contracts will be executed during the next 
7        year. For small multi-jurisdictional electric 
8        utilities that on December 31, 2005 served fewer than 
9        100,000 customers in Illinois, these shall be defined 
10        as demand-response products offered in an energy 
11        efficiency plan approved pursuant to Section 8-408 of 
12        this Act. The cost-effective demand-response measures 
13        shall be procured whenever the cost is lower than 
14        procuring comparable capacity products, provided that 
15        such products shall: 
16                (A) be procured by a demand-response provider 
17            from those retail customers included in the plan's 
18            electric supply service requirements;
19                (B) at least satisfy the demand-response 
20            requirements of the regional transmission 
21            organization market in which the utility's service 
22            territory is located, including, but not limited 
23            to, any applicable capacity or dispatch 
24            requirements;
25                (C) provide for customers' participation in 
26            the stream of benefits produced by the 
 
 
10400SB0025ham003- 759 -LRB104 07069 AAS 29208 a

1            demand-response products;
2                (D) provide for reimbursement by the 
3            demand-response provider of the utility for any 
4            costs incurred as a result of the failure of the 
5            supplier of such products to perform its 
6            obligations thereunder; and
7                (E) meet the same credit requirements as apply 
8            to suppliers of capacity, in the applicable 
9            regional transmission organization market; 
10            (iii) monthly forecasted system supply 
11        requirements, including expected minimum, maximum, and 
12        average values for the planning period;
13            (iv) the proposed mix and selection of standard 
14        wholesale products for which contracts will be 
15        executed during the next year, separately or in 
16        combination, to meet that portion of its load 
17        requirements not met through pre-existing contracts, 
18        including but not limited to monthly 5 x 16 peak period 
19        block energy, monthly off-peak wrap energy, monthly 7 
20        x 24 energy, annual 5 x 16 energy, other standardized 
21        energy or capacity products designed to provide 
22        eligible retail customer benefits from commercially 
23        deployed advanced technologies including but not 
24        limited to high voltage direct current converter 
25        stations, as such term is defined in Section 1-10 of 
26        the Illinois Power Agency Act, whether or not such 
 
 
10400SB0025ham003- 760 -LRB104 07069 AAS 29208 a

1        product is currently available in wholesale markets, 
2        annual off-peak wrap energy, annual 7 x 24 energy, 
3        monthly capacity, annual capacity, peak load capacity 
4        obligations, capacity purchase plan, and ancillary 
5        services;
6            (v) proposed term structures for each wholesale 
7        product type included in the proposed procurement plan 
8        portfolio of products; and
9            (vi) an assessment of the price risk, load 
10        uncertainty, and other factors that are associated 
11        with the proposed procurement plan; this assessment, 
12        to the extent possible, shall include an analysis of 
13        the following factors: contract terms, time frames for 
14        securing products or services, fuel costs, weather 
15        patterns, transmission costs, market conditions, and 
16        the governmental regulatory environment; the proposed 
17        procurement plan shall also identify alternatives for 
18        those portfolio measures that are identified as having 
19        significant price risk and mitigation in the form of 
20        additional retail customer and ratepayer price, 
21        reliability, and environmental benefits from 
22        standardized energy products delivered from 
23        commercially deployed advanced technologies, 
24        including, but not limited to, high voltage direct 
25        current converter stations, as such term is defined in 
26        Section 1-10 of the Illinois Power Agency Act, whether 
 
 
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1        or not such product is currently available in 
2        wholesale markets.
3        (4) Proposed procedures for balancing loads. The 
4    procurement plan shall include, for load requirements 
5    included in the procurement plan, the process for (i) 
6    hourly balancing of supply and demand and (ii) the 
7    criteria for portfolio re-balancing in the event of 
8    significant shifts in load.
9        (5) Long-Term Renewable Resources Procurement Plan. 
10    The Agency shall prepare a long-term renewable resources 
11    procurement plan for the procurement of renewable energy 
12    credits under Sections 1-56 and 1-75 of the Illinois Power 
13    Agency Act for delivery beginning in the 2017 delivery 
14    year.
15            (i) The initial long-term renewable resources 
16        procurement plan and all subsequent revisions shall be 
17        subject to review and approval by the Commission. For 
18        the purposes of this Section, "delivery year" has the 
19        same meaning as in Section 1-10 of the Illinois Power 
20        Agency Act. For purposes of this Section, "Agency" 
21        shall mean the Illinois Power Agency.
22            (ii) The long-term renewable resources planning 
23        process shall be conducted as follows:
24                (A) Electric utilities shall provide a range 
25            of load forecasts to the Illinois Power Agency 
26            within 45 days of the Agency's request for 
 
 
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1            forecasts, which request shall specify the length 
2            and conditions for the forecasts including, but 
3            not limited to, the quantity of distributed 
4            generation expected to be interconnected for each 
5            year.
6                (B) The Agency shall publish for comment the 
7            initial long-term renewable resources procurement 
8            plan no later than 120 days after the effective 
9            date of this amendatory Act of the 99th General 
10            Assembly and shall review, and may revise, the 
11            plan at least every 2 years thereafter. To the 
12            extent practicable, the Agency shall review and 
13            propose any revisions to the long-term renewable 
14            energy resources procurement plan in conjunction 
15            with the Agency's other planning and approval 
16            processes conducted under this Section. Plans may 
17            be released on separate dates, but the Agency 
18            shall, to the extent practicable, release both 
19            plans across a 30-day period. The initial 
20            long-term renewable resources procurement plan 
21            shall:
22                    (aa) Identify the procurement programs and 
23                competitive procurement events consistent with 
24                the applicable requirements of the Illinois 
25                Power Agency Act and shall be designed to 
26                achieve the goals set forth in subsection (c) 
 
 
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1                of Section 1-75 of that Act.
2                    (bb) Include a schedule for procurements 
3                for renewable energy credits from 
4                utility-scale wind projects, utility-scale 
5                solar projects, and brownfield site 
6                photovoltaic projects consistent with 
7                subparagraph (G) of paragraph (1) of 
8                subsection (c) of Section 1-75 of the Illinois 
9                Power Agency Act.
10                    (cc) Identify the process whereby the 
11                Agency will submit to the Commission for 
12                review and approval the proposed contracts to 
13                implement the programs required by such plan.
14                If so authorized by the Commission in its 
15            order approving the procurement plan, the 
16            procurement plan shall provide that small 
17            multi-jurisdictional electric utilities that, on 
18            December 31, 2005, served fewer than 100,000 
19            customers in Illinois shall, in lieu of serving as 
20            counterparties to contracts for the delivery of 
21            renewable energy credits, instead provide an 
22            amount equivalent to the contracts for the 
23            delivery of renewable energy credits in 
24            collections to utilities that served at least 
25            100,000 customers in Illinois as a compliance 
26            payment for the procurement of additional 
 
 
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1            renewable energy credits to satisfy that small 
2            multi-jurisdictional electric utility's 
3            obligation for compliance with the goals set forth 
4            in subsection (c) of Section 1-75 of the Illinois 
5            Power Agency Act. This authorization may include 
6            the transfer of existing contract obligations.    
7                Copies of the initial long-term renewable 
8            resources procurement plan and all subsequent 
9            revisions shall be posted and made publicly 
10            available on the Agency's and Commission's 
11            websites, and copies shall also be provided to 
12            each affected electric utility. An affected 
13            utility and other interested parties shall have 45 
14            days following the date of posting to provide 
15            comment to the Agency on the initial long-term 
16            renewable resources procurement plan and all 
17            subsequent revisions. All comments submitted to 
18            the Agency shall be specific, supported by data or 
19            other detailed analyses, and, if objecting to all 
20            or a portion of the procurement plan, accompanied 
21            by specific alternative wording or proposals. All 
22            comments shall be posted on the Agency's and 
23            Commission's websites. During this 45-day comment 
24            period, the Agency shall hold at least one virtual 
25            or in-person public hearing for within each 
26            utility's service area that is subject to the 
 
 
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1            requirements of this paragraph (5) for the purpose 
2            of receiving public comment. Within 21 days 
3            following the end of the 45-day review period, the 
4            Agency may revise the long-term renewable 
5            resources procurement plan based on the comments 
6            received and shall file the plan with the 
7            Commission for review and approval.
8                (C) Within 14 days after the filing of the 
9            initial long-term renewable resources procurement 
10            plan or any subsequent revisions, any person 
11            objecting to the plan may file an objection with 
12            the Commission. Within 21 days after the filing of 
13            the plan, the Commission shall determine whether a 
14            hearing is necessary. The Commission shall enter 
15            its order confirming or modifying the initial 
16            long-term renewable resources procurement plan or 
17            any subsequent revisions within 120 days after the 
18            filing of the plan by the Illinois Power Agency.
19                (D) The Commission shall approve the initial 
20            long-term renewable resources procurement plan and 
21            any subsequent revisions, including expressly the 
22            forecast used in the plan and taking into account 
23            that funding will be limited to the amount of 
24            revenues actually collected by the utilities, if 
25            the Commission determines that the plan will 
26            reasonably and prudently accomplish the 
 
 
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1            requirements of Section 1-56 and subsection (c) of 
2            Section 1-75 of the Illinois Power Agency Act. The 
3            Commission shall also approve the process for the 
4            submission, review, and approval of the proposed 
5            contracts to procure renewable energy credits or 
6            implement the programs authorized by the 
7            Commission pursuant to a long-term renewable 
8            resources procurement plan approved under this 
9            Section.
10                In approving any long-term renewable resources 
11            procurement plan after the effective date of this 
12            amendatory Act of the 102nd General Assembly, the 
13            Commission shall approve or modify the Agency's 
14            proposal for minimum equity standards pursuant to 
15            subsection (c-10) of Section 1-75 of the Illinois 
16            Power Agency Act. The Commission shall consider 
17            any analysis performed by the Agency in developing 
18            its proposal, including past performance, 
19            availability of equity eligible contractors, and 
20            availability of equity eligible persons at the 
21            time the long-term renewable resources procurement 
22            plan is approved. 
23            (iii) The Agency or third parties contracted by 
24        the Agency shall implement all programs authorized by 
25        the Commission in an approved long-term renewable 
26        resources procurement plan without further review and 
 
 
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1        approval by the Commission. Third parties shall not 
2        begin implementing any programs or receive any payment 
3        under this Section until the Commission has approved 
4        the contract or contracts under the process authorized 
5        by the Commission in item (D) of subparagraph (ii) of 
6        paragraph (5) of this subsection (b) and the third 
7        party and the Agency or utility, as applicable, have 
8        executed the contract. For those renewable energy 
9        credits subject to procurement through a competitive 
10        bid process under the plan or under the initial 
11        forward procurements for wind and solar resources 
12        described in subparagraph (G) of paragraph (1) of 
13        subsection (c) of Section 1-75 of the Illinois Power 
14        Agency Act, the Agency shall follow the procurement 
15        process specified in the provisions relating to 
16        electricity procurement in subsections (e) through (i) 
17        of this Section.
18            (iv) An electric utility shall recover its costs 
19        associated with the procurement of renewable energy 
20        credits under this Section and pursuant to subsection 
21        (c-5) of Section 1-75 of the Illinois Power Agency Act 
22        through an automatic adjustment clause tariff under 
23        subsection (k) or a tariff pursuant to subsection 
24        (i-5), as applicable, of Section 16-108 of this Act. A 
25        utility shall not be required to advance any payment 
26        or pay any amounts under this Section that exceed the 
 
 
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1        actual amount of revenues collected by the utility 
2        under paragraph (6) of subsection (c) of Section 1-75 
3        of the Illinois Power Agency Act, subsection (c-5) of 
4        Section 1-75 of the Illinois Power Agency Act, and 
5        subsection (k) or subsection (i-5), as applicable, of 
6        Section 16-108 of this Act, and contracts executed 
7        under this Section shall expressly incorporate this 
8        limitation.
9            (v) For the public interest, safety, and welfare, 
10        the Agency and the Commission may adopt rules to carry 
11        out the provisions of this Section on an emergency 
12        basis immediately following the effective date of this 
13        amendatory Act of the 99th General Assembly.
14            (vi) On or before July 1 of each year, the 
15        Commission shall hold an informal hearing for the 
16        purpose of receiving comments on the prior year's 
17        procurement process and any recommendations for 
18        change. 
19        (6) Energy Storage System Resources Procurement Plan. 
20    The Agency shall prepare an energy storage system 
21    resources procurement plan for the procurement of energy 
22    storage system resources in compliance with this Section 
23    and subsection (d-20) of Section 1-75 of the Illinois 
24    Power Agency Act.
25            (i) The initial energy storage system resources 
26        procurement plan and all subsequent revisions shall be 
 
 
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1        subject to review and approval by the Commission. For 
2        the purposes of this paragraph (6), "delivery year" 
3        has the meaning given to that term in Section 1-10 of 
4        the Illinois Power Agency Act, and "Agency" means the 
5        Illinois Power Agency.
6            (ii) The energy storage system resources 
7        procurement planning process shall be conducted as 
8        follows:
9                (A) The Agency shall publish for comment the 
10            initial energy storage system resources 
11            procurement plan no later than June 1, 2027 and 
12            may revise the plan at least every 2 years 
13            thereafter. To the extent practicable, the Agency 
14            shall review and propose any revisions to the 
15            energy storage system resources procurement plan 
16            in conjunction with the Agency's long-term 
17            renewable resources procurement plan. The initial 
18            energy storage system resources plan shall:
19                    (aa) include a schedule for procurements 
20                for energy storage system resources consistent 
21                with subsection (d-20) of Section 1-75 of the 
22                Illinois Power Agency Act; and
23                    (bb) identify the process whereby the 
24                Agency will submit to the Commission for 
25                review and approval the proposed contracts to 
26                implement the programs required by the plan.
 
 
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1                Copies of the initial energy storage system 
2            resources procurement plan and all subsequent 
3            revisions shall be posted and made publicly 
4            available on the Agency's and Commission's 
5            websites, and copies shall also be provided to 
6            each affected electric utility. An affected 
7            utility and other interested parties shall have 45 
8            days after the date of posting to provide comment 
9            to the Agency on the initial storage system 
10            resources procurement plan and all subsequent 
11            revisions. All comments shall be posted on the 
12            Agency's and the Commission's websites.
13                (B) The Commission shall approve the initial 
14            energy storage system resources procurement plan 
15            and any subsequent revisions if the Commission 
16            determines that the plan will reasonably and 
17            prudently accomplish the requirements of 
18            subsection (d-20) of Section 1-75 of the Illinois 
19            Power Agency Act. The Commission shall also 
20            approve the process for the submission, review, 
21            and approval of the proposed contracts to procure 
22            energy storage system resources or implement the 
23            programs authorized by the Commission pursuant to 
24            an energy storage system resources procurement 
25            plan approved under this Section.
26            (iii) The Agency or third parties contracted by 
 
 
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1        the Agency shall implement all programs authorized by 
2        the Commission in an approved energy storage system 
3        resources procurement plan without further review and 
4        approval by the Commission. Third parties shall not 
5        begin implementing any programs or receive any payment 
6        under this Section until the Commission has approved a 
7        contract under the energy storage system resources 
8        procurement process under this Section.
9            (iv) An electric utility shall recover its prudent 
10        and reasonable costs associated with the procurement 
11        of energy storage system resources procurements under 
12        this Section and under subsection (d-20) of Section 
13        1-75 of the Illinois Power Agency Act through an 
14        automatic adjustment clause tariff under subsection 
15        (k) of Section 16-108.    
16    (b-5) An electric utility that as of January 1, 2019 
17served more than 300,000 retail customers in this State shall 
18purchase renewable energy credits from new renewable energy 
19facilities constructed at or adjacent to the sites of 
20coal-fueled electric generating facilities in this State in 
21accordance with subsection (c-5) of Section 1-75 of the 
22Illinois Power Agency Act and shall purchase energy storage 
23credits, or other services as applicable, for energy storage 
24system resources in accordance with subsection (d-20) of 
25Section 1-75 of the Illinois Power Agency Act. Except as 
26expressly provided in this Section, the plans and procedures 
 
 
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1for such procurements shall not be included in the procurement 
2plans provided for in this Section, but rather shall be 
3conducted and implemented solely in accordance with subsection 
4(c-5) of Section 1-75 of the Illinois Power Agency Act.
5    (b-10) Beginning with the procurement plan for the 
6delivery year commencing on June 1, 2027, in recognition of 
7the potential need to facilitate additional supply to address 
8any resource adequacy challenges through a stable and 
9competitively neutral cost allocation mechanism, upon an 
10identification of need by the Commission in the resource 
11adequacy report prepared pursuant to subsection (o) of Section 
129.15 of the Environmental Protection Act, and as such need is 
13updated by the integrated resource planning process outlined 
14in subsection (b), the procurement plan may also include the 
15procurement of energy, capacity, environmental attributes, 
16resource adequacy attributes, or some combination thereof 
17intended to serve all retail customers. Any procurements 
18proposed under this subsection (b-10) shall feature long-term 
19contracts, shall be structured to facilitate new and additive 
20supply resources, and shall be sized to ensure that the 
21substantial majority of any load-serving entity's supply 
22portfolio is not composed of contracts awarded under this 
23subsection (b-10).
24        (1) Facilities eligible for long-term contracts under 
25    this subsection (b-10) must be new clean energy resources, 
26    as defined in Section 1-10 of the Illinois Power Agency 
 
 
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1    Act, including clean generation associated high voltage 
2    direct current transmission facilities, and must qualify 
3    as an accredited capacity resource within the service 
4    areas of PJM Interconnection, LLC, or Midcontinent 
5    Independent System Operator, Inc. For purposes of this 
6    subsection (b-10), "new" means energized on or after the 
7    effective date of this amendatory Act of the 104th General 
8    Assembly.
9        (2) Contracts may take the form of a sourcing 
10    agreement, power purchase agreement, or other instrument 
11    as determined by the Commission in approving the plan, and 
12    may feature fixed or variable pricing structures, 
13    including utilization of a contract for differences in 
14    pricing structure. Contracts may feature both electric 
15    utilities and alternative retail electric suppliers as 
16    counterparties. In approving the contract structure 
17    utilized for any contract awards made pursuant to this 
18    subsection (b-10), the Commission shall prioritize 
19    structures that ensure stable, reliable, and competitively 
20    neutral allocations of costs and responsibilities.
21        (3) Purchases made under contracts awarded through 
22    this subsection (b-10) shall be funded in a competitively 
23    neutral manner as determined by the Commission in 
24    approving the plan. To meet contract obligations, the 
25    Commission may order collections from all retail customers 
26    or from all load-serving entities, including alternative 
 
 
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1    retail electric suppliers as defined in Section 16-102 of 
2    this Act, as a means of ensuring a fair and competitively 
3    neutral allocation of contract costs. In establishing 
4    collections, the Agency may propose and the Commission may 
5    approve adjustments for load-serving entities that have 
6    contracts entered into before the effective date of this 
7    amendatory Act of the 104th General Assembly for energy, 
8    capacity, or environmental attributes.
9        (4) The Agency may propose and the Commission may 
10    approve additional terms, conditions, and requirements 
11    applicable to this procurement process through development 
12    and approval of the Agency's annual electricity 
13    procurement plan.
14        (5) The manner and form for developing contracts, 
15    qualifying potential counterparties, and awarding 
16    contracts shall be proposed as part of the annual 
17    electricity procurement plan described in this subsection 
18    (b-10). However, to the extent practicable, the proposed 
19    approach for contract development and award should 
20    endeavor to follow the provisions of subsections (c) and 
21    (e) through (i) of this Section.
22        (6) As further outlined in Section 16-115A, compliance 
23    with any procurement process proposed under this 
24    subsection (b-10) shall be considered a condition of 
25    service for alternative retail electric suppliers.    
26    (c) The provisions of this subsection (c) shall not apply 
 
 
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1to procurements conducted pursuant to subsection (c-5) of 
2Section 1-75 of the Illinois Power Agency Act. However, the 
3Agency may retain a procurement administrator to assist the 
4Agency in planning and carrying out the procurement events and 
5implementing the other requirements specified in such 
6subsection (c-5) of Section 1-75 of the Illinois Power Agency 
7Act, with the costs incurred by the Agency for the procurement 
8administrator to be recovered through fees charged to 
9applicants for selection to sell and deliver renewable energy 
10credits to electric utilities pursuant to subsection (c-5) of 
11Section 1-75 of the Illinois Power Agency Act. The procurement 
12process set forth in Section 1-75 of the Illinois Power Agency 
13Act and subsection (e) of this Section shall be administered 
14by a procurement administrator and monitored by a procurement 
15monitor.
16        (1) The procurement administrator shall:
17            (i) design the final procurement process in 
18        accordance with Section 1-75 of the Illinois Power 
19        Agency Act and subsection (e) of this Section 
20        following Commission approval of the procurement plan;
21            (ii) develop benchmarks in accordance with 
22        subsection (e)(3) to be used to evaluate bids; these 
23        benchmarks shall be submitted to the Commission for 
24        review and approval on a confidential basis prior to 
25        the procurement event;
26            (iii) serve as the interface between the electric 
 
 
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1        utility and suppliers;
2            (iv) manage the bidder pre-qualification and 
3        registration process;
4            (v) obtain the electric utilities' agreement to 
5        the final form of all supply contracts and credit 
6        collateral agreements;
7            (vi) administer the request for proposals process;
8            (vii) have the discretion to negotiate to 
9        determine whether bidders are willing to lower the 
10        price of bids that meet the benchmarks approved by the 
11        Commission; any post-bid negotiations with bidders 
12        shall be limited to price only and shall be completed 
13        within 24 hours after opening the sealed bids and 
14        shall be conducted in a fair and unbiased manner; in 
15        conducting the negotiations, there shall be no 
16        disclosure of any information derived from proposals 
17        submitted by competing bidders; if information is 
18        disclosed to any bidder, it shall be provided to all 
19        competing bidders;
20            (viii) maintain confidentiality of supplier and 
21        bidding information in a manner consistent with all 
22        applicable laws, rules, regulations, and tariffs;
23            (ix) submit a confidential report to the 
24        Commission recommending acceptance or rejection of 
25        bids;
26            (x) notify the utility of contract counterparties 
 
 
10400SB0025ham003- 777 -LRB104 07069 AAS 29208 a

1        and contract specifics; and
2            (xi) administer related contingency procurement 
3        events.
4        (2) The procurement monitor, who shall be retained by 
5    the Commission, shall:
6            (i) monitor interactions among the procurement 
7        administrator, suppliers, and utility;
8            (ii) monitor and report to the Commission on the 
9        progress of the procurement process;
10            (iii) provide an independent confidential report 
11        to the Commission regarding the results of the 
12        procurement event;
13            (iv) assess compliance with the procurement plans 
14        approved by the Commission for each utility that on 
15        December 31, 2005 provided electric service to at 
16        least 100,000 customers in Illinois and for each small 
17        multi-jurisdictional utility that on December 31, 2005 
18        served less than 100,000 customers in Illinois;
19            (v) preserve the confidentiality of supplier and 
20        bidding information in a manner consistent with all 
21        applicable laws, rules, regulations, and tariffs;
22            (vi) provide expert advice to the Commission and 
23        consult with the procurement administrator regarding 
24        issues related to procurement process design, rules, 
25        protocols, and policy-related matters; and
26            (vii) consult with the procurement administrator 
 
 
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1        regarding the development and use of benchmark 
2        criteria, standard form contracts, credit policies, 
3        and bid documents.
4    (d) Except as provided in subsection (j), the planning 
5process shall be conducted as follows:
6        (1) Beginning in 2008, each Illinois utility procuring 
7    power pursuant to this Section shall annually provide a 
8    range of load forecasts to the Illinois Power Agency by 
9    July 15 of each year, or such other date as may be required 
10    by the Commission or Agency. The load forecasts shall 
11    cover the 5-year procurement planning period for the next 
12    procurement plan and shall include hourly data 
13    representing a high-load, low-load, and expected-load 
14    scenario for the load of those retail customers included 
15    in the plan's electric supply service requirements. The 
16    utility shall provide supporting data and assumptions for 
17    each of the scenarios. 
18        (2) Beginning in 2008, the Illinois Power Agency shall 
19    prepare a procurement plan by August 15th of each year, or 
20    such other date as may be required by the Commission. The 
21    procurement plan shall identify the portfolio of 
22    demand-response and power and energy products to be 
23    procured. Cost-effective demand-response measures shall be 
24    procured as set forth in item (iii) of subsection (b) of 
25    this Section. Copies of the procurement plan shall be 
26    posted and made publicly available on the Agency's and 
 
 
10400SB0025ham003- 779 -LRB104 07069 AAS 29208 a

1    Commission's websites, and copies shall also be provided 
2    to each affected electric utility. An affected utility 
3    shall have 30 days following the date of posting to 
4    provide comment to the Agency on the procurement plan. 
5    Other interested entities also may comment on the 
6    procurement plan. All comments submitted to the Agency 
7    shall be specific, supported by data or other detailed 
8    analyses, and, if objecting to all or a portion of the 
9    procurement plan, accompanied by specific alternative 
10    wording or proposals. All comments shall be posted on the 
11    Agency's and Commission's websites. During this 30-day 
12    comment period, the Agency shall hold at least one virtual 
13    or in-person public hearing for within each utility's 
14    service area for the purpose of receiving public comment 
15    on the procurement plan. Within 14 days following the end 
16    of the 30-day review period, the Agency shall revise the 
17    procurement plan as necessary based on the comments 
18    received and file the procurement plan with the Commission 
19    and post the procurement plan on the websites.
20        (3) Within 5 days after the filing of the procurement 
21    plan, any person objecting to the procurement plan shall 
22    file an objection with the Commission. Within 10 days 
23    after the filing, the Commission shall determine whether a 
24    hearing is necessary. The Commission shall enter its order 
25    confirming or modifying the procurement plan within 90 
26    days after the filing of the procurement plan by the 
 
 
10400SB0025ham003- 780 -LRB104 07069 AAS 29208 a

1    Illinois Power Agency.
2        (4) The Commission shall approve the procurement plan, 
3    including expressly the forecast used in the procurement 
4    plan, if the Commission determines that it will ensure 
5    adequate, reliable, affordable, efficient, and 
6    environmentally sustainable electric service at the lowest 
7    total cost over time, taking into account any benefits of 
8    price stability.
9        (4.5) The Commission shall review the Agency's 
10    recommendations for the selection of applicants to enter 
11    into long-term contracts for the sale and delivery of 
12    renewable energy credits from new renewable energy 
13    facilities to be constructed at or adjacent to the sites 
14    of coal-fueled electric generating facilities in this 
15    State in accordance with the provisions of subsection 
16    (c-5) of Section 1-75 of the Illinois Power Agency Act, 
17    and shall approve the Agency's recommendations if the 
18    Commission determines that the applicants recommended by 
19    the Agency for selection, the proposed new renewable 
20    energy facilities to be constructed, the amounts of 
21    renewable energy credits to be delivered pursuant to the 
22    contracts, and the other terms of the contracts, are 
23    consistent with the requirements of subsection (c-5) of 
24    Section 1-75 of the Illinois Power Agency Act. 
25    (e) The procurement process shall include each of the 
26following components:
 
 
10400SB0025ham003- 781 -LRB104 07069 AAS 29208 a

1        (1) Solicitation, pre-qualification, and registration 
2    of bidders. The procurement administrator shall 
3    disseminate information to potential bidders to promote a 
4    procurement event, notify potential bidders that the 
5    procurement administrator may enter into a post-bid price 
6    negotiation with bidders that meet the applicable 
7    benchmarks, provide supply requirements, and otherwise 
8    explain the competitive procurement process. In addition 
9    to such other publication as the procurement administrator 
10    determines is appropriate, this information shall be 
11    posted on the Illinois Power Agency's and the Commission's 
12    websites. The procurement administrator shall also 
13    administer the prequalification process, including 
14    evaluation of credit worthiness, compliance with 
15    procurement rules, and agreement to the standard form 
16    contract developed pursuant to paragraph (2) of this 
17    subsection (e). The procurement administrator shall then 
18    identify and register bidders to participate in the 
19    procurement event.
20        (2) Standard contract forms and credit terms and 
21    instruments. The procurement administrator, in 
22    consultation with the utilities, the Commission, and other 
23    interested parties and subject to Commission oversight, 
24    shall develop and provide standard contract forms for the 
25    supplier contracts that meet generally accepted industry 
26    practices. Standard credit terms and instruments that meet 
 
 
10400SB0025ham003- 782 -LRB104 07069 AAS 29208 a

1    generally accepted industry practices shall be similarly 
2    developed. The procurement administrator shall make 
3    available to the Commission all written comments it 
4    receives on the contract forms, credit terms, or 
5    instruments. If the procurement administrator cannot reach 
6    agreement with the applicable electric utility as to the 
7    contract terms and conditions, the procurement 
8    administrator must notify the Commission of any disputed 
9    terms and the Commission shall resolve the dispute. The 
10    terms of the contracts shall not be subject to negotiation 
11    by winning bidders, and the bidders must agree to the 
12    terms of the contract in advance so that winning bids are 
13    selected solely on the basis of price.
14        (3) Establishment of a market-based price benchmark. 
15    As part of the development of the procurement process, the 
16    procurement administrator, in consultation with the 
17    Commission staff, Agency staff, and the procurement 
18    monitor, shall establish benchmarks for evaluating the 
19    final prices in the contracts for each of the products 
20    that will be procured through the procurement process. The 
21    benchmarks shall be based on price data for similar 
22    products for the same delivery period and same delivery 
23    hub, or other delivery hubs after adjusting for that 
24    difference. The price benchmarks may also be adjusted to 
25    take into account differences between the information 
26    reflected in the underlying data sources and the specific 
 
 
10400SB0025ham003- 783 -LRB104 07069 AAS 29208 a

1    products and procurement process being used to procure 
2    power for the Illinois utilities. The benchmarks shall be 
3    confidential but shall be provided to, and will be subject 
4    to Commission review and approval, prior to a procurement 
5    event.
6        (4) Request for proposals competitive procurement 
7    process. The procurement administrator shall design and 
8    issue a request for proposals to supply electricity in 
9    accordance with each utility's procurement plan, as 
10    approved by the Commission. The request for proposals 
11    shall set forth a procedure for sealed, binding commitment 
12    bidding with pay-as-bid settlement, and provision for 
13    selection of bids on the basis of price.
14        (5) A plan for implementing contingencies in the event 
15    of supplier default or failure of the procurement process 
16    to fully meet the expected load requirement due to 
17    insufficient supplier participation, Commission rejection 
18    of results, or any other cause.
19            (i) Event of supplier default: In the event of 
20        supplier default, the utility shall review the 
21        contract of the defaulting supplier to determine if 
22        the amount of supply is 200 megawatts or greater, and 
23        if there are more than 60 days remaining of the 
24        contract term. If both of these conditions are met, 
25        and the default results in termination of the 
26        contract, the utility shall immediately notify the 
 
 
10400SB0025ham003- 784 -LRB104 07069 AAS 29208 a

1        Illinois Power Agency that a request for proposals 
2        must be issued to procure replacement power, and the 
3        procurement administrator shall run an additional 
4        procurement event. If the contracted supply of the 
5        defaulting supplier is less than 200 megawatts or 
6        there are less than 60 days remaining of the contract 
7        term, the utility shall procure power and energy from 
8        the applicable regional transmission organization 
9        market, including ancillary services, capacity, and 
10        day-ahead or real time energy, or both, for the 
11        duration of the contract term to replace the 
12        contracted supply; provided, however, that if a needed 
13        product is not available through the regional 
14        transmission organization market it shall be purchased 
15        from the wholesale market.
16            (ii) Failure of the procurement process to fully 
17        meet the expected load requirement: If the procurement 
18        process fails to fully meet the expected load 
19        requirement due to insufficient supplier participation 
20        or due to a Commission rejection of the procurement 
21        results, the procurement administrator, the 
22        procurement monitor, and the Commission staff shall 
23        meet within 10 days to analyze potential causes of low 
24        supplier interest or causes for the Commission 
25        decision. If changes are identified that would likely 
26        result in increased supplier participation, or that 
 
 
10400SB0025ham003- 785 -LRB104 07069 AAS 29208 a

1        would address concerns causing the Commission to 
2        reject the results of the prior procurement event, the 
3        procurement administrator may implement those changes 
4        and rerun the request for proposals process according 
5        to a schedule determined by those parties and 
6        consistent with Section 1-75 of the Illinois Power 
7        Agency Act and this subsection. In any event, a new 
8        request for proposals process shall be implemented by 
9        the procurement administrator within 90 days after the 
10        determination that the procurement process has failed 
11        to fully meet the expected load requirement.
12            (iii) In all cases where there is insufficient 
13        supply provided under contracts awarded through the 
14        procurement process to fully meet the electric 
15        utility's load requirement, the utility shall meet the 
16        load requirement by procuring power and energy from 
17        the applicable regional transmission organization 
18        market, including ancillary services, capacity, and 
19        day-ahead or real time energy, or both; provided, 
20        however, that if a needed product is not available 
21        through the regional transmission organization market 
22        it shall be purchased from the wholesale market.
23        (6) The procurement processes described in this 
24    subsection and in subsection (c-5) of Section 1-75 of the 
25    Illinois Power Agency Act are exempt from the requirements 
26    of the Illinois Procurement Code, pursuant to Section 
 
 
10400SB0025ham003- 786 -LRB104 07069 AAS 29208 a

1    20-10 of that Code.
2    (f) Within 2 business days after opening the sealed bids, 
3the procurement administrator shall submit a confidential 
4report to the Commission. The report shall contain the results 
5of the bidding for each of the products along with the 
6procurement administrator's recommendation for the acceptance 
7and rejection of bids based on the price benchmark criteria 
8and other factors observed in the process. The procurement 
9monitor also shall submit a confidential report to the 
10Commission within 2 business days after opening the sealed 
11bids. The report shall contain the procurement monitor's 
12assessment of bidder behavior in the process as well as an 
13assessment of the procurement administrator's compliance with 
14the procurement process and rules. The Commission shall review 
15the confidential reports submitted by the procurement 
16administrator and procurement monitor, and shall accept or 
17reject the recommendations of the procurement administrator 
18within 2 business days after receipt of the reports.
19    (g) Within 3 business days after the Commission decision 
20approving the results of a procurement event, the utility 
21shall enter into binding contractual arrangements with the 
22winning suppliers using the standard form contracts; except 
23that the utility shall not be required either directly or 
24indirectly to execute the contracts if a tariff that is 
25consistent with subsection (l) of this Section has not been 
26approved and placed into effect for that utility.
 
 
10400SB0025ham003- 787 -LRB104 07069 AAS 29208 a

1    (h) For the procurement of standard wholesale products, 
2the names of the successful bidders and the load weighted 
3average of the winning bid prices for each contract type and 
4for each contract term shall be made available to the public at 
5the time of Commission approval of a procurement event. For 
6procurements conducted to meet the requirements of subsection 
7(b) of Section 1-56 or subsection (c) of Section 1-75 of the 
8Illinois Power Agency Act governed by the provisions of this 
9Section, the address and nameplate capacity of the new 
10renewable energy generating facility proposed by a winning 
11bidder shall also be made available to the public at the time 
12of Commission approval of a procurement event, along with the 
13business address and contact information for any winning 
14bidder. An estimate or approximation of the nameplate capacity 
15of the new renewable energy generating facility may be 
16disclosed if necessary to protect the confidentiality of 
17individual bid prices.
18    The Commission, the procurement monitor, the procurement 
19administrator, the Illinois Power Agency, and all participants 
20in the procurement process shall maintain the confidentiality 
21of all other supplier and bidding information in a manner 
22consistent with all applicable laws, rules, regulations, and 
23tariffs. Confidential information, including the confidential 
24reports submitted by the procurement administrator and 
25procurement monitor pursuant to subsection (f) of this 
26Section, shall not be made publicly available and shall not be 
 
 
10400SB0025ham003- 788 -LRB104 07069 AAS 29208 a

1discoverable by any party in any proceeding, absent a 
2compelling demonstration of need, nor shall those reports be 
3admissible in any proceeding other than one for law 
4enforcement purposes.
5    For procurements conducted to meet the requirements of 
6subsection (b) of Section 1-56 or subsection (c) of Section 
71-75 of the Illinois Power Agency Act, the Illinois Power 
8Agency may release aggregated information related to 
9participation levels across product types and the basis of 
10rejection for non-accepted bids if the Commission, the 
11procurement monitor, the procurement administrator, and the 
12Illinois Power Agency determine that the release of this 
13information would not result in the disclosure of confidential 
14bid information or negatively impact the competitiveness of 
15future renewable energy credit procurements. The Agency may 
16also release information about the development status of new 
17renewable energy projects under contract and project-specific 
18information about renewable energy credit delivery quantities 
19for projects under contract if the Commission, the procurement 
20monitor, the procurement administrator, and the Illinois Power 
21Agency determine that the release of this information would 
22not result in the disclosure of confidential bid information 
23or negatively impact the competitiveness of future renewable 
24energy credit procurements.    
25    (i) Within 2 business days after a Commission decision 
26approving the results of a procurement event or such other 
 
 
10400SB0025ham003- 789 -LRB104 07069 AAS 29208 a

1date as may be required by the Commission from time to time, 
2the utility shall file for informational purposes with the 
3Commission its actual or estimated retail supply charges, as 
4applicable, by customer supply group reflecting the costs 
5associated with the procurement and computed in accordance 
6with the tariffs filed pursuant to subsection (l) of this 
7Section and approved by the Commission.
8    (j) Within 60 days following August 28, 2007 (the 
9effective date of Public Act 95-481), each electric utility 
10that on December 31, 2005 provided electric service to at 
11least 100,000 customers in Illinois shall prepare and file 
12with the Commission an initial procurement plan, which shall 
13conform in all material respects to the requirements of the 
14procurement plan set forth in subsection (b); provided, 
15however, that the Illinois Power Agency Act shall not apply to 
16the initial procurement plan prepared pursuant to this 
17subsection. The initial procurement plan shall identify the 
18portfolio of power and energy products to be procured and 
19delivered for the period June 2008 through May 2009, and shall 
20identify the proposed procurement administrator, who shall 
21have the same experience and expertise as is required of a 
22procurement administrator hired pursuant to Section 1-75 of 
23the Illinois Power Agency Act. Copies of the procurement plan 
24shall be posted and made publicly available on the 
25Commission's website. The initial procurement plan may include 
26contracts for renewable resources that extend beyond May 2009.
 
 
10400SB0025ham003- 790 -LRB104 07069 AAS 29208 a

1        (i) Within 14 days following filing of the initial 
2    procurement plan, any person may file a detailed objection 
3    with the Commission contesting the procurement plan 
4    submitted by the electric utility. All objections to the 
5    electric utility's plan shall be specific, supported by 
6    data or other detailed analyses. The electric utility may 
7    file a response to any objections to its procurement plan 
8    within 7 days after the date objections are due to be 
9    filed. Within 7 days after the date the utility's response 
10    is due, the Commission shall determine whether a hearing 
11    is necessary. If it determines that a hearing is 
12    necessary, it shall require the hearing to be completed 
13    and issue an order on the procurement plan within 60 days 
14    after the filing of the procurement plan by the electric 
15    utility.
16        (ii) The order shall approve or modify the procurement 
17    plan, approve an independent procurement administrator, 
18    and approve or modify the electric utility's tariffs that 
19    are proposed with the initial procurement plan. The 
20    Commission shall approve the procurement plan if the 
21    Commission determines that it will ensure adequate, 
22    reliable, affordable, efficient, and environmentally 
23    sustainable electric service at the lowest total cost over 
24    time, taking into account any benefits of price stability.
25    (k) (Blank).
26    (k-5) (Blank).
 
 
10400SB0025ham003- 791 -LRB104 07069 AAS 29208 a

1    (l) An electric utility shall recover its costs incurred 
2under this Section and subsection (c-5) of Section 1-75 of the 
3Illinois Power Agency Act, including, but not limited to, the 
4costs of procuring power and energy demand-response resources 
5under this Section and its costs for purchasing renewable 
6energy credits pursuant to subsection (c-5) of Section 1-75 of 
7the Illinois Power Agency Act. The utility shall file with the 
8initial procurement plan its proposed tariffs through which 
9its costs of procuring power that are incurred pursuant to a 
10Commission-approved procurement plan and those other costs 
11identified in this subsection (l), will be recovered. The 
12tariffs shall include a formula rate or charge designed to 
13pass through both the costs incurred by the utility in 
14procuring a supply of electric power and energy for the 
15applicable customer classes with no mark-up or return on the 
16price paid by the utility for that supply, plus any just and 
17reasonable costs that the utility incurs in arranging and 
18providing for the supply of electric power and energy. The 
19formula rate or charge shall also contain provisions that 
20ensure that its application does not result in over or under 
21recovery due to changes in customer usage and demand patterns, 
22and that provide for the correction, on at least an annual 
23basis, of any accounting errors that may occur. A utility 
24shall recover through the tariff all reasonable costs incurred 
25to implement or comply with any procurement plan that is 
26developed and put into effect pursuant to Section 1-75 of the 
 
 
10400SB0025ham003- 792 -LRB104 07069 AAS 29208 a

1Illinois Power Agency Act and this Section, and for the 
2procurement of renewable energy credits pursuant to subsection 
3(c-5) of Section 1-75 of the Illinois Power Agency Act, 
4including any fees assessed by the Illinois Power Agency, 
5costs associated with load balancing, and contingency plan 
6costs. The electric utility shall also recover its full costs 
7of procuring electric supply for which it contracted before 
8the effective date of this Section in conjunction with the 
9provision of full requirements service under fixed-price 
10bundled service tariffs subsequent to December 31, 2006. All 
11such costs shall be deemed to have been prudently incurred. 
12The pass-through tariffs that are filed and approved pursuant 
13to this Section shall not be subject to review under, or in any 
14way limited by, Section 16-111(i) of this Act. All of the costs 
15incurred by the electric utility associated with the purchase 
16of zero emission credits in accordance with subsection (d-5) 
17of Section 1-75 of the Illinois Power Agency Act, all costs 
18incurred by the electric utility associated with the purchase 
19of carbon mitigation credits in accordance with subsection 
20(d-10) of Section 1-75 of the Illinois Power Agency Act, and, 
21beginning June 1, 2017, all of the costs incurred by the 
22electric utility associated with the purchase of renewable 
23energy resources in accordance with Sections 1-56 and 1-75 of 
24the Illinois Power Agency Act, and all of the costs incurred by 
25the electric utility in purchasing renewable energy credits in 
26accordance with subsection (c-5) of Section 1-75 of the 
 
 
10400SB0025ham003- 793 -LRB104 07069 AAS 29208 a

1Illinois Power Agency Act, shall be recovered through the 
2electric utility's tariffed charges applicable to all of its 
3retail customers, as specified in subsection (k) or subsection 
4(i-5), as applicable, of Section 16-108 of this Act, and shall 
5not be recovered through the electric utility's tariffed 
6charges for electric power and energy supply to its eligible 
7retail customers.
8    (m) The Commission has the authority to adopt rules to 
9carry out the provisions of this Section. For the public 
10interest, safety, and welfare, the Commission also has 
11authority to adopt rules to carry out the provisions of this 
12Section on an emergency basis immediately following August 28, 
132007 (the effective date of Public Act 95-481).
14    (n) Notwithstanding any other provision of this Act, any 
15affiliated electric utilities that submit a single procurement 
16plan covering their combined needs may procure for those 
17combined needs in conjunction with that plan, and may enter 
18jointly into power supply contracts, purchases, and other 
19procurement arrangements, and allocate capacity and energy and 
20cost responsibility therefor among themselves in proportion to 
21their requirements.
22    (o) On or before June 1 of each year, the Commission shall 
23hold an informal hearing for the purpose of receiving comments 
24on the prior year's procurement process and any 
25recommendations for change. 
26    (p) An electric utility subject to this Section may 
 
 
10400SB0025ham003- 794 -LRB104 07069 AAS 29208 a

1propose to invest, lease, own, or operate an electric 
2generation facility as part of its procurement plan, provided 
3the utility demonstrates that such facility is the least-cost 
4option to provide electric service to those retail customers 
5included in the plan's electric supply service requirements. 
6If the facility is shown to be the least-cost option and is 
7included in a procurement plan prepared in accordance with 
8Section 1-75 of the Illinois Power Agency Act and this 
9Section, then the electric utility shall make a filing 
10pursuant to Section 8-406 of this Act, and may request of the 
11Commission any statutory relief required thereunder. If the 
12Commission grants all of the necessary approvals for the 
13proposed facility, such supply shall thereafter be considered 
14as a pre-existing contract under subsection (b) of this 
15Section. The Commission shall in any order approving a 
16proposal under this subsection specify how the utility will 
17recover the prudently incurred costs of investing in, leasing, 
18owning, or operating such generation facility through just and 
19reasonable rates charged to those retail customers included in 
20the plan's electric supply service requirements. Cost recovery 
21for facilities included in the utility's procurement plan 
22pursuant to this subsection shall not be subject to review 
23under or in any way limited by the provisions of Section 
2416-111(i) of this Act. Nothing in this Section is intended to 
25prohibit a utility from filing for a fuel adjustment clause as 
26is otherwise permitted under Section 9-220 of this Act. 
 
 
10400SB0025ham003- 795 -LRB104 07069 AAS 29208 a

1    (q) If the Illinois Power Agency filed with the 
2Commission, under Section 16-111.5 of this Act, its proposed 
3procurement plan for the period commencing June 1, 2017, and 
4the Commission has not yet entered its final order approving 
5the plan on or before the effective date of this amendatory Act 
6of the 99th General Assembly, then the Illinois Power Agency 
7shall file a notice of withdrawal with the Commission, after 
8the effective date of this amendatory Act of the 99th General 
9Assembly, to withdraw the proposed procurement of renewable 
10energy resources to be approved under the plan, other than the 
11procurement of renewable energy credits from distributed 
12renewable energy generation devices using funds previously 
13collected from electric utilities' retail customers that take 
14service pursuant to electric utilities' hourly pricing tariff 
15or tariffs and, for an electric utility that serves less than 
16100,000 retail customers in the State, other than the 
17procurement of renewable energy credits from distributed 
18renewable energy generation devices. Upon receipt of the 
19notice, the Commission shall enter an order that approves the 
20withdrawal of the proposed procurement of renewable energy 
21resources from the plan. The initially proposed procurement of 
22renewable energy resources shall not be approved or be the 
23subject of any further hearing, investigation, proceeding, or 
24order of any kind.
25    This amendatory Act of the 99th General Assembly preempts 
26and supersedes any order entered by the Commission that 
 
 
10400SB0025ham003- 796 -LRB104 07069 AAS 29208 a

1approved the Illinois Power Agency's procurement plan for the 
2period commencing June 1, 2017, to the extent it is 
3inconsistent with the provisions of this amendatory Act of the 
499th General Assembly. To the extent any previously entered 
5order approved the procurement of renewable energy resources, 
6the portion of that order approving the procurement shall be 
7void, other than the procurement of renewable energy credits 
8from distributed renewable energy generation devices using 
9funds previously collected from electric utilities' retail 
10customers that take service under electric utilities' hourly 
11pricing tariff or tariffs and, for an electric utility that 
12serves less than 100,000 retail customers in the State, other 
13than the procurement of renewable energy credits for 
14distributed renewable energy generation devices. 
15(Source: P.A. 102-662, eff. 9-15-21.)
 
16    (220 ILCS 5/16-111.7)
17    Sec. 16-111.7. On-bill financing program; electric 
18utilities.
19    (a) The Illinois General Assembly finds that Illinois 
20homes and businesses have the potential to save energy through 
21conservation and cost-effective energy efficiency measures. 
22Programs created pursuant to this Section will allow utility 
23customers to purchase cost-effective energy efficiency 
24measures, including measures set forth in a 
25Commission-approved energy efficiency and demand-response plan 
 
 
10400SB0025ham003- 797 -LRB104 07069 AAS 29208 a

1under Section 8-103 or 8-103B of this Act, with no required 
2initial upfront payment, and to pay the cost of those products 
3and services over time on their utility bill.
4    (b) Notwithstanding any other provision of this Act, an 
5electric utility serving more than 100,000 customers on 
6January 1, 2009 shall offer a Commission-approved on-bill 
7financing program ("program") that allows its eligible retail 
8customers, as that term is defined in Section 16-111.5 of this 
9Act, who own a residential single family home, duplex, or 
10other residential building with 4 or less units, or 
11condominium at which the electric service is being provided 
12(i) to borrow funds from a third party lender in order to 
13purchase electric energy efficiency measures approved under 
14the program for installation in such home or condominium 
15without any required upfront payment and (ii) to pay back such 
16funds over time through the electric utility's bill. Based 
17upon the process described in subsection (b-5) of this 
18Section, small commercial customers who own the premises at 
19which electric service is being provided may be included in 
20such program. After receiving a request from an electric 
21utility for approval of a proposed program and tariffs 
22pursuant to this Section, the Commission shall render its 
23decision within 120 days. If no decision is rendered within 
24120 days, then the request shall be deemed to be approved.
25    Beginning no later than December 31, 2013, an electric 
26utility subject to this subsection (b) shall also offer its 
 
 
10400SB0025ham003- 798 -LRB104 07069 AAS 29208 a

1program to eligible retail customers that own multifamily 
2residential or mixed-use buildings with no more than 50 
3residential units, provided, however, that such customers must 
4either be a residential customer or small commercial customer 
5and may not use the program in such a way that repayment of the 
6cost of energy efficiency measures is made through tenants' 
7utility bills. An electric utility may impose a per site loan 
8limit not to exceed $150,000. The program, and loans issued 
9thereunder, shall only be offered to customers of the utility 
10that meet the requirements of this Section and that also have 
11an electric service account at the premises where the energy 
12efficiency measures being financed shall be installed. 
13Beginning no later than 2 years after the effective date of 
14this amendatory Act of the 99th General Assembly, the 50 
15residential unit limitation described in this paragraph shall 
16no longer apply, and the utility shall replace the per site 
17loan limit of $150,000 with a loan limit that correlates to a 
18maximum monthly payment that does not exceed 50% of the 
19customer's average utility bill over the prior 12-month 
20period.
21    Beginning no later than 2 years after the effective date 
22of this amendatory Act of the 99th General Assembly, an 
23electric utility subject to this subsection (b) shall also 
24offer its program to eligible retail customers that are Unit 
25Owners' Associations, as defined in subsection (o) of Section 
262 of the Condominium Property Act, or Master Associations, as 
 
 
10400SB0025ham003- 799 -LRB104 07069 AAS 29208 a

1defined in subsection (u) of the Condominium Property Act. 
2However, such customers must either be residential customers 
3or small commercial customers and may not use the program in 
4such a way that repayment of the cost of energy efficiency 
5measures is made through unit owners' utility bills. The 
6program and loans issued under the program shall only be 
7offered to customers of the utility that meet the requirements 
8of this Section and that also have an electric service account 
9at the premises where the energy efficiency measures being 
10financed shall be installed. 
11    For purposes of this Section, "small commercial customer" 
12means, for an electric utility serving more than 3,000,000 
13retail customers, those customers having peak demand of less 
14than 100 kilowatts, and, for an electric utility serving less 
15than 3,000,000 retail customers, those customers having peak 
16demand of less than 150 kilowatts; provided, however, that in 
17the event the Commission, after the effective date of this 
18amendatory Act of the 98th General Assembly, approves changes 
19to a utility's tariffs that reflects new or revised demand 
20criteria for the utility's customer rate classifications, then 
21the utility may file a petition with the Commission to revise 
22the applicable definition of a small commercial customer to 
23reflect the new or revised demand criteria for the purposes of 
24this Section. After notice and hearing, the Commission shall 
25enter an order approving, or approving with modification, the 
26revised definition within 60 days after the utility files the 
 
 
10400SB0025ham003- 800 -LRB104 07069 AAS 29208 a

1petition. 
2    (b-5) Within 30 days after the effective date of this 
3amendatory Act of the 96th General Assembly, the Commission 
4shall convene a workshop process during which interested 
5participants may discuss issues related to the program, 
6including program design, eligible electric energy efficiency 
7measures, vendor qualifications, and a methodology for 
8ensuring ongoing compliance with such qualifications, 
9financing, sample documents such as request for proposals, 
10contracts and agreements, dispute resolution, pre-installment 
11and post-installment verification, and evaluation. The 
12workshop process shall be completed within 150 days after the 
13effective date of this amendatory Act of the 96th General 
14Assembly.
15    (c) Not later than 60 days following completion of the 
16workshop process described in subsection (b-5) of this 
17Section, each electric utility subject to subsection (b) of 
18this Section shall submit a proposed program to the Commission 
19that contains the following components:
20        (1) A list of recommended electric energy efficiency 
21    measures that will be eligible for on-bill financing. An 
22    eligible electric energy efficiency measure ("measure") 
23    shall be a product or service for which one or more of the 
24    following is true:
25            (A) (blank); 
26            (B) the projected electricity savings (determined 
 
 
10400SB0025ham003- 801 -LRB104 07069 AAS 29208 a

1        by rates in effect at the time of purchase) are 
2        sufficient to cover the costs of implementing the 
3        measures, including finance charges and any program 
4        fees not recovered pursuant to subsection (f) of this 
5        Section; or
6            (C) the product or service is included in a 
7        Commission-approved energy efficiency and 
8        demand-response plan under Section 8-103 or 8-103B of 
9        this Act. 
10        (1.5) Beginning no later than 2 years after the 
11    effective date of this amendatory Act of the 99th General 
12    Assembly, an eligible electric energy efficiency measure 
13    (measure) shall be a product or service that qualifies 
14    under subparagraph (B) or (C) of paragraph (1) of this 
15    subsection (c) or for which one or more of the following is 
16    true:
17            (A) a building energy assessment, performed by an 
18        energy auditor who is certified by the Building 
19        Performance Institute or who holds a similar 
20        certification, has recommended the product or service 
21        as likely to be cost effective over the course of its 
22        installed life for the building in which the measure 
23        is to be installed; or
24            (B) the product or service is necessary to safely 
25        or correctly install to code or industry standard an 
26        efficiency measure, including, but not limited to, 
 
 
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1        installation work; changes needed to plumbing or 
2        electrical connections; upgrades to wiring or 
3        fixtures; removal of hazardous materials; correction 
4        of leaks; changes to thermostats, controls, or similar 
5        devices; and changes to venting or exhaust 
6        necessitated by the measure. However, the costs of the 
7        product or service described in this subparagraph (B) 
8        shall not exceed 25% of the total cost of installing 
9        the measure. 
10        (2) The electric utility shall issue a request for 
11    proposals ("RFP") to lenders for purposes of providing 
12    financing to participants to pay for approved measures. 
13    The RFP criteria shall include, but not be limited to, the 
14    interest rate, origination fees, and credit terms. The 
15    utility shall select the winning bidders based on its 
16    evaluation of these criteria, with a preference for those 
17    bids containing the rates, fees, and terms most favorable 
18    to participants;
19        (3) The utility shall work with the lenders selected 
20    pursuant to the RFP process, and with vendors, to 
21    establish the terms and processes pursuant to which a 
22    participant can purchase eligible electric energy 
23    efficiency measures using the financing obtained from the 
24    lender. The vendor shall explain and offer the approved 
25    financing packaging to those customers identified in 
26    subsection (b) of this Section and shall assist customers 
 
 
10400SB0025ham003- 803 -LRB104 07069 AAS 29208 a

1    in applying for financing. As part of the process, vendors 
2    shall also provide to participants information about any 
3    other incentives that may be available for the measures.
4        (4) The lender shall conduct credit checks or 
5    undertake other appropriate measures to limit credit risk, 
6    and shall review and approve or deny financing 
7    applications submitted by customers identified in 
8    subsection (b) of this Section. Following the lender's 
9    approval of financing and the participant's purchase of 
10    the measure or measures, the lender shall forward payment 
11    information to the electric utility, and the utility shall 
12    add as a separate line item on the participant's utility 
13    bill a charge showing the amount due under the program 
14    each month.
15        (5) A loan issued to a participant pursuant to the 
16    program shall be the sole responsibility of the 
17    participant, and any dispute that may arise concerning the 
18    loan's terms, conditions, or charges shall be resolved 
19    between the participant and lender. Upon transfer of the 
20    property title for the premises at which the participant 
21    receives electric service from the utility or the 
22    participant's request to terminate service at such 
23    premises, the participant shall pay in full its electric 
24    utility bill, including all amounts due under the program, 
25    provided that this obligation may be modified as provided 
26    in subsection (g) of this Section. Amounts due under the 
 
 
10400SB0025ham003- 804 -LRB104 07069 AAS 29208 a

1    program shall be deemed amounts owed for residential and, 
2    as appropriate, small commercial electric service.
3        (6) The electric utility shall remit payment in full 
4    to the lender each month on behalf of the participant. In 
5    the event a participant defaults on payment of its 
6    electric utility bill, the electric utility shall continue 
7    to remit all payments due under the program to the lender, 
8    and the utility shall be entitled to recover all costs 
9    related to a participant's nonpayment through the 
10    automatic adjustment clause tariff established pursuant to 
11    Section 16-111.8 of this Act. In addition, the electric 
12    utility shall retain a security interest in the measure or 
13    measures purchased under the program, and the utility 
14    retains its right to disconnect a participant that 
15    defaults on the payment of its utility bill.
16        (7) The total outstanding amount financed under the 
17    program in this subsection and subsection (c-5) of this 
18    Section shall not exceed $2.5 million for an electric 
19    utility or electric utilities under a single holding 
20    company, provided that the electric utility or electric 
21    utilities may petition the Commission for an increase in 
22    such amount. Beginning after the effective date of this 
23    amendatory Act of the 99th General Assembly, the total 
24    maximum outstanding amount financed under the program in 
25    this subsection and subsections (c-5) and (c-10) of this 
26    Section shall increase by $5,000,000 per year until such 
 
 
10400SB0025ham003- 805 -LRB104 07069 AAS 29208 a

1    time as the total maximum outstanding amount financed 
2    reaches $20,000,000. For purposes of this Section, 
3    "maximum outstanding amount financed" means the sum of all 
4    principal that has been loaned and not yet repaid. 
5    (c-5) Within 120 days after the effective date of this 
6amendatory Act of the 98th General Assembly, each electric 
7utility subject to the requirements of this Section shall 
8submit an informational filing to the Commission that 
9describes its plan for implementing the provisions of this 
10amendatory Act of the 98th General Assembly on or before 
11December 31, 2013. Such filing shall also describe how the 
12electric utility shall coordinate its program with any gas 
13utility or utilities that provide gas service to buildings 
14within the electric utility's service territory so that it is 
15practical and feasible for the owner of a multifamily building 
16to make a single application to access loans for both gas and 
17electric energy efficiency measures in any individual 
18building.
19    (c-10) No later than 365 days after the effective date of 
20this amendatory Act of the 99th General Assembly, each 
21electric utility subject to the requirements of this Section 
22shall submit an informational filing to the Commission that 
23describes its plan for implementing the provisions of this 
24amendatory Act of the 99th General Assembly that were 
25incorporated into this Section. Such filing shall also include 
26the criteria to be used by the program for determining if 
 
 
10400SB0025ham003- 806 -LRB104 07069 AAS 29208 a

1measures to be financed are eligible electric energy 
2efficiency measures, as defined by paragraph (1.5) of 
3subsection (c) of this Section. 
4    (d) A program approved by the Commission shall also 
5include the following criteria and guidelines for such 
6program:
7        (1) guidelines for financing of measures installed 
8    under a program, including, but not limited to, RFP 
9    criteria and limits on both individual loan amounts and 
10    the duration of the loans;
11        (2) criteria and standards for identifying and 
12    approving measures;
13        (3) qualifications of vendors that will market or 
14    install measures, as well as a methodology for ensuring 
15    ongoing compliance with such qualifications;
16        (4) sample contracts and agreements necessary to 
17    implement the measures and program; and
18        (5) the types of data and information that utilities 
19    and vendors participating in the program shall collect for 
20    purposes of preparing the reports required under 
21    subsection (g) of this Section.
22    (e) The proposed program submitted by each electric 
23utility shall be consistent with the provisions of this 
24Section that define operational, financial and billing 
25arrangements between and among program participants, vendors, 
26lenders, and the electric utility.
 
 
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1    (f) An electric utility shall recover all of the prudently 
2incurred costs of offering a program approved by the 
3Commission pursuant to this Section, including, but not 
4limited to, all start-up and administrative costs and the 
5costs for program evaluation. All prudently incurred costs 
6under this Section shall be recovered from the residential and 
7small commercial retail customer classes eligible to 
8participate in the program through the automatic adjustment 
9clause tariff established pursuant to Section 8-103 or 8-103B 
10of this Act.
11    (g) An independent evaluation of a program shall be 
12conducted after 3 years of the program's operation. The 
13electric utility shall retain an independent evaluator who 
14shall evaluate the effects of the measures installed under the 
15program and the overall operation of the program, including, 
16but not limited to, customer eligibility criteria and whether 
17the payment obligation for permanent electric energy 
18efficiency measures that will continue to provide benefits of 
19energy savings should attach to the meter location. As part of 
20the evaluation process, the evaluator shall also solicit 
21feedback from participants and interested stakeholders. The 
22evaluator shall issue a report to the Commission on its 
23findings no later than 4 years after the date on which the 
24program commenced, and the Commission shall issue a report to 
25the Governor and General Assembly including a summary of the 
26information described in this Section as well as its 
 
 
10400SB0025ham003- 808 -LRB104 07069 AAS 29208 a

1recommendations as to whether the program should be 
2discontinued, continued with modification or modifications or 
3continued without modification, provided that any recommended 
4modifications shall only apply prospectively and to measures 
5not yet installed or financed.
6    (h) An electric utility offering a Commission-approved 
7program pursuant to this Section shall not be required to 
8comply with any other statute, order, rule, or regulation of 
9this State that may relate to the offering of such program, 
10provided that nothing in this Section is intended to limit the 
11electric utility's obligation to comply with this Act and the 
12Commission's orders, rules, and regulations, including Part 
13280 of Title 83 of the Illinois Administrative Code.
14    (i) The source of a utility customer's electric supply 
15shall not disqualify a customer from participation in the 
16utility's on-bill financing program. Customers of alternative 
17retail electric suppliers may participate in the program under 
18the same terms and conditions applicable to the utility's 
19supply customers.
20    (j) This Section is repealed on January 1, 2027.    
21(Source: P.A. 98-586, eff. 8-27-13; 99-906, eff. 6-1-17.)
 
22    (220 ILCS 5/16-115A)
23    Sec. 16-115A. Obligations of alternative retail electric 
24suppliers.
25    (a) An alternative retail electric supplier:
 
 
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1        (i) shall comply with the requirements imposed on 
2    public utilities by Sections 8-201 through 8-207, 8-301, 
3    8-505 and 8-507 of this Act, to the extent that these 
4    Sections have application to the services being offered by 
5    the alternative retail electric supplier;
6        (ii) shall continue to comply with the requirements 
7    for certification stated in subsection (d) of Section 
8    16-115;
9        (iii) by May 31, 2020 and every June 30 thereafter, 
10    shall submit to the Commission and the Office of the 
11    Attorney General the rates the retail electric supplier 
12    charged to residential customers in the prior year, 
13    including each distinct rate charged and whether the rate 
14    was a fixed or variable rate, the basis for the variable 
15    rate, and any fees charged in addition to the supply rate, 
16    including monthly fees, flat fees, or other service 
17    charges; and
18        (iv) shall make publicly available on its website, 
19    without the need for a customer login, rate information 
20    for all of its variable, time-of-use, and fixed rate 
21    contracts currently available to residential customers, 
22    including, but not limited to, fixed monthly charges, 
23    early termination fees, and kilowatt-hour charges; .
24        (v) shall provide to the Commission, in the form and 
25    manner requested, the information necessary for the 
26    Commission to compile and submit the integrated resource 
 
 
10400SB0025ham003- 810 -LRB104 07069 AAS 29208 a

1    plan required under Section 16-201; and
2        (vi) shall comply with the Commission's determinations 
3    made pursuant to subsection (b-10) of Section 16-111.5, 
4    including, but not limited to, the imposition of any 
5    collections, the execution of any contracts, and the 
6    required performance under any contracts developed 
7    thereunder.
8    (b) An alternative retail electric supplier shall obtain 
9verifiable authorization from a customer, in a form or manner 
10approved by the Commission consistent with Section 2EE of the 
11Consumer Fraud and Deceptive Business Practices Act, before 
12the customer is switched from another supplier.
13    (c) No alternative retail electric supplier, or electric 
14utility other than the electric utility in whose service area 
15a customer is located, shall (i) enter into or employ any 
16arrangements which have the effect of preventing a retail 
17customer with a maximum electrical demand of less than one 
18megawatt from having access to the services of the electric 
19utility in whose service area the customer is located or (ii) 
20charge retail customers for such access. This subsection shall 
21not be construed to prevent an arms-length agreement between a 
22supplier and a retail customer that sets a term of service, 
23notice period for terminating service and provisions governing 
24early termination through a tariff or contract as allowed by 
25Section 16-119.
26    (d) An alternative retail electric supplier that is 
 
 
10400SB0025ham003- 811 -LRB104 07069 AAS 29208 a

1certified to serve residential or small commercial retail 
2customers shall not:
3        (1) deny service to a customer or group of customers 
4    nor establish any differences as to prices, terms, 
5    conditions, services, products, facilities, or in any 
6    other respect, whereby such denial or differences are 
7    based upon race, gender or income, except as provided in 
8    Section 16-115E.
9        (2) deny service to a customer or group of customers 
10    based on locality nor establish any unreasonable 
11    difference as to prices, terms, conditions, services, 
12    products, or facilities as between localities.
13        (3) warrant that it has a residential customer or 
14    small commercial retail customer's express consent 
15    agreement to access interval data as described in 
16    subsection (b) of Section 16-122, unless the alternative 
17    retail electric supplier has:
18            (A) disclosed to the consumer at the outset of the 
19        offer that the alternative retail electric supplier 
20        will access the consumer's interval data from the 
21        consumer's utility with the consumer's express 
22        agreement and the consumer's option to refuse to 
23        provide express agreement to access the consumer's 
24        interval data; and
25            (B) obtained the consumer's express agreement for 
26        the alternative retail electric supplier to access the 
 
 
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1        consumer's interval data from the consumer's utility 
2        in a separate letter of agency, a distinct response to 
3        a third-party verification, or as a separate 
4        affirmative consent during a recorded enrollment 
5        initiated by the consumer. The disclosure by the 
6        alternative retail electric supplier to the consumer 
7        in this Section shall be conducted in, translated 
8        into, and provided in a language in which the consumer 
9        subject to the disclosure is able to understand and 
10        communicate.
11        (4) release, sell, license, or otherwise disclose any 
12    customer interval data obtained under Section 16-122 to 
13    any third person except as provided for in Section 16-122 
14    and paragraphs (1) through (4) of subsection (d-5) of 
15    Section 2EE of the Consumer Fraud and Deceptive Business 
16    Practices Act. 
17    (e) An alternative retail electric supplier shall comply 
18with the following requirements with respect to the marketing, 
19offering and provision of products or services to residential 
20and small commercial retail customers:
21        (i) All marketing materials, including, but not 
22    limited to, electronic marketing materials, in-person 
23    solicitations, and telephone solicitations, shall contain 
24    information that adequately discloses the prices, terms, 
25    and conditions of the products or services that the 
26    alternative retail electric supplier is offering or 
 
 
10400SB0025ham003- 813 -LRB104 07069 AAS 29208 a

1    selling to the customer and shall disclose the current 
2    utility electric supply price to compare applicable at the 
3    time the alternative retail electric supplier is offering 
4    or selling the products or services to the customer and 
5    shall disclose the date on which the utility electric 
6    supply price to compare became effective and the date on 
7    which it will expire. The utility electric supply price to 
8    compare shall be the sum of the electric supply charge and 
9    the transmission services charge and shall not include the 
10    purchased electricity adjustment. The disclosure shall 
11    include a statement that the price to compare does not 
12    include the purchased electricity adjustment, and, if 
13    applicable, the range of the purchased electricity 
14    adjustment. All marketing materials, including, but not 
15    limited to, electronic marketing materials, in-person 
16    solicitations, and telephone solicitations, shall include 
17    the following statement: 
18            "(Name of the alternative retail electric 
19        supplier) is not the same entity as your electric 
20        delivery company. You are not required to enroll with 
21        (name of alternative retail electric supplier). 
22        Beginning on (effective date), the electric supply 
23        price to compare is (price in cents per kilowatt 
24        hour). The electric utility electric supply price will 
25        expire on (expiration date). The utility electric 
26        supply price to compare does not include the purchased 
 
 
10400SB0025ham003- 814 -LRB104 07069 AAS 29208 a

1        electricity adjustment factor. For more information go 
2        to the Illinois Commerce Commission's free website at 
3        www.pluginillinois.org.
4        If applicable, the statement shall also include the 
5    following statement:
6            "The purchased electricity adjustment factor may 
7        range between +.5 cents and -.5 cents per kilowatt 
8        hour.". 
9        This paragraph (i) does not apply to goodwill or 
10    institutional advertising. 
11        (ii) Before any customer is switched from another 
12    supplier, the alternative retail electric supplier shall 
13    give the customer written information that adequately 
14    discloses, in plain language, the prices, terms and 
15    conditions of the products and services being offered and 
16    sold to the customer. This written information shall be 
17    provided in a language in which the customer subject to 
18    the marketing or solicitation is able to understand and 
19    communicate, and the alternative retail electric supplier 
20    shall not switch a customer who is unable to understand 
21    and communicate in a language in which the marketing or 
22    solicitation was conducted. The alternative retail 
23    electric supplier shall comply with Section 2N of the 
24    Consumer Fraud and Deceptive Business Practices Act. 
25        (iii) An alternative retail electric supplier shall 
26    provide documentation to the Commission and to customers 
 
 
10400SB0025ham003- 815 -LRB104 07069 AAS 29208 a

1    that substantiates any claims made by the alternative 
2    retail electric supplier regarding the technologies and 
3    fuel types used to generate the electricity offered or 
4    sold to customers.
5        (iv) The alternative retail electric supplier shall 
6    provide to the customer (1) itemized billing statements 
7    that describe the products and services provided to the 
8    customer and their prices, and (2) an additional 
9    statement, at least annually, that adequately discloses 
10    the average monthly prices, and the terms and conditions, 
11    of the products and services sold to the customer.
12        (v) All in-person and telephone solicitations shall be 
13    conducted in, translated into, and provided in a language 
14    in which the consumer subject to the marketing or 
15    solicitation is able to understand and communicate. An 
16    alternative retail electric supplier shall terminate a 
17    solicitation if the consumer subject to the marketing or 
18    communication is unable to understand and communicate in 
19    the language in which the marketing or solicitation is 
20    being conducted. An alternative retail electric supplier 
21    shall comply with Section 2N of the Consumer Fraud and 
22    Deceptive Business Practices Act.
23        (vi) Each alternative retail electric supplier shall 
24    conduct training for individual representatives engaged in 
25    in-person solicitation and telemarketing to residential 
26    customers on behalf of that alternative retail electric 
 
 
10400SB0025ham003- 816 -LRB104 07069 AAS 29208 a

1    supplier prior to conducting any such solicitations on the 
2    alternative retail electric supplier's behalf. Each 
3    alternative retail electric supplier shall submit a copy 
4    of its training material to the Commission on an annual 
5    basis and the Commission shall have the right to review 
6    and require updates to the material. After initial 
7    training, each alternative retail electric supplier shall 
8    be required to conduct refresher training for its 
9    individual representatives every 6 months. 
10    (f) An alternative retail electric supplier may limit the 
11overall size or availability of a service offering by 
12specifying one or more of the following: a maximum number of 
13customers, maximum amount of electric load to be served, time 
14period during which the offering will be available, or other 
15comparable limitation, but not including the geographic 
16locations of customers within the area which the alternative 
17retail electric supplier is certificated to serve. The 
18alternative retail electric supplier shall file the terms and 
19conditions of such service offering including the applicable 
20limitations with the Commission prior to making the service 
21offering available to customers.
22    (g) Nothing in this Section shall be construed as 
23preventing an alternative retail electric supplier, which is 
24an affiliate of, or which contracts with, (i) an industry or 
25trade organization or association, (ii) a membership 
26organization or association that exists for a purpose other 
 
 
10400SB0025ham003- 817 -LRB104 07069 AAS 29208 a

1than the purchase of electricity, or (iii) another 
2organization that meets criteria established in a rule adopted 
3by the Commission, from offering through the organization or 
4association services at prices, terms and conditions that are 
5available solely to the members of the organization or 
6association.
7(Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
 
8    (220 ILCS 5/16-119A)
9    Sec. 16-119A. Functional separation. 
10    (a) Within 90 days after the effective date of this 
11amendatory Act of 1997, the Commission shall open a rulemaking 
12proceeding to establish standards of conduct for every 
13electric utility described in subsection (b). To create 
14efficient competition between suppliers of generating services 
15and sellers of such services at retail and wholesale, the 
16rules shall allow all customers of a public utility that 
17distributes electric power and energy to purchase electric 
18power and energy from the supplier of their choice in 
19accordance with the provisions of Section 16-104. In addition, 
20the rules shall address relations between providers of any 2 
21services described in subsection (b) to prevent undue 
22discrimination and promote efficient competition. Provided, 
23however, that a proposed rule shall not be published prior to 
24May 15, 1999.
25    (b) The Commission shall also have the authority to 
 
 
10400SB0025ham003- 818 -LRB104 07069 AAS 29208 a

1investigate the need for, and adopt rules requiring, 
2functional separation between the generation services and the 
3delivery services of those electric utilities whose principal 
4service area is in Illinois as necessary to meet the objective 
5of creating efficient competition between suppliers of 
6generating services and sellers of such services at retail and 
7wholesale. After January 1, 2003, the Commission shall also 
8have the authority to investigate the need for, and adopt 
9rules requiring, functional separation between an electric 
10utility's competitive and non-competitive services.
11    (b-5) If there is a change in ownership of a majority of 
12the voting capital stock of an electric utility or the 
13ownership or control of any entity that owns or controls a 
14majority of the voting capital stock of an electric utility, 
15the electric utility shall have the right to file with the 
16Commission a new plan. The newly filed plan shall supersede 
17any plan previously approved by the Commission pursuant to 
18this Section for that electric utility, subject to Commission 
19approval. This subsection only applies to the extent that the 
20Commission rules for the functional separation of delivery 
21services and generation services provide an electric utility 
22with the ability to select from 2 or more options to comply 
23with this Section. The electric utility may file its revised 
24plan with the Commission up to one calendar year after the 
25conclusion of the sale, purchase, or any other transfer of 
26ownership described in this subsection. In all other respects, 
 
 
10400SB0025ham003- 819 -LRB104 07069 AAS 29208 a

1an electric utility must comply with the Commission rules in 
2effect under this Section. The Commission may promulgate rules 
3to implement this subsection. This subsection shall have no 
4legal effect after January 1, 2005.
5    (c) In establishing or considering the need for rules 
6under subsections (a) and (b), the Commission shall take into 
7account the effects on the cost and reliability of service and 
8the obligation of the utility to provide bundled service under 
9this Act. The Commission shall adopt rules that are a cost 
10effective means to ensure compliance with this Section.
11    (d) Nothing in this Section shall be construed as imposing 
12any requirements or obligations that are in conflict with 
13federal law.
14    (e) Notwithstanding anything to the contrary, an electric 
15utility may market and promote the services, rates and 
16programs authorized by Sections 16-107, 16-107.8, and 16-108.6 
17of this Act.
18(Source: P.A. 99-906, eff. 6-1-17.)
 
19    (220 ILCS 5/16-126.2 new)
20    Sec. 16-126.2. Energy Reliability Corporation of Illinois.
21    (a) The General Assembly finds that:
22        (1) When Illinois restructured its electric market in 
23    1997, Illinois' largest 2 electric utilities unexpectedly 
24    elected to join 2 different regional transmission 
25    organizations (RTO), which effectively split the State 
 
 
10400SB0025ham003- 820 -LRB104 07069 AAS 29208 a

1    into 2 zones.
2        (2) Illinois' bifurcated, existing RTO membership 
3    structure has created significant concerns related to 
4    delays in transmission build out, excessively long 
5    interconnection queue processes, favoring polluting 
6    generation resources over more cost-effective clean 
7    sources, inhibiting State policies, and inexplicably 
8    frustrating State efforts to address its resource adequacy 
9    needs through the development of new generation.
10        (3) The governance structures of PJM Interconnection, 
11    LLC (PJM) and the Midcontinent Independent System 
12    Operator, Inc. (MISO) have consistently failed to 
13    represent Illinois' interests.
14        (4) The Illinois Commerce Commission and the Illinois 
15    Power Agency have the expertise to evaluate and present 
16    findings related to the costs and benefits of Illinois 
17    pursuing any one of the following 3 options: (1) 
18    establishing a single, State-specific Independent System 
19    Operator (ISO); (2) consolidating Illinois' existing 
20    bifurcated RTO membership structure into one existing RTO; 
21    or (3) maintaining the existing bifurcated RTO structure.
22    (b) The Commission and the Illinois Power Agency shall 
23conduct a joint study and publish the findings of the study to 
24evaluate whether (1) establishing a single State-operated ISO; 
25(2) consolidating this State's bifurcated RTO membership into 
26an existing RTO; or (3) maintaining the existing bifurcated 
 
 
10400SB0025ham003- 821 -LRB104 07069 AAS 29208 a

1RTO structure, would be consistent with the State's goals and 
2would maximize benefits to State businesses and residents. As 
3a part of this evaluation, the Commission and the Illinois 
4Power Agency shall analyze whether it would be feasible and 
5practical for this State to pursue any of the options 
6described in this subsection (b).
7    (c) The Commission and the Illinois Power Agency shall 
8examine the costs and benefits, over a 20 year period, of this 
9State pursuing any of the options described in subsection (b). 
10The study shall examine the costs and benefits of such 
11participation over 20 years. The study shall examine the costs 
12and benefits to State ratepayers, including, but not limited 
13to, consideration of the regulatory, reliability, operational, 
14and competitive benefits of this State participating in one 
15existing RTO, as compared to participating in a State-specific 
16ISO, or continuing to participate in the current bifurcated 
17RTO structure. The costs and benefits evaluated should include 
18resource adequacy benefits, resilience, affordability, equity, 
19the impact on the environment, and the general health, safety, 
20and welfare of the People of this State.
21    The study shall, at a minimum, include the following, and 
22it may consider or suggest additional or alternative items:
23        (1) the appropriate timetable to (i) establish and 
24    effectively transition to a State-specific ISO, or (ii) 
25    consolidate into an existing RTO, taking into account how 
26    that schedule could support the emission reduction 
 
 
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1    timeline established in Section 9.15 of the Environmental 
2    Protection Act; and
3        (2) the appropriate benefits and costs to consider, 
4    such as the regulatory, reliability, operational, and 
5    competitive benefits, including, but not limited to:
6            (i) capacity market benefits and costs of 
7        separating from the PJM and MISO territories versus 
8        those of the status quo;
9            (ii) transmission benefits and costs of separating 
10        from the PJM and MISO territories versus those of a 
11        State-specific ISO;
12            (iii) the legal, correct, and appropriate exit 
13        fees for leaving regional transmission organizations;
14            (iv) managing the State's energy resources to 
15        supply electricity throughout the State versus the 
16        existing bifurcated structure;
17            (v) the potential improvements in interconnection 
18        queue speed versus the current lengthy delays in the 
19        PJM and MISO processes;
20            (vi) the potential for a State-specific ISO to 
21        more effectively value and enable resources, such as 
22        storage of renewable resources, demand response, 
23        energy efficiency, and the adoption of new 
24        technologies and applications, versus the current PJM 
25        and MISO structures; and
26            (vii) an evaluation of any improved ability for 
 
 
10400SB0025ham003- 823 -LRB104 07069 AAS 29208 a

1        the State to meet its goals and objectives in a new 
2        State-specific ISO versus the existing structure.
3        After the completion of the study, if the Commission 
4    and the Illinois Power Agency find that the results of the 
5    study were overall beneficial to the citizens of this 
6    State, then the Commission and the Illinois Power Agency 
7    may conduct and publish an additional ISO policy study 
8    that explores the steps required to establish a 
9    State-specific ISO. The Governor and members of the 
10    General Assembly may request an additional ISO policy 
11    study, or any other follow-up study, regardless of the 
12    outcome of the original study. An additional study may, 
13    for example, investigate the steps required for this State 
14    to consolidate into one existing RTO.
15        The additional ISO policy study shall investigate a 
16    governance structure and design that would enable State 
17    policy independence and more fully support State resource 
18    adequacy and reliability while also complying with FERC 
19    Order 2000. The additional ISO study may investigate how a 
20    State-specific ISO would be able to demonstrate the 
21    following issues, including, but not limited to:
22        (i) independence from market participants;
23        (ii) an appropriate scope and regional configuration;
24        (iii) possession of operational authority for all 
25    transmission facilities under the control of the 
26    State-specific ISO;
 
 
10400SB0025ham003- 824 -LRB104 07069 AAS 29208 a

1        (iv) exclusive authority to maintain short-term 
2    reliability of the grid;
3        (v) tariff administration and design;
4        (vi) congestion management;
5        (vii) management of parallel path flows;
6        (viii) provision of last resort for ancillary 
7    services;
8        (ix) development of an Open Access Same-time 
9    Information System (OASIS);
10        (x) market monitoring; and
11        (xi) responsibility for planning and expanding 
12    facilities under its control.
13    (d) The Commission and the Illinois Power Agency shall 
14retain the services of technical and policy experts with 
15relevant fields of expertise. Given the critical and rapid 
16actions required under this Section, the Commission and the 
17Illinois Power Agency may procure the services of any 
18facilitator, expert, or consultant to assist with the 
19implementation of this Section. Such procurement is exempt 
20from the requirements of the Illinois Procurement Code under 
21Section 20-10 of the Illinois Procurement Code. The Commission 
22and the Illinois Power Agency may jointly determine that the 
23cost of any contract pursuant to this Section may be borne 
24initially by the relevant electric public utilities, but shall 
25be recovered as an expense through normal ratemaking 
26procedures. The Illinois Finance Authority, the Illinois 
 
 
10400SB0025ham003- 825 -LRB104 07069 AAS 29208 a

1Environmental Protection Agency, and the Department of 
2Commerce and Economic Opportunity shall provide support to and 
3consult with the Commission and the Illinois Power Agency when 
4requested. The Commission and the Illinois Power Agency may 
5consult with other State agencies, commissions, or task forces 
6as needed.
7    (e) The Commission and the Illinois Power Agency may 
8solicit information, including confidential or proprietary 
9information, from entities likely to be impacted by the 
10creation of a State-specific ISO. The Commission and the 
11Illinois Power Agency may consult with and seek assistance 
12from (i) Independent System Operators in other states, such as 
13Texas, California, and New York, (ii) federal agencies, such 
14as the Federal Energy Regulatory Commission, and (iii) the 
15regional transmission organizations PJM and MISO. Any 
16information designated as confidential or proprietary 
17information by the entity providing the information shall be 
18kept confidential by the Commission, its consultants, and its 
19contractors, and the Illinois Power Agency, its consultants, 
20and its contractors, and is not subject to disclosure under 
21the Freedom of Information Act. The Office of the Attorney 
22General shall have access to, and maintain the confidentiality 
23of, such information pursuant to Section 6.5 of the Attorney 
24General Act.
25    (f) The Commission and the Illinois Power Agency shall 
26publish the joint final policy study no later than December 1, 
 
 
10400SB0025ham003- 826 -LRB104 07069 AAS 29208 a

12026 and suitable copies shall be delivered to the Governor 
2and members of the General Assembly.    
 
3    (220 ILCS 5/16-145 new)
4    Sec. 16-145. Powering Up Illinois.
5    (a) For the purposes of this Section:
6    "Electric utility" means an electric utility serving more 
7than 500,000 customers in this State.
8    "Energization" and "energize" means the connection of new 
9electric vehicle charging infrastructure projects over 5 
10megawatts to the electrical grid or upgrading electrical 
11capacity to provide adequate service to such electric vehicle 
12charging infrastructure projects. "Energization" and 
13"energize" do not include activities related to connecting 
14electricity supply resources.
15    "Energization time period" means the period of time that 
16begins when the electric utility receives a substantially 
17complete energization project application and ends when the 
18electric service associated with the project is installed and 
19energized, consistent with the service obligations set forth 
20in the Section 8-101 of the Public Utilities Act.
21    (b) The Commission shall adopt rules to establish and 
22track reasonable average and maximum target energization time 
23periods for energization projects. Such rules shall, at a 
24minimum, establish the following:
25        (1) reasonable average and maximum target energization 
 
 
10400SB0025ham003- 827 -LRB104 07069 AAS 29208 a

1    time periods. The targets shall ensure that work is 
2    completed in a safe and reliable manner that minimizes 
3    delay in meeting the date requested by a customer for 
4    completion of the energization project to the greatest 
5    extent possible. The targets may vary based on factors, 
6    including, but not limited to, customer class, size of the 
7    project, the complexity and magnitude of the work 
8    required, and uncertainties regarding the readiness of the 
9    customer project needing energization. The targets may 
10    also recognize any factors beyond the electric utility's 
11    control;
12        (2) requirements for an electric utility to report to 
13    the Commission, at least annually, in order to track and 
14    improve electric utility performance. The report shall, at 
15    a minimum, include the average, median, and standard 
16    deviation time between receiving an application for 
17    electrical service and energizing the electrical service, 
18    and detailed explanations for energization time periods 
19    that exceed the target maximum for energization projects, 
20    constraints and obstacles to each type of energization, 
21    including, but not limited to, funding limitations, 
22    qualified staffing availability, or equipment 
23    availability, and any other information that the 
24    Commission, in its discretion, concludes that such reports 
25    should contain; and
26        (3) procedures for customers to report energization 
 
 
10400SB0025ham003- 828 -LRB104 07069 AAS 29208 a

1    delays to the Commission.
2    (c) If an electric utility's average time period for 
3energization in a calendar year exceeds the Commission's 
4target averages or if an electric utility has exceeded the 
5Commission's target maximums as established by rule, the 
6electric utility shall include in its report pursuant to rules 
7adopted under paragraph (2) of subsection (b) a detailed 
8remedial plan for meeting the targets in the future. The 
9Commission may require modification to the electric utility's 
10remedial plan to ensure that the electric utility meets 
11targets promptly.
12    (d) Data reported by electric utilities shall be 
13anonymized or aggregated to the extent necessary to prevent 
14identifying individual customers. The Commission shall make 
15all such reports publicly available.
16    (e) In addition to requiring remedial plans pursuant to 
17subsection (c) of this Section, the Commission may require an 
18electric utility to take any remedial actions necessary to 
19achieve the Commission's targets.    
 
20    (220 ILCS 5/16-201 new)
21    Sec. 16-201. Integrated resource plan development.
22    (a) The General Assembly hereby finds that:
23        (1) In 2021, Illinois set itself on the path to a clean 
24    energy future that would produce the least amount of 
25    carbon and copollutant emissions while ensuring adequate, 
 
 
10400SB0025ham003- 829 -LRB104 07069 AAS 29208 a

1    reliable, affordable, efficient, and environmentally 
2    sustainable electric service at the lowest total cost over 
3    time and in a manner that benefits the Illinois economy 
4    and workforce and improves the quality of life, including 
5    environmental health, for all its citizens.
6        (2) In the ensuing years, Illinois has created a 
7    strong economic environment that has led to the 
8    revitalization and expansion of its manufacturing sector 
9    and has made Illinois an attractive place for the 
10    technology industry to locate new data and quantum 
11    computing centers. These developments have led to the 
12    creation of good-paying jobs for working families.
13        (3) The unforeseen growth in the manufacturing and 
14    technology sectors will likely lead to a dramatic increase 
15    in electricity demand over time.
16        (4) The long interconnection times and the capacity 
17    market structures enacted by the 2 regional transmission 
18    organizations that Illinois is split between further 
19    exacerbate the potential for an imbalance between 
20    electricity supply and demand.
21        (5) The new sources of load growth from the 
22    manufacturing and technology sectors combined with 
23    external challenges require a more nimble and responsive 
24    administrative approach to effectively address future 
25    resource adequacy challenges.
26        (6) The Illinois agencies that oversee and implement 
 
 
10400SB0025ham003- 830 -LRB104 07069 AAS 29208 a

1    Illinois energy policy must have the ability to (i) fully 
2    understand current and future resource adequacy needs, 
3    (ii) plan for what resources could be utilized to address 
4    such needs, (iii) be able to coordinate, modify, expand, 
5    and direct all of Illinois' existing energy programs and 
6    policies so as to address any resource adequacy or 
7    reliability concerns, and (iv) direct the development of 
8    new energy programs and policies in order meet resource 
9    adequacy and reliability needs without the need for 
10    additional legislative action.
11    (b) The purpose of this Section is to ensure that the 
12Commission, the agencies, electric utilities supplying 
13electric service in Illinois, stakeholders, market 
14participants, and policymakers have a common set of data and 
15information regarding the State's electricity resource needs 
16in order to plan for sufficient electricity resources to serve 
17Illinois customers in a manner that is adequate, safe, 
18reliable, affordable, efficient, environmentally sustainable, 
19at the lowest cost over time, and consistent with the energy 
20policy goals of the State, including, but not limited to, the 
21clean energy policy established by Public Act 102-662. To that 
22end, this Section establishes a requirement that the agencies 
23prepare an integrated resource plan and submit such plan to 
24the Commission consistent with this Section for the 
25Commission's review and approval after an opportunity for 
26notice and hearing.
 
 
10400SB0025ham003- 831 -LRB104 07069 AAS 29208 a

1    (c) Unless otherwise specified, as used in this Section, 
2the following terms shall have the following meanings:
3        (1) "Advanced transmission technologies" means 
4    technologies, tools, and software that improve power flows 
5    over transmission systems and lines. "Advanced 
6    transmission technologies" includes, but is not limited 
7    to, the following:
8            (i) technology that dynamically adjusts the rated 
9        capacity of transmission lines based on real-time 
10        conditions;
11            (ii) advanced power flow controls used to actively 
12        control the flow of electricity across transmission 
13        lines to optimize usage or relieve congestion;
14            (iii) software or hardware used to identify 
15        optimal transmission grid configurations or enable 
16        routing power flows around congestion points; and
17            (iv) advanced transmission line conductors that 
18        have a direct current electrical resistance at least 
19        10% lower than existing conductors of a similar 
20        diameter on the transmission system.
21        (2) "Agencies" means the Illinois Commerce Commission 
22    Staff, the Illinois Power Agency, the Illinois Finance 
23    Authority, the Illinois Environmental Protection Agency, 
24    and any consultants those agencies retain, including, but 
25    not limited to, the consultant retained by the Commission 
26    pursuant to subsection (j) of this Section and the 
 
 
10400SB0025ham003- 832 -LRB104 07069 AAS 29208 a

1    consultant retained by the Illinois Power Agency pursuant 
2    to paragraph (1) of subsection (a) of Section 1-75 of the 
3    Illinois Power Agency Act.
4        (3) "Clean energy" means energy generation that 
5    either:
6            (A) emits no on-site SO2, NOx, mercury, or any 
7        other regulated pollutants; or
8            (B) as shown through pollution control 
9        technologies, has reduced a utility's CO2 emissions by 
10        90% compared to what the utility would have otherwise 
11        emitted and that has CO2 emissions less than 130 
12        lb/MWh.
13        (4) "Regional transmission organization" or "RTO" 
14    means PJM Interconnection, LLC (PJM) and the Midcontinent 
15    Independent System Operator, Inc. (MISO) or the regional 
16    transmission organization or independent system operator 
17    of which the electric utility is a member or would be a 
18    member, given the location of the electric utility's 
19    customers, if it were required to be a member.
20    (d) The agencies, coordinated by Commission staff, shall 
21compile and propose an integrated resource plan in compliance 
22with this Section once every 4 years. The agencies may consult 
23with each electric utility that has more than 500,000 electric 
24retail customers in developing the plan and the plan shall 
25consider any necessary interactions between RTO zones in the 
26State. Commission staff shall submit the initial integrated 
 
 
10400SB0025ham003- 833 -LRB104 07069 AAS 29208 a

1resource plan to the Commission no later than November 15, 
22026, the second integrated resource plan to the Commission no 
3later than September 30, 2029, and each subsequent plan to the 
4Commission every 4 years thereafter no later than September 30 
5of the applicable year. For the first integrated resource plan 
6due on November 15, 2026, the agencies shall take into account 
7the resource adequacy report prepared pursuant to subsection 
8(o) of Section 9.15 of the Environmental Protection Act and 
9shall specifically address any and all divergences from the 
10analysis and conclusions in the report. At any time after the 
11submission of a plan, the agencies may submit an update to the 
12plan if the agencies believe that a material change in the 
13inputs or conclusions of the plan is warranted. The agencies 
14shall notify the Commission as soon as practicable of the 
15material change and the potential update to the plan. The 
16Commission shall publish the integrated resource plan on its 
17website.
18    (e) An alternative retail electric supplier shall provide 
19information related to the resource needs of its customers 
20located in an electric utility's service territory as 
21requested by the agencies or the Commission to compile and 
22develop the plan required by this Section.
23    (f) Commission staff shall lead the agencies in the 
24development of the integrated resource plan to ensure that a 
25plan submitted pursuant to this Section includes a detailed 
26analysis of the following:
 
 
10400SB0025ham003- 834 -LRB104 07069 AAS 29208 a

1        (1) an evaluation of the future electric resource 
2    needs in each electric utility's service area for periods 
3    of at least 5, 10, 15, and 20 years such that the plan 
4    coincides with the timelines established in Section 9.15 
5    of Title II of the Environmental Protection Act and is 
6    designed to support those standards to the maximum extent 
7    practicable on the schedule established therein;
8        (2) peak demand and energy usage forecasts, such that 
9    the plan:
10            (i) contains no fewer than 3 scenarios of (i) 
11        forecasted peak demand, (ii) net peak demand if 
12        different from peak demand, (iii) non-coincidental 
13        peak demand, and (iv) energy usage, to capture a 
14        reasonable range of forecasts based on historic trends 
15        and a diverse range of more conservative to high load 
16        growth based on reasonable projections. The scenarios 
17        should consider estimates of peak demand corresponding 
18        to seasons or other applicable time periods as defined 
19        by the regional transmission organization in which 
20        this State's electric utilities are a member;
21            (ii) reflects known changes in facility and 
22        appliance codes and standards;
23            (iii) reflects load reductions from 
24        State-sponsored programs;
25            (iv) reflects load reductions from programs 
26        sponsored by electric utilities;
 
 
10400SB0025ham003- 835 -LRB104 07069 AAS 29208 a

1            (v) reflects load reductions from aggregators of 
2        retail customers that can be applied to the host 
3        load-serving entity's resource adequacy requirement;
4            (vi) reflects load reductions from any other 
5        sources including out-of-state programs that could 
6        influence load;
7            (vii) reflects expected adoption of other 
8        distributed energy resources, including 
9        behind-the-meter generation; and
10            (viii) includes any additional sensitivities as 
11        determined by the agencies;
12        (3) an analysis of all generation and energy resource 
13    options available to meet the range of load forecasts with 
14    a focus on the first period of at least 5 years covered by 
15    the plan, including an analysis of existing supply found 
16    within each electric utility's service area and new supply 
17    expected to come online across that period of at least 5 
18    years, such that the plan shall consider the following:
19            (i) the current and projected status of electric 
20        resource adequacy throughout the State from sources 
21        the agencies deem reasonable;
22            (ii) a range of resource options that can be 
23        deployed at a reasonable scale, that provide clean 
24        energy to the maximum extent practicable, and that 
25        include generation and energy resources on both the 
26        demand-side and supply-side;
 
 
10400SB0025ham003- 836 -LRB104 07069 AAS 29208 a

1            (iii) developing technologies that will be 
2        commercially viable during the period of analysis;
3            (iv) reflect reasonable assumptions for capital 
4        and operating costs and the performance of resource 
5        technologies. The calculation of resource costs shall 
6        include reasonable expected costs for transmission 
7        interconnection and network upgrades made necessary by 
8        the addition of each resource; and
9            (v) appropriate considerations for implementation, 
10        such as:
11                (A) timelines for implementation, including, 
12            but not limited to, siting, permitting, 
13            engineering, transmission interconnection, and the 
14            time it takes to modify existing programs or 
15            create new programs and put them into operation;
16                (B) recommendations for how new clean 
17            resources should be developed to respond to 
18            resource adequacy challenges; and
19                (C) any other requirements for implementation;
20        (4) confirmation that the resource adequacy and 
21    reliability requirements employed in the plan meet the 
22    following conditions:
23            (i) the plan must reflect planning reserve margin 
24        requirements established by the corresponding RTO, 
25        other resource adequacy requirements set by an 
26        applicable authority as authorized by the State, or 
 
 
10400SB0025ham003- 837 -LRB104 07069 AAS 29208 a

1        another standard chosen by the Commission; and
2            (ii) the integrated resource plan may reflect a 
3        supplemental reliability analysis, including the 
4        evaluation of reliability metrics not prescribed by an 
5        RTO or other applicable authority as authorized by the 
6        State;
7        (5) consistency with existing State and federal 
8    environmental laws and policies, including, but not 
9    limited to, the decarbonization goals set forth in Section 
10    9.15 of the Illinois Environmental Protection Act. The 
11    plan may consider potential changes in State and federal 
12    environmental laws and policies. The plan must provide 
13    expected emissions for CO2, SO2, NOx, mercury, and any 
14    other regulated pollutants in order to analyze the impact 
15    of retirement timelines on emissions reductions. The plan 
16    must be consistent with the State's other clean energy 
17    goals and targets, including, but not limited to, its 
18    renewable portfolio standard, its energy efficiency 
19    portfolio standard, the carbon mitigation credit program, 
20    and its energy storage system portfolio standard. The plan 
21    shall include an analysis of the following:
22            (i) the State's current progress toward its 
23        renewable energy resource development goals, its 
24        storage development goals, and its energy efficiency 
25        and demand-response goals, as well as the pace of the 
26        development of renewables, energy storage, including 
 
 
10400SB0025ham003- 838 -LRB104 07069 AAS 29208 a

1        distributed storage, the deployment of virtual power 
2        plants, and demand-response utilization; and
3            (ii) the status of the State's CO2e and copollutant 
4        emissions reductions and its current status and 
5        progress toward developing emerging clean energy 
6        technologies;
7        (6) consideration of the following additional issues:
8            (i) an integrated resource plan shall be designed 
9        to collectively meet all of Illinois' energy policy 
10        goals and shall describe:
11                (A) how the plan complies with the various 
12            requirements of State energy policy;
13                (B) the assumptions and analytical methods 
14            used in the plan;
15                (C) recommendations for how State policy 
16            should serve to facilitate the development of new 
17            resources;
18                (D) the impacts of the plan on customer costs, 
19            including net present value costs relative to 
20            alternatives; and
21                (E) how the plan improves energy equity within 
22            environmental justice and equity investment 
23            eligible communities, as defined by the Energy 
24            Transition Act, including, but not limited to, 
25            reducing energy burden, ensuring affordability of 
26            electric utility bills and uninterruptible 
 
 
10400SB0025ham003- 839 -LRB104 07069 AAS 29208 a

1            essential utility service, and reducing barriers 
2            to accessing renewable energy;    
3            (ii) an integrated resource plan shall include a 
4        discussion of the steps needed to implement the plan, 
5        including, but not limited to, options and steps to 
6        bring on new or increased energy generated from any 
7        recommended resources for the 5 years after the plan 
8        would be implemented, that align with State clean 
9        energy policy;
10            (iii) an integrated resource plan shall consider 
11        the information and conclusions set forth in the 
12        renewable energy access plan developed in accordance 
13        with Section 8-512, including, but not limited to, 
14        information concerning the locations of renewable 
15        energy access plan zones, considerations of advanced 
16        transmission technologies to increase efficiencies, 
17        and different transmission planning options and cost 
18        allocations;
19            (iv) an integrated resource plan may consider the 
20        impacts of future or anticipated changes in State and 
21        federal energy laws and policies; and
22            (v) any solutions for any additional conclusions;
23        (7) if the agencies choose, portfolio-optimization 
24    results based on the following:
25            (i) capacity expansion and production cost 
26        modeling consistent with the conditions and 
 
 
10400SB0025ham003- 840 -LRB104 07069 AAS 29208 a

1        constraints set forth in this Section;
2            (ii) optimized candidate portfolios that align 
3        with the load-growth scenarios described in paragraph 
4        (2) of subsection (f) of this Section and any 
5        additional portfolios chosen by the agencies to 
6        reflect alternative policy or technology assumptions;
7            (iii) a comparison of total system cost on a 
8        net-present-value basis, customer rate and bill 
9        impacts, risk metrics, including, but not limited to, 
10        cost variability under fuel-price and load shocks, 
11        emissions trajectories, and key reliability 
12        indicators; and
13            (iv) an identification of a preferred portfolio or 
14        portfolios that best satisfy the objectives of 
15        affordability, reliability, equity, and emission 
16        reduction and a narrative explanation of why the 
17        portfolio is recommended; and
18    The agencies may request that PJM and MISO, or their 
19respective successor organizations, conduct a resource 
20adequacy and reliability study. The study shall include the 
21megawatt amount of energy storage capacity that would maintain 
22resource adequacy during the study period to fully meet the 
23requirements for CO2e and copollutant emissions reductions 
24under Public Act 102-662 that would not otherwise be met by the 
25interconnection queue and without large transmission upgrades, 
26including maintaining sufficient in-State capacity to meet the 
 
 
10400SB0025ham003- 841 -LRB104 07069 AAS 29208 a

1zonal requirements of MISO Zone 4 or the PJM ComEd Zone. The 
2study shall also identify recommended geographic locations for 
3new storage and clean energy to mitigate local reliability 
4risks, including at or near the sites of any generator 
5deactivations to maximize the efficient utilization of 
6existing infrastructure.    
 
7    (220 ILCS 5/16-202 new)
8    Sec. 16-202. Integrated resource plan review and approval.
9    (a) The Commission shall enter its order approving or 
10approving with modifications an integrated resource plan 
11within 180 days after the agencies filing the plan and any 
12companion reports or other information. The Commission may 
13extend the period of review of the plan for no more than an 
14additional 180 days.
15    (b) The Commission may approve a plan or a modified plan 
16and authorize its implementation only if, after notice and 
17hearing, including the conduct of discovery and taking of 
18evidence, it finds that the plan:
19        (1) addresses any resource adequacy challenges in the 
20    5 years immediately following approval of the plan, while 
21    also taking into account the 10 years following the plan;
22        (2) prepares the State to best address issues of 
23    resource adequacy at the least amount of CO2e and 
24    copollutant emissions;
25        (3) considers the emissions' impacts on environmental 
 
 
10400SB0025ham003- 842 -LRB104 07069 AAS 29208 a

1    justice communities while taking into account all 
2    applicable labor and equity standards;
3        (4) supports the provisioning of adequate, reliable, 
4    affordable, efficient, and environmentally sustainable 
5    electric service at the lowest total cost over time; and
6        (5) utilizes the expansion of renewable energy, energy 
7    storage, virtual power plants and distributed energy 
8    storage, energy efficiency, demand response, time-of-use 
9    rates or other mechanisms designed to manage peak load, 
10    transmission development, carbon mitigation credits or any 
11    other clean energy strategies to the maximum extent 
12    practicable to resolve any identified resource adequacy 
13    shortfall or reliability violation in a cost-effective, 
14    affordable, timely, and clean manner.
15    (c) The Commission may, as a part of its decision to 
16approve a plan or modified plan and to the extent consistent 
17with the uniform allocation of costs required under subsection 
18(k) of Section 16-108, order changes to existing programs, 
19direct specific actions within existing programs including the 
20authorization to support the expansion of an existing program, 
21including, but not limited to:
22        (1) any of the following plans or programs designed to 
23    increase the amount of generation and capacity available:
24            (i) the Long-Term Renewable Resources Procurement 
25        Plan, including programs and procurements authorized 
26        through that Plan, and to increase the limitations 
 
 
10400SB0025ham003- 843 -LRB104 07069 AAS 29208 a

1        placed on the procurement of renewable energy 
2        resources established pursuant to subparagraph (E) of 
3        paragraph (1) of subsection (c) of Section 1-75 of the 
4        Illinois Power Agency Act in order to increase, 
5        direct, or adjust procurements of renewable energy 
6        resources to support new renewable energy projects;
7            (ii) the Energy Storage Resources Procurement 
8        Plan, including programs and procurements authorized 
9        through that Plan, and to increase the procurement of 
10        energy storage established pursuant to subsection 
11        (d-20) of Section 1-75 of the Illinois Power Agency 
12        Act in order to increase or adjust procurements for 
13        new energy storage;
14            (iii) the carbon mitigation credit procurement 
15        plans established pursuant to subsection (d-10) of 
16        Section 1-75 of the Illinois Power Agency Act in order 
17        to preserve existing carbon-free energy resources, 
18        including extending or expanding carbon mitigation 
19        credit contract awards in accordance with a new 
20        schedule of baseline costs;
21            (iv) the Illinois Power Agency's annual 
22        electricity procurement plans established pursuant to 
23        paragraph (2) of subsection (d) of Section 16-111.5, 
24        including modification of the products to be procured 
25        and allowing for costs associated with the purchase of 
26        new or additional products to be socialized across all 
 
 
10400SB0025ham003- 844 -LRB104 07069 AAS 29208 a

1        retail customers or all load-serving entities, as 
2        applicable; and
3            (v) any additional programs designed to procure 
4        appropriate sources of new clean energy and capacity 
5        resources, including any associated clean attribute 
6        credits; and
7        (2) any of the following designed to manage energy 
8    demand, including, but not limited to:
9            (i) extending or expanding the energy efficiency 
10        programs implemented by electric utilities and the 
11        limitation on the amount of energy efficiency and 
12        demand-response measures implemented pursuant to 
13        Section 8-103B in order to gain increased load 
14        reductions; and
15            (ii) the Multi-Year Integrated Grid Plans 
16        implemented by electric utilities pursuant to Section 
17        16-105.17 in order to extend or expand programs 
18        related to peak load management and reduction, 
19        including, but not limited to, virtual power plants, 
20        front of the meter distributed storage, demand 
21        response, and time-of-use rates.
22    (d) If all of the changes made to the programs pursuant to 
23this Section would reasonably be insufficient to balance 
24supply and demand and avoid a resource adequacy shortfall, 
25then the Commission may delay, in whole or in part, the CO2e    
26and copollutant emissions reductions requirements found in 
 
 
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1Section 9.15 of the Environmental Protection Act but only to 
2the minimum extent and duration necessary to address the 
3resource adequacy shortfall needs of the State. If the 
4Commission finds that reducing or delaying the emissions 
5reductions requirements is necessary, despite any or all of 
6the changes made pursuant to this Section, then it shall also 
7include in its final order recommendations to the General 
8Assembly on what additional policies may be adopted that could 
9avoid future modifications to the emissions reductions.
10    (e) Unless otherwise specified by the Commission, the 
11order approving the plan or modified plan shall become 
12effective January 1 of the calendar year immediately following 
13the issuance of the order. The agencies, electric utilities, 
14and any other impacted entities shall comply with any of the 
15Commission's orders, and when required seek approval from the 
16Commission and make any required modifications to their plans, 
17programs, or related initiatives in a manner consistent with 
18the process and timing for those changes as outlined in the 
19approved plans or, if none is specified, as soon as 
20practicable. If the integrated resource plan approved by the 
21Commission contains recommendations that are outside the 
22Commission's authority, the Commission shall communicate any 
23such recommendations to the Governor and the General Assembly.
24    (f) Given the critical and rapid actions required under 
25this Section, the Commission may procure the services of any 
26facilitator, expert, or consultant, including the procurement 
 
 
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1monitor retained by the Commission pursuant to paragraph (2) 
2of subsection (c) of Section 16-111.5. Such procurement is 
3exempt from the requirements of the Illinois Procurement Code, 
4pursuant to Section 20-10 of that Code.
5    (g) Costs that are prudently and reasonably incurred by 
6electric utilities to comply with the requirements of this 
7Section shall be recovered and shall be excluded from the 
8calculation performed under paragraph (6) of subsection (f) of 
9Section 16-108.18. Nothing in the Commission's order directing 
10changes to a prior approved plan as enumerated in this Section 
11shall be the sole basis for a finding of imprudence or 
12unreasonableness or the lack of use or usefulness of any 
13investment or expenditure.    
14    (h) In the event that the Commission's final order under 
15this Section includes the approval of rate increases through 
16the expansion of existing programs, the creation of new 
17programs, or the increase of limitations placed on 
18procurements as described under paragraphs (1) and (2) of 
19subsection (c), the Commission shall submit notice to the 
20General Assembly of the increases included in the final order, 
21including the estimated monthly cost impact on customers and 
22the expected costs savings or benefits of such actions. After 
23receipt of a notice, any member of the General Assembly may 
24introduce in the General Assembly a joint resolution stating 
25that the General Assembly desires to suspend the rate 
26increases, or suspend a portion of the rate increases, 
 
 
10400SB0025ham003- 847 -LRB104 07069 AAS 29208 a

1identified in the final order and specifying the rationale for 
2the General Assembly's determination.
3        (1) If the General Assembly passes a joint resolution 
4    under this subsection (h) that takes effect prior to the 
5    effective date of the Commission's final order, the 
6    General Assembly shall send notice to the Commission of 
7    the resolution, and the Commission shall suspend its final 
8    order. Within 30 days of receipt of the General Assembly's 
9    notice, the Commission shall reopen the docket approving 
10    the plan or modified plan in order to take into account the 
11    General Assembly's reduction or elimination of the rate 
12    increases. The Commission shall approve the modified plan 
13    within 120 days of reopening the docket and send notice to 
14    the General Assembly of its modified plan. The General 
15    Assembly may rescind its desire to suspend the rate 
16    increases, or suspend a portion of the rate increases, by 
17    adoption of a subsequent joint resolution by each chamber 
18    of the General Assembly within 30 days of receipt of the 
19    Commission's notice.
20        (2) If the General Assembly fails to pass a joint 
21    resolution under this subsection (h) prior to the 
22    effective date of the Commission's final order, the 
23    associated rate increases shall be deemed just, 
24    reasonable, and approved and shall go into effect pursuant 
25    to the schedule specified in the Commission's final order 
26    approving the plan or modified plan.    
 
 
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1    (i) The Commission may adopt rules to implement the 
2requirements of this Section.    
 
3    (220 ILCS 5/17-900)
4    Sec. 17-900. Customer self-generation of electricity.
5    (a) The General Assembly finds and declares that municipal 
6systems and electric cooperatives shall continue to be 
7governed by their respective governing bodies, but that such 
8governing bodies should recognize and implement policies to 
9provide the opportunity for their residential and small 
10commercial customers who wish to self-generate electricity and 
11for reasonable credits to customers for excess electricity, 
12balanced against the rights of the other non-self-generating 
13customers. This includes creating consistent, fair policies 
14that are accessible to all customers and transparent, fair 
15processes for raising and addressing any concerns.
16    (b) Customers have the right to install renewable 
17generating facilities to be located on the customer's premises 
18or customer's side of the billing meter and that are intended 
19primarily to offset the customer's own electrical requirements 
20and produce, consume, and store their own renewable energy 
21without discriminatory repercussions from an electric 
22cooperative or municipal system. This includes a customer's 
23rights to:
24        (1) generate, consume, and deliver excess renewable 
25    energy to the distribution grid and reduce his or her use 
 
 
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1    of electricity obtained from the grid;
2        (2) use technology to store energy at his or her 
3    residence;
4        (3) interconnect his or her electrical system that 
5    generates renewable energy, stores energy, or any 
6    combination thereof, with the electricity meter on the 
7    customer's premises that is provided by an electric 
8    cooperative or municipal system:
9            (A) in a timely manner;
10            (B) in accordance with requirements established by 
11        the electric cooperative or municipal utility to 
12        ensure the safety of utility workers; and
13            (C) after providing written notice to the electric 
14        cooperative or municipal utility system providing 
15        service in the service territory, installing a 
16        nomenclature plate on the electrical meter panel and 
17        meeting all applicable State and local safety and 
18        electrical code requirements associated with 
19        installing a parallel distributed generation system; 
20        and
21        (4) receive fair credit for excess energy delivered to 
22    the distribution grid; and
23        (5) for residential and small commercial customers, 
24    interconnect renewable energy systems sized up to and 
25    including 25 kW AC.
26    (c) The policies of municipal systems and electric 
 
 
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1cooperatives regarding self-generation and credits for excess 
2electricity may reasonably differ from those required of other 
3entities by Article XVI of the Public Utilities Act or other 
4Acts. The credits must recognize the value of self-generation 
5to the distribution grid and benefits to other customers.
6    (c-5) The policies of municipal systems and electric 
7cooperatives regarding self-generation and credits for excess 
8electricity shall not require customers to name the municipal 
9system or electric cooperative as an additional insured on the 
10customer's insurance policies or have any minimum liability 
11limit requirement in connection with the installation and 
12operation of renewable generating facilities if the renewable 
13generating facilities meet the safety standards listed in the 
14applicable interconnection agreement and the contractor used 
15to install the renewable generating facilities is licensed and 
16possesses commercial general liability insurance coverage of 
17at least $1,000,000 per occurrence and $2,000,000 in the 
18aggregate per year.    
19    (d) Within 180 days after this amendatory Act of the 102nd 
20General Assembly, each electric cooperative and municipal 
21system shall update its policies for the interconnection and 
22fair crediting of customer self-generation and storage if 
23necessary, to comply with the standards of subsection (b) of 
24this Section. Each electric cooperative and municipal system 
25shall post its updated policies to a public-facing area of its 
26website.
 
 
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1    (e) An electric cooperative or municipal system customer 
2who produces, consumes, and stores his or her own renewable 
3energy shall not face discriminatory rate design, fees or 
4charges, treatment, or excessive compliance requirements that 
5would unreasonably affect that customer's right to 
6self-generate electricity as provided for in this Section.
7    (f) An electric cooperative or municipal utility system 
8customer shall have a right to appeal any decision related to 
9self-generation and storage that violates these rights to 
10self-generation and non-discrimination pursuant to the 
11provisions of this Section through a complaint under the 
12Administrative Review Law or similar legal process.
13(Source: P.A. 102-662, eff. 9-15-21.)
 
14    (220 ILCS 5/20-140 new)
15    Sec. 20-140. Interconnection Working Group.
16    (a) The Commission shall establish an Interconnection 
17Working Group. The Working Group shall include representatives 
18from electric utilities, developers of renewable electric 
19generating facilities, representatives of new large loads 
20seeking grid interconnection, other industries that regularly 
21apply for interconnection with the electric utilities as 
22appropriate, representatives of distributed generation 
23customers, the Commission staff, and other stakeholders with a 
24substantial interest in the topics addressed by the 
25Interconnection Working Group.
 
 
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1    (b) The Interconnection Working Group shall address at 
2least the following issues in relation to new generation and 
3new large loads:
4        (1) the cost of and the best available technology for 
5    interconnection and metering, including the 
6    standardization and publication of standard costs;
7        (2) transparency, accuracy, and use of the 
8    distribution interconnection queue and hosting capacity 
9    maps;
10        (3) distribution system upgrade cost avoidance through 
11    use of advanced inverter functions, energy storage, and 
12    load management;
13        (4) predictability of the queue management process and 
14    enforcement of timelines;
15        (5) benefits and challenges associated with group 
16    studies and cost sharing;
17        (6) minimum requirements for application to the 
18    interconnection process and throughout the interconnection 
19    process to avoid queue clogging behavior;
20        (7) the process and customer service for 
21    interconnecting customers adopting distributed energy 
22    resources, including energy storage;
23        (8) options for metering distributed energy resources, 
24    including energy storage;
25        (9) interconnection of new technologies, including 
26    smart inverters and energy storage;
 
 
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1        (10) collection, examination, and sharing of data on 
2    Level 1 interconnection costs, including cost and type of 
3    upgrades required for interconnection, and the use of this 
4    data to inform the final standardized cost of Level 1 
5    interconnection;
6        (11) determination of a single standardized cost for 
7    Level 1 interconnections, which shall not exceed $200; and
8        (12) such other technical, policy, and tariff issues 
9    related to and affecting interconnection performance and 
10    customer service as determined by the Interconnection 
11    Working Group.
12    (c) The Commission may create subcommittees of the 
13Interconnection Working Group to focus on specific issues of 
14importance, as appropriate.
15    (d) The Interconnection Working Group shall report to the 
16Commission on recommended improvements to interconnection 
17rules, tariffs, and policies as determined by the 
18Interconnection Working Group at least every year. A report 
19shall include consensus recommendations of the Interconnection 
20Working Group and, if applicable, additional recommendations 
21for which consensus was not reached. Non-consensus shall not 
22be a basis for excluding recommendations that are majority or 
23minority recommendations. The Commission shall use the report 
24from the Interconnection Working Group to determine whether 
25processes should be commenced to formally codify or implement 
26the recommendations. The Interconnection Working Group shall 
 
 
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1provide the reports under this subsection (d) to the 
2Commission on at least the following topics in the order 
3listed below within a reasonable time, but no later than 12 
4months, after the effective date of this amendatory Act of the 
5104th General Assembly: (A) a mechanism for good cause 
6extensions to construction timelines as long as the 
7interconnection customer reasonably demonstrates progress; (B) 
8a mechanism for all electric utilities to accept cash, letters 
9of credit, or bonds for any deposits required under the 
10interconnection agreement; (C) cost sharing for distribution 
11system upgrades and interconnection facilities for multiple 
12interconnection customers attempting to interconnect on the 
13same feeder or substation; (D) requirements that 
14interconnection studies process without delay based on queue 
15position or status of applications ahead in the queue, and 
16associated requirements for disclosure of contingent upgrades; 
17(E) provisions allowing for queue reservation for the 
18interconnection of projects installed on public school land to 
19accommodate timing constraints of school board approval and 
20budgeting; and (F) if feasible within the time allotted for 
21the initial report, parameters for utility interconnection 
22studies of energy storage systems not paired with distributed 
23generation that are based on the proposed operational profile 
24of the energy storage systems.
25    (d-5) Within 12 months after the report directed by 
26subsection (d) has been submitted, the Working Group shall 
 
 
10400SB0025ham003- 855 -LRB104 07069 AAS 29208 a

1report to the Commission on the following: (A) mandatory 
2disclosures on the hosting capacity map and studies for 
3contingent upgrades including timelines for notice of 
4responsibility and payment; (B) a framework for concurrent 
5study on multiple feeders for a distributed energy resource; 
6and (C) if not provided in the initial report required under 
7subsection (d), parameters for utility interconnection studies 
8of energy storage systems not paired with distributed 
9generation that are based on the proposed operational profile 
10of the energy storage systems.
11    (d-10) Within 12 months after the report directed by 
12subsection (d-5) has been submitted, the Working Group shall 
13report to the Commission on the following: (A) dynamic hosting 
14capacity maps; (B) standards for public queue and hosting 
15capacity map information regarding individual projects in 
16queue, including (i) distributed generation nameplate 
17capacity, (ii) paired or stand-alone energy storage system 
18nameplate capacity, (iii) detailed estimated upgrade costs, 
19and (iv) systems that have completed upgrades and withdrawn 
20projects; and (C) timelines for refund of deposits if the 
21interconnection agreement is terminated. Within the same time 
22period, utilities shall publish all final interconnection 
23agreements, facilities studies, and system impact studies.
24    (d-15) Within 12 months after the report directed by 
25subsection (d-10) has been submitted, the Working Group shall 
26report to the Commission on the following: (A) level of detail 
 
 
10400SB0025ham003- 856 -LRB104 07069 AAS 29208 a

1of costs in system impact and facilities studies and level 2 
2studies; and (B) a cap on charges to the interconnection 
3customer based on a percentage of the non-binding cost 
4estimate in the facilities study, system impact study, or 
5level 2 study.
6    (e) In collaboration with the General Counsel of the 
7Commission, the Office of Retail Market Development shall 
8develop policies and procedures to facilitate employees of the 
9Office in leading the Interconnection Working Group without 
10interference with docketed proceedings. The policies and 
11procedures developed under this subsection (e) shall be 
12designed to allow the Interconnection Working Group to work 
13without interruption.    
 
14    (220 ILCS 5/20-145 new)
15    Sec. 20-145. Interconnection Monitor.
16    (a) The Office of Retail Market Development may employ, 
17designate, or otherwise retain the services of an Ombudsperson 
18who, in addition to the roles described in this Act, is 
19responsible for overseeing electric utility compliance with 
20the standards established by this Section and other regulatory 
21or statutory obligations regarding interconnections.
22    (b) The Ombudsperson may from time to time request, and 
23each electric utility shall timely provide records and 
24information to carry out his or her duties under this Section.
25    (c) The Office shall monitor interconnection between 
 
 
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1electric utilities and applicants for interconnection and 
2interconnection customers. The Office may request, and 
3electric utilities shall promptly provide, information and 
4records related to pending, successful, and terminated 
5interconnections.
6    (d) The Office may require electric utilities to provide a 
7detailed breakdown of the non-binding costs of operation and 
8an estimate that transparently itemizes operational costs, 
9including equipment by type or model, labor, operation and 
10maintenance, engineering and design, permitting, easements and 
11rights-of-way, direct overhead, and indirect overhead.
12    (e) The Office may establish an informal interconnection 
13dispute resolution process that may supersede 83 Ill. Adm. 
14Code 466.130, 83 Ill. Adm. Code 467.80, and interconnection 
15agreements to the extent described in this subsection (e). 
16Following the informal process described in this Section, 
17including any extensions agreed upon by the parties, an 
18electric utility, an interconnection customer, or an 
19interconnection applicant may submit the interconnection 
20dispute to the Ombudsperson, or his or her designee. The 
21Ombudsperson, or his or her designee, shall provide a 
22recommended resolution of such dispute within 30 days after 
23the Ombudsperson determines that full information from all 
24parties to the dispute has been received. The electric 
25utility, the interconnection customer, the interconnection 
26applicant, or any other party authorized to initiate dispute 
 
 
10400SB0025ham003- 858 -LRB104 07069 AAS 29208 a

1resolution under the Commission's rules authorized by this Act 
2may include the Ombudsperson's recommendation in any formal 
3complaint before the Commission.
4    (f) The Office is encouraged to include at least one 
5employee, at the Bureau Chief's discretion, with a background 
6in engineering of renewable resources and distribution 
7interconnections.    
 
8    (220 ILCS 5/Art. XXIII heading new)
9
ARTICLE XXIII.  SITING APPEALS BOARD

 
10    (220 ILCS 5/23-105 new)
11    Sec. 23-105. Findings. The General Assembly finds that:    
12        (1) the timely siting and development of commercial 
13    wind energy facilities, commercial solar energy 
14    facilities, and energy storage system facilities is 
15    critical to the State's energy security;
16        (2) the General Assembly has adopted statewide county 
17    siting regulations to establish uniform standards for 
18    commercial wind energy facilities, commercial solar energy 
19    facilities, and energy storage system facilities 
20    throughout this State;
21        (3) a consistent dispute resolution process with 
22    respect to the siting and development of commercial wind 
23    energy facilities, commercial solar energy facilities, and 
24    energy storage system facilities is necessary to provide 
 
 
10400SB0025ham003- 859 -LRB104 07069 AAS 29208 a

1    fair and expeditious decisions on siting disputes to 
2    parties affected by the development and siting of a 
3    renewable energy project;
4        (4) empowering the Commission to resolve siting 
5    disputes would allow parties to avoid time-consuming and 
6    costly litigation and would provide consistency and 
7    certainty to the renewable energy siting and development 
8    process in the State; and
9        (5) the Commission has the relevant expertise to 
10    establish and govern a renewable energy siting disputes 
11    resolution process.
 
12    (220 ILCS 5/23-110 new)
13    Sec. 23-110. Definitions. In this Article:
14    "Commercial solar energy facility" has the meaning given 
15to that term in subsection (a) of Section 5-12020 of the 
16Counties Code. "Commercial solar energy facility" includes 
17supporting facilities, as defined in subsection (a) of Section 
185-12020 of the Counties Code.
19    "Commercial wind energy facility" has the meaning given to 
20that term in subsection (a) of Section 5-12020 of the Counties 
21Code. "Commercial wind energy facility" includes supporting 
22facilities, as defined in subsection (a) of Section 5-12020 of 
23the Counties Code.    
24    "Energy storage system facility" has the meaning given to 
25that term in Section 5-12024 of the Counties Code. "Energy 
 
 
10400SB0025ham003- 860 -LRB104 07069 AAS 29208 a

1storage system facility" includes supporting facilities, as 
2defined in subsection (a) of Section 5-12024 of the Counties 
3Code.    
 
4    (220 ILCS 5/23-115 new)
5    Sec. 23-115. Siting appeals board. The Illinois Commerce 
6Commission shall establish a siting appeals board to resolve 
7disputes involving the siting of commercial wind energy 
8facilities, commercial solar energy facilities, and energy 
9storage system facilities throughout the State. The Commission 
10shall adopt any rules necessary to establish and govern the 
11siting appeals board.
 
12    Section 90-40. The Electric Transmission Systems 
13Construction Standards Act is amended by changing Sections 5 
14and 15 as follows:
 
15    (220 ILCS 32/5)
16    Sec. 5. Definitions. For the purposes of this Act:
17    "Commission" means the Illinois Commerce Commission. 
18    "Construction contractor" means any nonutility entity 
19responsible for the construction, installation, maintenance, 
20or repair of electric transmission systems subject to this 
21Act.
22    "Electric transmission systems" means an electrical 
23transmission system designed and constructed with the 
 
 
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1capability of being safely and reliably energized at 69 
2kilovolts or more, including transmission lines, transmission 
3towers, conductors, insulators, foundations, grounding 
4systems, access roads, and all associated transmission 
5facilities, including transmission substations. "Electric 
6transmission systems" does not include projects located on the 
7electric generating facility's side of the facility's point of 
8interconnection or facilities not functionally classified as 
9transmission systems, regardless of voltage.
10    "OSHA" means Occupational Safety and Health 
11Administration.
12    "Utility" means an entity that is a public utility, as 
13defined in Section 3-105 of the Public Utilities Act, and that 
14serves residential customers. has the meaning given to that 
15term in Section 3-105 of the Public Utilities Act.
16(Source: P.A. 103-1066, eff. 2-20-25.)
 
17    (220 ILCS 32/15)
18    Sec. 15. Requirements for construction contractors.
19    (a) Prevailing wage compliance. All utilities and    
20construction contractors responsible for the construction, 
21installation, maintenance, or repair of electric transmission 
22systems shall pay employees performing the construction, 
23installation, maintenance, or repair work of such systems 
24wages and benefits consistent with the Prevailing Wage Act.
25    (b) Training and competence requirement. To ensure safety 
 
 
10400SB0025ham003- 862 -LRB104 07069 AAS 29208 a

1and reliability in the construction, installation, 
2maintenance, and repair of electric transmission systems, each 
3electric utility and construction contractor must demonstrate 
4the competence of their employees who are performing the work 
5of construction, installation, maintenance, or repair of 
6electric transmission systems, which shall be consistent with 
7the standards required by Illinois utilities as of January 1, 
82007, or greater. Competence must include, at a minimum: (1) 
9completion, or active participation with ultimate completion, 
10in an accredited or recognized apprenticeship program for the 
11relevant craft, trade, or skill; or (2) a minimum of 2 years of 
12direct employment in the specific work function. 
13    The Commission shall oversee compliance to ensure 
14employees meet these standards.
15    (c) Safety training. All employees engaged in the 
16construction, installation, maintenance, or repair of electric 
17transmission systems must successfully complete OSHA-certified 
18safety training required for their specific roles on the 
19project site.
20    (d) Diversity Plan.
21        (1) All construction contractors engaged in the 
22    construction, installation, maintenance, or repair of 
23    electric transmission systems shall develop a Diversity 
24    Plan that sets forth:
25            (A) the goals for apprenticeship hours to be 
26        performed by minorities and women;
 
 
10400SB0025ham003- 863 -LRB104 07069 AAS 29208 a

1            (B) the goals for total hours to be performed by 
2        underrepresented minorities and women; and
3            (C) spending for women-owned, minority-owned, 
4        veteran-owned, and small business enterprises in the 
5        previous calendar year.
6        (2) These goals shall be expressed as a percentage of 
7    the total work performed by the construction contractor 
8    submitting the plan and the actual spending for all 
9    women-owned, minority-owned, veteran-owned, and small 
10    business enterprises shall also be expressed as a 
11    percentage of the total work performed by the construction 
12    contractor submitting the Diversity Plan.
13        (3) For purposes of the Diversity Plan, minorities and 
14    women shall have the same definition as defined in the 
15    Business Enterprise for Minorities, Women, and Persons 
16    with Disabilities Act.
17        (4) The construction contractor shall submit the 
18    Diversity Plan to the Commission.
19(Source: P.A. 103-1066, eff. 2-20-25.)
 
20    Section 90-45. The Environmental Protection Act is amended 
21by changing Sections 9.15 and 39 as follows:
 
22    (415 ILCS 5/9.15)
23    Sec. 9.15. Greenhouse gases.
24    (a) An air pollution construction permit shall not be 
 
 
10400SB0025ham003- 864 -LRB104 07069 AAS 29208 a

1required due to emissions of greenhouse gases if the 
2equipment, site, or source is not subject to regulation, as 
3defined by 40 CFR 52.21, as now or hereafter amended, for 
4greenhouse gases or is otherwise not addressed in this Section 
5or by the Board in regulations for greenhouse gases. These 
6exemptions do not relieve an owner or operator from the 
7obligation to comply with other applicable rules or 
8regulations.
9    (b) An air pollution operating permit shall not be 
10required due to emissions of greenhouse gases if the 
11equipment, site, or source is not subject to regulation, as 
12defined by Section 39.5 of this Act, for greenhouse gases or is 
13otherwise not addressed in this Section or by the Board in 
14regulations for greenhouse gases. These exemptions do not 
15relieve an owner or operator from the obligation to comply 
16with other applicable rules or regulations.
17    (c) (Blank). 
18    (d) (Blank).
19    (e) (Blank). 
20    (f) As used in this Section:
21    "Carbon dioxide emission" means the plant annual CO2 total 
22output emission as measured by the United States Environmental 
23Protection Agency in its Emissions & Generation Resource 
24Integrated Database (eGrid), or its successor. 
25    "Carbon dioxide equivalent emissions" or "CO2e" means the 
26sum total of the mass amount of emissions in tons per year, 
 
 
10400SB0025ham003- 865 -LRB104 07069 AAS 29208 a

1calculated by multiplying the mass amount of each of the 6 
2greenhouse gases specified in Section 3.207, in tons per year, 
3by its associated global warming potential as set forth in 40 
4CFR 98, subpart A, table A-1 or its successor, and then adding 
5them all together.
6    "Cogeneration" or "combined heat and power" refers to any 
7system that, either simultaneously or sequentially, produces 
8electricity and useful thermal energy from a single fuel 
9source.
10    "Copollutants" refers to the 6 criteria pollutants that 
11have been identified by the United States Environmental 
12Protection Agency pursuant to the Clean Air Act.
13    "Electric generating unit" or "EGU" means a fossil 
14fuel-fired stationary boiler, combustion turbine, or combined 
15cycle system that serves a generator that has a nameplate 
16capacity greater than 25 MWe and produces electricity for 
17sale.
18    "Environmental justice community" means the definition of 
19that term based on existing methodologies and findings, used 
20and as may be updated by the Illinois Power Agency and its 
21program administrator in the Illinois Solar for All Program.
22    "Equity investment eligible community" or "eligible 
23community" means the geographic areas throughout Illinois that 
24would most benefit from equitable investments by the State 
25designed to combat discrimination and foster sustainable 
26economic growth. Specifically, eligible community means the 
 
 
10400SB0025ham003- 866 -LRB104 07069 AAS 29208 a

1following areas:
2        (1) areas where residents have been historically 
3    excluded from economic opportunities, including 
4    opportunities in the energy sector, as defined as R3 areas 
5    pursuant to Section 10-40 of the Cannabis Regulation and 
6    Tax Act; and
7        (2) areas where residents have been historically 
8    subject to disproportionate burdens of pollution, 
9    including pollution from the energy sector, as established 
10    by environmental justice communities as defined by the 
11    Illinois Power Agency pursuant to the Illinois Power 
12    Agency Act, excluding any racial or ethnic indicators.
13    "Equity investment eligible person" or "eligible person" 
14means the persons who would most benefit from equitable 
15investments by the State designed to combat discrimination and 
16foster sustainable economic growth. Specifically, eligible 
17person means the following people:
18        (1) persons whose primary residence is in an equity 
19    investment eligible community;
20        (2) persons whose primary residence is in a 
21    municipality, or a county with a population under 100,000, 
22    where the closure of an electric generating unit or mine 
23    has been publicly announced or the electric generating 
24    unit or mine is in the process of closing or closed within 
25    the last 5 years;
26        (3) persons who are graduates of or currently enrolled 
 
 
10400SB0025ham003- 867 -LRB104 07069 AAS 29208 a

1    in the foster care system; or
2        (4) persons who were formerly incarcerated.
3    "Existing emissions" means: 
4        (1) for CO2e, the total average tons-per-year of CO2e 
5    emitted by the EGU or large GHG-emitting unit either in 
6    the years 2018 through 2020 or, if the unit was not yet in 
7    operation by January 1, 2018, in the first 3 full years of 
8    that unit's operation; and
9        (2) for any copollutant, the total average 
10    tons-per-year of that copollutant emitted by the EGU or 
11    large GHG-emitting unit either in the years 2018 through 
12    2020 or, if the unit was not yet in operation by January 1, 
13    2018, in the first 3 full years of that unit's operation. 
14    "Green hydrogen" means a power plant technology in which 
15an EGU creates electric power exclusively from electrolytic 
16hydrogen, in a manner that produces zero carbon and 
17copollutant emissions, using hydrogen fuel that is 
18electrolyzed using a 100% renewable zero carbon emission 
19energy source.
20    "Large greenhouse gas-emitting unit" or "large 
21GHG-emitting unit" means a unit that is an electric generating 
22unit or other fossil fuel-fired unit that itself has a 
23nameplate capacity or serves a generator that has a nameplate 
24capacity greater than 25 MWe and that produces electricity, 
25including, but not limited to, coal-fired, coal-derived, 
26oil-fired, natural gas-fired, and cogeneration units.
 
 
10400SB0025ham003- 868 -LRB104 07069 AAS 29208 a

1    "NOx emission rate" means the plant annual NOx total output 
2emission rate as measured by the United States Environmental 
3Protection Agency in its Emissions & Generation Resource 
4Integrated Database (eGrid), or its successor, in the most 
5recent year for which data is available.
6    "Public greenhouse gas-emitting units" or "public 
7GHG-emitting unit" means large greenhouse gas-emitting units, 
8including EGUs, that are wholly owned, directly or indirectly, 
9by one or more municipalities, municipal corporations, joint 
10municipal electric power agencies, electric cooperatives, or 
11other governmental or nonprofit entities, whether organized 
12and created under the laws of Illinois or another state.
13    "SO2 emission rate" means the "plant annual SO2 total 
14output emission rate" as measured by the United States 
15Environmental Protection Agency in its Emissions & Generation 
16Resource Integrated Database (eGrid), or its successor, in the 
17most recent year for which data is available.
18    (g) All EGUs and large greenhouse gas-emitting units that 
19use coal or oil as a fuel and are not public GHG-emitting units 
20shall permanently reduce all CO2e and copollutant emissions to 
21zero no later than January 1, 2030.
22    (h) All EGUs and large greenhouse gas-emitting units that 
23use coal as a fuel and are public GHG-emitting units shall 
24permanently reduce CO2e emissions to zero no later than 
25December 31, 2045. Any source or plant with such units must 
26also reduce their CO2e emissions by 45% from existing 
 
 
10400SB0025ham003- 869 -LRB104 07069 AAS 29208 a

1emissions by no later than January 1, 2035. If the emissions 
2reduction requirement is not achieved by December 31, 2035, 
3the plant shall retire one or more units or otherwise reduce 
4its CO2e emissions by 45% from existing emissions by June 30, 
52038.
6    (i) All EGUs and large greenhouse gas-emitting units that 
7use gas as a fuel and are not public GHG-emitting units shall 
8permanently reduce all CO2e and copollutant emissions to zero, 
9including through unit retirement or the use of 100% green 
10hydrogen or other similar technology that is commercially 
11proven to achieve zero carbon emissions, according to the 
12following:
13        (1) No later than January 1, 2030: all EGUs and large 
14    greenhouse gas-emitting units that have a NOx emissions 
15    rate of greater than 0.12 lbs/MWh or a SO2 emission rate of 
16    greater than 0.006 lb/MWh, and are located in or within 3 
17    miles of an environmental justice community designated as 
18    of January 1, 2021 or an equity investment eligible 
19    community.
20        (2) No later than January 1, 2040: all EGUs and large 
21    greenhouse gas-emitting units that have a NOx emission 
22    rate of greater than 0.12 lbs/MWh or a SO2 emission rate 
23    greater than 0.006 lb/MWh, and are not located in or 
24    within 3 miles of an environmental justice community 
25    designated as of January 1, 2021 or an equity investment 
26    eligible community. After January 1, 2035, each such EGU 
 
 
10400SB0025ham003- 870 -LRB104 07069 AAS 29208 a

1    and large greenhouse gas-emitting unit shall reduce its 
2    CO2e emissions by at least 50% from its existing emissions 
3    for CO2e, and shall be limited in operation to, on average, 
4    6 hours or less per day, measured over a calendar year, and 
5    shall not run for more than 24 consecutive hours except in 
6    emergency conditions, as designated by a Regional 
7    Transmission Organization or Independent System Operator.
8        (3) No later than January 1, 2035: all EGUs and large 
9    greenhouse gas-emitting units that began operation prior 
10    to the effective date of this amendatory Act of the 102nd 
11    General Assembly and have a NOx emission rate of less than 
12    or equal to 0.12 lb/MWh and a SO2 emission rate less than 
13    or equal to 0.006 lb/MWh, and are located in or within 3 
14    miles of an environmental justice community designated as 
15    of January 1, 2021 or an equity investment eligible 
16    community. Each such EGU and large greenhouse gas-emitting 
17    unit shall reduce its CO2e emissions by at least 50% from 
18    its existing emissions for CO2e no later than January 1, 
19    2030.
20        (4) No later than January 1, 2040: All remaining EGUs 
21    and large greenhouse gas-emitting units that have a heat 
22    rate greater than or equal to 7000 BTU/kWh. Each such EGU 
23    and Large greenhouse gas-emitting unit shall reduce its 
24    CO2e emissions by at least 50% from its existing emissions 
25    for CO2e no later than January 1, 2035.
26        (5) No later than January 1, 2045: all remaining EGUs 
 
 
10400SB0025ham003- 871 -LRB104 07069 AAS 29208 a

1    and large greenhouse gas-emitting units. 
2    (j) All EGUs and large greenhouse gas-emitting units that 
3use gas as a fuel and are public GHG-emitting units shall 
4permanently reduce all CO2e and copollutant emissions to zero, 
5including through unit retirement or the use of 100% green 
6hydrogen or other similar technology that is commercially 
7proven to achieve zero carbon emissions by January 1, 2045.
8    (k) All EGUs and large greenhouse gas-emitting units that 
9utilize combined heat and power or cogeneration technology 
10shall permanently reduce all CO2e and copollutant emissions to 
11zero, including through unit retirement or the use of 100% 
12green hydrogen or other similar technology that is 
13commercially proven to achieve zero carbon emissions by 
14January 1, 2045.
15    (k-5) No EGU or large greenhouse gas-emitting unit that 
16uses gas as a fuel and is not a public GHG-emitting unit may 
17emit, in any 12-month period, CO2e or copollutants in excess of 
18that unit's existing emissions for those pollutants. 
19    (l) Notwithstanding subsections (g) through (k-5), large 
20GHG-emitting units including EGUs may temporarily continue 
21emitting CO2e and copollutants after any applicable deadline 
22specified in any of subsections (g) through (k-5) if it has 
23been determined, as described in paragraphs (1) and (2) of 
24this subsection, that ongoing operation of the EGU is 
25necessary to maintain power grid supply and reliability or 
26ongoing operation of large GHG-emitting unit that is not an 
 
 
10400SB0025ham003- 872 -LRB104 07069 AAS 29208 a

1EGU is necessary to serve as an emergency backup to 
2operations. Up to and including the occurrence of an emission 
3reduction deadline under subsection (i), all EGUs and large 
4GHG-emitting units must comply with the following terms:
5        (1) if an EGU or large GHG-emitting unit that is a 
6    participant in a regional transmission organization 
7    intends to retire, it must submit documentation to the 
8    appropriate regional transmission organization by the 
9    appropriate deadline that meets all applicable regulatory 
10    requirements necessary to obtain approval to permanently 
11    cease operating the large GHG-emitting unit;
12        (2) if any EGU or large GHG-emitting unit that is a 
13    participant in a regional transmission organization 
14    receives notice that the regional transmission 
15    organization has determined that continued operation of 
16    the unit is required, the unit may continue operating 
17    until the issue identified by the regional transmission 
18    organization is resolved. The owner or operator of the 
19    unit must cooperate with the regional transmission 
20    organization in resolving the issue and must reduce its 
21    emissions to zero, consistent with the requirements under 
22    subsection (g), (h), (i), (j), (k), or (k-5), as 
23    applicable, as soon as practicable when the issue 
24    identified by the regional transmission organization is 
25    resolved; and
26        (3) any large GHG-emitting unit that is not a 
 
 
10400SB0025ham003- 873 -LRB104 07069 AAS 29208 a

1    participant in a regional transmission organization shall 
2    be allowed to continue emitting CO2e and copollutants 
3    after the zero-emission date specified in subsection (g), 
4    (h), (i), (j), (k), or (k-5), as applicable, in the 
5    capacity of an emergency backup unit if approved by the 
6    Illinois Commerce Commission.
7    (m) No variance, adjusted standard, or other regulatory 
8relief otherwise available in this Act may be granted to the 
9emissions reduction and elimination obligations in this 
10Section.
11    (n) By June 30 of each year, beginning in 2025, the Agency 
12shall prepare and publish on its website a report setting 
13forth the actual greenhouse gas emissions from individual 
14units and the aggregate statewide emissions from all units for 
15the prior year.
16    (o) The Every 5 years beginning in 2025, the Environmental 
17Protection Agency, Illinois Power Agency, and Illinois 
18Commerce Commission shall jointly prepare, and release 
19publicly, a report to the General Assembly that examines the 
20State's current progress toward its renewable energy resource 
21development goals, the status of CO2e and copollutant 
22emissions reductions, the current status and progress toward 
23developing and implementing green hydrogen technologies, the 
24current and projected status of electric resource adequacy and 
25reliability throughout the State for the period beginning 5 
26years ahead, and proposed solutions for any findings. The 
 
 
10400SB0025ham003- 874 -LRB104 07069 AAS 29208 a

1Environmental Protection Agency, Illinois Power Agency, and 
2Illinois Commerce Commission shall consult PJM 
3Interconnection, LLC and Midcontinent Independent System 
4Operator, Inc., or their respective successor organizations 
5regarding forecasted resource adequacy and reliability needs, 
6anticipated new generation interconnection, new transmission 
7development or upgrades, and any announced large GHG-emitting 
8unit closure dates and include this information in the report. 
9The report shall be released publicly by no later than 
10December 15, 2025 or the effective date of this amendatory Act 
11of the 104th General Assembly, whichever is later of the year 
12it is prepared. If the Environmental Protection Agency, 
13Illinois Power Agency, and Illinois Commerce Commission 
14jointly conclude in the report that the data from the regional 
15grid operators, the pace of renewable energy development, the 
16pace of development of energy storage and demand response 
17utilization, transmission capacity, and the CO2e and 
18copollutant emissions reductions required by subsection (i) or 
19(k-5) reasonably demonstrate that a resource adequacy 
20shortfall will occur, including whether there will be 
21sufficient in-state capacity to meet the zonal requirements of 
22MISO Zone 4 or the PJM ComEd Zone, per the requirements of the 
23regional transmission organizations, or that the regional 
24transmission operators determine that a reliability violation 
25will occur during the time frame the study is evaluating, then 
26the Illinois Power Agency, in conjunction with the 
 
 
10400SB0025ham003- 875 -LRB104 07069 AAS 29208 a

1Environmental Protection Agency shall develop a plan to reduce 
2or delay CO2e and copollutant emissions reductions 
3requirements only to the extent and for the duration necessary 
4to meet the resource adequacy and reliability needs of the 
5State, including allowing any plants whose emission reduction 
6deadline has been identified in the plan as creating a 
7reliability concern to continue operating, including operating 
8with reduced emissions or as emergency backup where 
9appropriate. The plan shall also consider the use of renewable 
10energy, energy storage, demand response, transmission 
11development, or other strategies to resolve the identified 
12resource adequacy shortfall or reliability violation.
13        (1) In developing the plan, the Environmental 
14    Protection Agency and the Illinois Power Agency shall hold 
15    at least one workshop open to, and accessible at a time and 
16    place convenient to, the public and shall consider any 
17    comments made by stakeholders or the public. Upon 
18    development of the plan, copies of the plan shall be 
19    posted and made publicly available on the Environmental 
20    Protection Agency's, the Illinois Power Agency's, and the 
21    Illinois Commerce Commission's websites. All interested 
22    parties shall have 60 days following the date of posting 
23    to provide comment to the Environmental Protection Agency 
24    and the Illinois Power Agency on the plan. All comments 
25    submitted to the Environmental Protection Agency and the 
26    Illinois Power Agency shall be encouraged to be specific, 
 
 
10400SB0025ham003- 876 -LRB104 07069 AAS 29208 a

1    supported by data or other detailed analyses, and, if 
2    objecting to all or a portion of the plan, accompanied by 
3    specific alternative wording or proposals. All comments 
4    shall be posted on the Environmental Protection Agency's, 
5    the Illinois Power Agency's, and the Illinois Commerce 
6    Commission's websites. Within 30 days following the end of 
7    the 60-day review period, the Environmental Protection 
8    Agency and the Illinois Power Agency shall revise the plan 
9    as necessary based on the comments received and file its 
10    revised plan with the Illinois Commerce Commission for 
11    approval.
12        (2) Within 60 days after the filing of the revised 
13    plan at the Illinois Commerce Commission, any person 
14    objecting to the plan shall file an objection with the 
15    Illinois Commerce Commission. Within 30 days after the 
16    expiration of the comment period, the Illinois Commerce 
17    Commission shall determine whether an evidentiary hearing 
18    is necessary. The Illinois Commerce Commission shall also 
19    host 3 public hearings within 90 days after the plan is 
20    filed. Following the evidentiary and public hearings, the 
21    Illinois Commerce Commission shall enter its order 
22    approving or approving with modifications the reliability 
23    mitigation plan within 180 days.
24        (3) The Illinois Commerce Commission shall only 
25    approve the plan if the Illinois Commerce Commission 
26    determines that it will resolve the resource adequacy or 
 
 
10400SB0025ham003- 877 -LRB104 07069 AAS 29208 a

1    reliability deficiency identified in the reliability 
2    mitigation plan at the least amount of CO2e and copollutant 
3    emissions, taking into consideration the emissions impacts 
4    on environmental justice communities, and that it will 
5    ensure adequate, reliable, affordable, efficient, and 
6    environmentally sustainable electric service at the lowest 
7    total cost over time, taking into account the impact of 
8    increases in emissions.
9        (4) If the resource adequacy or reliability deficiency 
10    identified in the reliability mitigation plan is resolved 
11    or reduced, the Environmental Protection Agency and the 
12    Illinois Power Agency may file an amended plan adjusting 
13    the reduction or delay in CO2e and copollutant emission 
14    reduction requirements identified in the plan. 
15(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
 
16    (415 ILCS 5/39)  (from Ch. 111 1/2, par. 1039)
17    Sec. 39. Issuance of permits; procedures. 
18    (a) When the Board has by regulation required a permit for 
19the construction, installation, or operation of any type of 
20facility, equipment, vehicle, vessel, or aircraft, the 
21applicant shall apply to the Agency for such permit and it 
22shall be the duty of the Agency to issue such a permit upon 
23proof by the applicant that the facility, equipment, vehicle, 
24vessel, or aircraft will not cause a violation of this Act or 
25of regulations hereunder. The Agency shall adopt such 
 
 
10400SB0025ham003- 878 -LRB104 07069 AAS 29208 a

1procedures as are necessary to carry out its duties under this 
2Section. In making its determinations on permit applications 
3under this Section the Agency may consider prior adjudications 
4of noncompliance with this Act by the applicant that involved 
5a release of a contaminant into the environment. In granting 
6permits, the Agency may impose reasonable conditions 
7specifically related to the applicant's past compliance 
8history with this Act as necessary to correct, detect, or 
9prevent noncompliance. The Agency may impose such other 
10conditions as may be necessary to accomplish the purposes of 
11this Act, and as are not inconsistent with the regulations 
12promulgated by the Board hereunder. Except as otherwise 
13provided in this Act, a bond or other security shall not be 
14required as a condition for the issuance of a permit. If the 
15Agency denies any permit under this Section, the Agency shall 
16transmit to the applicant within the time limitations of this 
17Section specific, detailed statements as to the reasons the 
18permit application was denied. Such statements shall include, 
19but not be limited to, the following:
20        (i) the Sections of this Act which may be violated if 
21    the permit were granted;
22        (ii) the provision of the regulations, promulgated 
23    under this Act, which may be violated if the permit were 
24    granted;
25        (iii) the specific type of information, if any, which 
26    the Agency deems the applicant did not provide the Agency; 
 
 
10400SB0025ham003- 879 -LRB104 07069 AAS 29208 a

1    and
2        (iv) a statement of specific reasons why the Act and 
3    the regulations might not be met if the permit were 
4    granted.
5    If there is no final action by the Agency within 90 days 
6after the filing of the application for permit, the applicant 
7may deem the permit issued; except that this time period shall 
8be extended to 180 days when (1) notice and opportunity for 
9public hearing are required by State or federal law or 
10regulation, (2) the application which was filed is for any 
11permit to develop a landfill subject to issuance pursuant to 
12this subsection, or (3) the application that was filed is for a 
13MSWLF unit required to issue public notice under subsection 
14(p) of Section 39. The 90-day and 180-day time periods for the 
15Agency to take final action do not apply to NPDES permit 
16applications under subsection (b) of this Section, to RCRA 
17permit applications under subsection (d) of this Section, to 
18UIC permit applications under subsection (e) of this Section, 
19or to CCR surface impoundment applications under subsection 
20(y) of this Section.
21    The Agency shall publish notice of all final permit 
22determinations for development permits for MSWLF units and for 
23significant permit modifications for lateral expansions for 
24existing MSWLF units one time in a newspaper of general 
25circulation in the county in which the unit is or is proposed 
26to be located.
 
 
10400SB0025ham003- 880 -LRB104 07069 AAS 29208 a

1    After January 1, 1994 and until July 1, 1998, operating 
2permits issued under this Section by the Agency for sources of 
3air pollution permitted to emit less than 25 tons per year of 
4any combination of regulated air pollutants, as defined in 
5Section 39.5 of this Act, shall be required to be renewed only 
6upon written request by the Agency consistent with applicable 
7provisions of this Act and regulations promulgated hereunder. 
8Such operating permits shall expire 180 days after the date of 
9such a request. The Board shall revise its regulations for the 
10existing State air pollution operating permit program 
11consistent with this provision by January 1, 1994.
12    After June 30, 1998, operating permits issued under this 
13Section by the Agency for sources of air pollution that are not 
14subject to Section 39.5 of this Act and are not required to 
15have a federally enforceable State operating permit shall be 
16required to be renewed only upon written request by the Agency 
17consistent with applicable provisions of this Act and its 
18rules. Such operating permits shall expire 180 days after the 
19date of such a request. Before July 1, 1998, the Board shall 
20revise its rules for the existing State air pollution 
21operating permit program consistent with this paragraph and 
22shall adopt rules that require a source to demonstrate that it 
23qualifies for a permit under this paragraph.
24    Each air pollution construction permit for fossil 
25fuel-fired power backup generators to a source that is a data 
26center, as defined in subsection (c) of Section 605-1025 of 
 
 
10400SB0025ham003- 881 -LRB104 07069 AAS 29208 a

1the Department of Commerce and Economic Opportunity Law of the 
2Civil Administrative Code of Illinois, that is applied for 6 
3months after the effective date of this amendatory Act of the 
4104th General Assembly and that is required to have a 
5federally enforceable State operating permit or a Clean Air 
6Act Permit Program permit shall, in addition to any other 
7applicable requirements, require each generator to: (i) meet 
8standards at least as protective as Tier 4 standards for 
9non-road diesel engines set out by the United States 
10Environmental Protection Agency in 40 CFR 1039, as it exists 
11on the effective date of this amendatory Act of the 104th 
12General Assembly; and (ii) operate solely as an emergency or 
13standby unit in accordance with 35 Ill. Adm. Code 211.1920, as 
14it exists on the effective date of this amendatory Act of the 
15104th General Assembly.    
16    (b) The Agency may issue NPDES permits exclusively under 
17this subsection for the discharge of contaminants from point 
18sources into navigable waters, all as defined in the Federal 
19Water Pollution Control Act, as now or hereafter amended, 
20within the jurisdiction of the State, or into any well.
21    All NPDES permits shall contain those terms and 
22conditions, including, but not limited to, schedules of 
23compliance, which may be required to accomplish the purposes 
24and provisions of this Act.
25    The Agency may issue general NPDES permits for discharges 
26from categories of point sources which are subject to the same 
 
 
10400SB0025ham003- 882 -LRB104 07069 AAS 29208 a

1permit limitations and conditions. Such general permits may be 
2issued without individual applications and shall conform to 
3regulations promulgated under Section 402 of the Federal Water 
4Pollution Control Act, as now or hereafter amended.
5    The Agency may include, among such conditions, effluent 
6limitations and other requirements established under this Act, 
7Board regulations, the Federal Water Pollution Control Act, as 
8now or hereafter amended, and regulations pursuant thereto, 
9and schedules for achieving compliance therewith at the 
10earliest reasonable date.
11    The Agency shall adopt filing requirements and procedures 
12which are necessary and appropriate for the issuance of NPDES 
13permits, and which are consistent with the Act or regulations 
14adopted by the Board, and with the Federal Water Pollution 
15Control Act, as now or hereafter amended, and regulations 
16pursuant thereto.
17    The Agency, subject to any conditions which may be 
18prescribed by Board regulations, may issue NPDES permits to 
19allow discharges beyond deadlines established by this Act or 
20by regulations of the Board without the requirement of a 
21variance, subject to the Federal Water Pollution Control Act, 
22as now or hereafter amended, and regulations pursuant thereto.
23    (c) Except for those facilities owned or operated by 
24sanitary districts organized under the Metropolitan Water 
25Reclamation District Act, no permit for the development or 
26construction of a new pollution control facility may be 
 
 
10400SB0025ham003- 883 -LRB104 07069 AAS 29208 a

1granted by the Agency unless the applicant submits proof to 
2the Agency that the location of the facility has been approved 
3by the county board of the county if in an unincorporated area, 
4or the governing body of the municipality when in an 
5incorporated area, in which the facility is to be located in 
6accordance with Section 39.2 of this Act. For purposes of this 
7subsection (c), and for purposes of Section 39.2 of this Act, 
8the appropriate county board or governing body of the 
9municipality shall be the county board of the county or the 
10governing body of the municipality in which the facility is to 
11be located as of the date when the application for siting 
12approval is filed. 
13    In the event that siting approval granted pursuant to 
14Section 39.2 has been transferred to a subsequent owner or 
15operator, that subsequent owner or operator may apply to the 
16Agency for, and the Agency may grant, a development or 
17construction permit for the facility for which local siting 
18approval was granted. Upon application to the Agency for a 
19development or construction permit by that subsequent owner or 
20operator, the permit applicant shall cause written notice of 
21the permit application to be served upon the appropriate 
22county board or governing body of the municipality that 
23granted siting approval for that facility and upon any party 
24to the siting proceeding pursuant to which siting approval was 
25granted. In that event, the Agency shall conduct an evaluation 
26of the subsequent owner or operator's prior experience in 
 
 
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1waste management operations in the manner conducted under 
2subsection (i) of Section 39 of this Act.
3    Beginning August 20, 1993, if the pollution control 
4facility consists of a hazardous or solid waste disposal 
5facility for which the proposed site is located in an 
6unincorporated area of a county with a population of less than 
7100,000 and includes all or a portion of a parcel of land that 
8was, on April 1, 1993, adjacent to a municipality having a 
9population of less than 5,000, then the local siting review 
10required under this subsection (c) in conjunction with any 
11permit applied for after that date shall be performed by the 
12governing body of that adjacent municipality rather than the 
13county board of the county in which the proposed site is 
14located; and for the purposes of that local siting review, any 
15references in this Act to the county board shall be deemed to 
16mean the governing body of that adjacent municipality; 
17provided, however, that the provisions of this paragraph shall 
18not apply to any proposed site which was, on April 1, 1993, 
19owned in whole or in part by another municipality.
20    In the case of a pollution control facility for which a 
21development permit was issued before November 12, 1981, if an 
22operating permit has not been issued by the Agency prior to 
23August 31, 1989 for any portion of the facility, then the 
24Agency may not issue or renew any development permit nor issue 
25an original operating permit for any portion of such facility 
26unless the applicant has submitted proof to the Agency that 
 
 
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1the location of the facility has been approved by the 
2appropriate county board or municipal governing body pursuant 
3to Section 39.2 of this Act.
4    After January 1, 1994, if a solid waste disposal facility, 
5any portion for which an operating permit has been issued by 
6the Agency, has not accepted waste disposal for 5 or more 
7consecutive calendar years, before that facility may accept 
8any new or additional waste for disposal, the owner and 
9operator must obtain a new operating permit under this Act for 
10that facility unless the owner and operator have applied to 
11the Agency for a permit authorizing the temporary suspension 
12of waste acceptance. The Agency may not issue a new operation 
13permit under this Act for the facility unless the applicant 
14has submitted proof to the Agency that the location of the 
15facility has been approved or re-approved by the appropriate 
16county board or municipal governing body under Section 39.2 of 
17this Act after the facility ceased accepting waste.
18    Except for those facilities owned or operated by sanitary 
19districts organized under the Metropolitan Water Reclamation 
20District Act, and except for new pollution control facilities 
21governed by Section 39.2, and except for fossil fuel mining 
22facilities, the granting of a permit under this Act shall not 
23relieve the applicant from meeting and securing all necessary 
24zoning approvals from the unit of government having zoning 
25jurisdiction over the proposed facility.
26    Before beginning construction on any new sewage treatment 
 
 
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1plant or sludge drying site to be owned or operated by a 
2sanitary district organized under the Metropolitan Water 
3Reclamation District Act for which a new permit (rather than 
4the renewal or amendment of an existing permit) is required, 
5such sanitary district shall hold a public hearing within the 
6municipality within which the proposed facility is to be 
7located, or within the nearest community if the proposed 
8facility is to be located within an unincorporated area, at 
9which information concerning the proposed facility shall be 
10made available to the public, and members of the public shall 
11be given the opportunity to express their views concerning the 
12proposed facility.
13    The Agency may issue a permit for a municipal waste 
14transfer station without requiring approval pursuant to 
15Section 39.2 provided that the following demonstration is 
16made:
17        (1) the municipal waste transfer station was in 
18    existence on or before January 1, 1979 and was in 
19    continuous operation from January 1, 1979 to January 1, 
20    1993;
21        (2) the operator submitted a permit application to the 
22    Agency to develop and operate the municipal waste transfer 
23    station during April of 1994;
24        (3) the operator can demonstrate that the county board 
25    of the county, if the municipal waste transfer station is 
26    in an unincorporated area, or the governing body of the 
 
 
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1    municipality, if the station is in an incorporated area, 
2    does not object to resumption of the operation of the 
3    station; and
4        (4) the site has local zoning approval.
5    (d) The Agency may issue RCRA permits exclusively under 
6this subsection to persons owning or operating a facility for 
7the treatment, storage, or disposal of hazardous waste as 
8defined under this Act. Subsection (y) of this Section, rather 
9than this subsection (d), shall apply to permits issued for 
10CCR surface impoundments. 
11    All RCRA permits shall contain those terms and conditions, 
12including, but not limited to, schedules of compliance, which 
13may be required to accomplish the purposes and provisions of 
14this Act. The Agency may include among such conditions 
15standards and other requirements established under this Act, 
16Board regulations, the Resource Conservation and Recovery Act 
17of 1976 (P.L. 94-580), as amended, and regulations pursuant 
18thereto, and may include schedules for achieving compliance 
19therewith as soon as possible. The Agency shall require that a 
20performance bond or other security be provided as a condition 
21for the issuance of a RCRA permit.
22    In the case of a permit to operate a hazardous waste or PCB 
23incinerator as defined in subsection (k) of Section 44, the 
24Agency shall require, as a condition of the permit, that the 
25operator of the facility perform such analyses of the waste to 
26be incinerated as may be necessary and appropriate to ensure 
 
 
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1the safe operation of the incinerator.
2    The Agency shall adopt filing requirements and procedures 
3which are necessary and appropriate for the issuance of RCRA 
4permits, and which are consistent with the Act or regulations 
5adopted by the Board, and with the Resource Conservation and 
6Recovery Act of 1976 (P.L. 94-580), as amended, and 
7regulations pursuant thereto.
8    The applicant shall make available to the public for 
9inspection all documents submitted by the applicant to the 
10Agency in furtherance of an application, with the exception of 
11trade secrets, at the office of the county board or governing 
12body of the municipality. Such documents may be copied upon 
13payment of the actual cost of reproduction during regular 
14business hours of the local office. The Agency shall issue a 
15written statement concurrent with its grant or denial of the 
16permit explaining the basis for its decision.
17    (e) The Agency may issue UIC permits exclusively under 
18this subsection to persons owning or operating a facility for 
19the underground injection of contaminants as defined under 
20this Act.
21    All UIC permits shall contain those terms and conditions, 
22including, but not limited to, schedules of compliance, which 
23may be required to accomplish the purposes and provisions of 
24this Act. The Agency may include among such conditions 
25standards and other requirements established under this Act, 
26Board regulations, the Safe Drinking Water Act (P.L. 93-523), 
 
 
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1as amended, and regulations pursuant thereto, and may include 
2schedules for achieving compliance therewith. The Agency shall 
3require that a performance bond or other security be provided 
4as a condition for the issuance of a UIC permit.
5    The Agency shall adopt filing requirements and procedures 
6which are necessary and appropriate for the issuance of UIC 
7permits, and which are consistent with the Act or regulations 
8adopted by the Board, and with the Safe Drinking Water Act 
9(P.L. 93-523), as amended, and regulations pursuant thereto.
10    The applicant shall make available to the public for 
11inspection all documents submitted by the applicant to the 
12Agency in furtherance of an application, with the exception of 
13trade secrets, at the office of the county board or governing 
14body of the municipality. Such documents may be copied upon 
15payment of the actual cost of reproduction during regular 
16business hours of the local office. The Agency shall issue a 
17written statement concurrent with its grant or denial of the 
18permit explaining the basis for its decision.
19    (f) In making any determination pursuant to Section 9.1 of 
20this Act:
21        (1) The Agency shall have authority to make the 
22    determination of any question required to be determined by 
23    the Clean Air Act, as now or hereafter amended, this Act, 
24    or the regulations of the Board, including the 
25    determination of the Lowest Achievable Emission Rate, 
26    Maximum Achievable Control Technology, or Best Available 
 
 
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1    Control Technology, consistent with the Board's 
2    regulations, if any.
3        (2) The Agency shall adopt requirements as necessary 
4    to implement public participation procedures, including, 
5    but not limited to, public notice, comment, and an 
6    opportunity for hearing, which must accompany the 
7    processing of applications for PSD permits. The Agency 
8    shall briefly describe and respond to all significant 
9    comments on the draft permit raised during the public 
10    comment period or during any hearing. The Agency may group 
11    related comments together and provide one unified response 
12    for each issue raised.
13        (3) Any complete permit application submitted to the 
14    Agency under this subsection for a PSD permit shall be 
15    granted or denied by the Agency not later than one year 
16    after the filing of such completed application. 
17        (4) The Agency shall, after conferring with the 
18    applicant, give written notice to the applicant of its 
19    proposed decision on the application, including the terms 
20    and conditions of the permit to be issued and the facts, 
21    conduct, or other basis upon which the Agency will rely to 
22    support its proposed action.
23    (g) The Agency shall include as conditions upon all 
24permits issued for hazardous waste disposal sites such 
25restrictions upon the future use of such sites as are 
26reasonably necessary to protect public health and the 
 
 
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1environment, including permanent prohibition of the use of 
2such sites for purposes which may create an unreasonable risk 
3of injury to human health or to the environment. After 
4administrative and judicial challenges to such restrictions 
5have been exhausted, the Agency shall file such restrictions 
6of record in the Office of the Recorder of the county in which 
7the hazardous waste disposal site is located.
8    (h) A hazardous waste stream may not be deposited in a 
9permitted hazardous waste site unless specific authorization 
10is obtained from the Agency by the generator and disposal site 
11owner and operator for the deposit of that specific hazardous 
12waste stream. The Agency may grant specific authorization for 
13disposal of hazardous waste streams only after the generator 
14has reasonably demonstrated that, considering technological 
15feasibility and economic reasonableness, the hazardous waste 
16cannot be reasonably recycled for reuse, nor incinerated or 
17chemically, physically, or biologically treated so as to 
18neutralize the hazardous waste and render it nonhazardous. In 
19granting authorization under this Section, the Agency may 
20impose such conditions as may be necessary to accomplish the 
21purposes of the Act and are consistent with this Act and 
22regulations promulgated by the Board hereunder. If the Agency 
23refuses to grant authorization under this Section, the 
24applicant may appeal as if the Agency refused to grant a 
25permit, pursuant to the provisions of subsection (a) of 
26Section 40 of this Act. For purposes of this subsection (h), 
 
 
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1the term "generator" has the meaning given in Section 3.205 of 
2this Act, unless: (1) the hazardous waste is treated, 
3incinerated, or partially recycled for reuse prior to 
4disposal, in which case the last person who treats, 
5incinerates, or partially recycles the hazardous waste prior 
6to disposal is the generator; or (2) the hazardous waste is 
7from a response action, in which case the person performing 
8the response action is the generator. This subsection (h) does 
9not apply to any hazardous waste that is restricted from land 
10disposal under 35 Ill. Adm. Code 728.
11    (i) Before issuing any RCRA permit, any permit for a waste 
12storage site, sanitary landfill, waste disposal site, waste 
13transfer station, waste treatment facility, waste incinerator, 
14or any waste-transportation operation, any permit or interim 
15authorization for a clean construction or demolition debris 
16fill operation, or any permit required under subsection (d-5) 
17of Section 55, the Agency shall conduct an evaluation of the 
18prospective owner's or operator's prior experience in waste 
19management operations, clean construction or demolition debris 
20fill operations, and tire storage site management. The Agency 
21may deny such a permit, or deny or revoke interim 
22authorization, if the prospective owner or operator or any 
23employee or officer of the prospective owner or operator has a 
24history of:
25        (1) repeated violations of federal, State, or local 
26    laws, regulations, standards, or ordinances in the 
 
 
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1    operation of waste management facilities or sites, clean 
2    construction or demolition debris fill operation 
3    facilities or sites, or tire storage sites; or
4        (2) conviction in this or another State of any crime 
5    which is a felony under the laws of this State, or 
6    conviction of a felony in a federal court; or conviction 
7    in this or another state or federal court of any of the 
8    following crimes: forgery, official misconduct, bribery, 
9    perjury, or knowingly submitting false information under 
10    any environmental law, regulation, or permit term or 
11    condition; or
12        (3) proof of gross carelessness or incompetence in 
13    handling, storing, processing, transporting, or disposing 
14    of waste, clean construction or demolition debris, or used 
15    or waste tires, or proof of gross carelessness or 
16    incompetence in using clean construction or demolition 
17    debris as fill.
18    (i-5) Before issuing any permit or approving any interim 
19authorization for a clean construction or demolition debris 
20fill operation in which any ownership interest is transferred 
21between January 1, 2005, and the effective date of the 
22prohibition set forth in Section 22.52 of this Act, the Agency 
23shall conduct an evaluation of the operation if any previous 
24activities at the site or facility may have caused or allowed 
25contamination of the site. It shall be the responsibility of 
26the owner or operator seeking the permit or interim 
 
 
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1authorization to provide to the Agency all of the information 
2necessary for the Agency to conduct its evaluation. The Agency 
3may deny a permit or interim authorization if previous 
4activities at the site may have caused or allowed 
5contamination at the site, unless such contamination is 
6authorized under any permit issued by the Agency. 
7    (j) The issuance under this Act of a permit to engage in 
8the surface mining of any resources other than fossil fuels 
9shall not relieve the permittee from its duty to comply with 
10any applicable local law regulating the commencement, 
11location, or operation of surface mining facilities.
12    (k) A development permit issued under subsection (a) of 
13Section 39 for any facility or site which is required to have a 
14permit under subsection (d) of Section 21 shall expire at the 
15end of 2 calendar years from the date upon which it was issued, 
16unless within that period the applicant has taken action to 
17develop the facility or the site. In the event that review of 
18the conditions of the development permit is sought pursuant to 
19Section 40 or 41, or permittee is prevented from commencing 
20development of the facility or site by any other litigation 
21beyond the permittee's control, such two-year period shall be 
22deemed to begin on the date upon which such review process or 
23litigation is concluded.
24    (l) No permit shall be issued by the Agency under this Act 
25for construction or operation of any facility or site located 
26within the boundaries of any setback zone established pursuant 
 
 
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1to this Act, where such construction or operation is 
2prohibited.
3    (m) The Agency may issue permits to persons owning or 
4operating a facility for composting landscape waste. In 
5granting such permits, the Agency may impose such conditions 
6as may be necessary to accomplish the purposes of this Act, and 
7as are not inconsistent with applicable regulations 
8promulgated by the Board. Except as otherwise provided in this 
9Act, a bond or other security shall not be required as a 
10condition for the issuance of a permit. If the Agency denies 
11any permit pursuant to this subsection, the Agency shall 
12transmit to the applicant within the time limitations of this 
13subsection specific, detailed statements as to the reasons the 
14permit application was denied. Such statements shall include 
15but not be limited to the following:
16        (1) the Sections of this Act that may be violated if 
17    the permit were granted;
18        (2) the specific regulations promulgated pursuant to 
19    this Act that may be violated if the permit were granted;
20        (3) the specific information, if any, the Agency deems 
21    the applicant did not provide in its application to the 
22    Agency; and
23        (4) a statement of specific reasons why the Act and 
24    the regulations might be violated if the permit were 
25    granted.
26    If no final action is taken by the Agency within 90 days 
 
 
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1after the filing of the application for permit, the applicant 
2may deem the permit issued. Any applicant for a permit may 
3waive the 90-day limitation by filing a written statement with 
4the Agency.
5    The Agency shall issue permits for such facilities upon 
6receipt of an application that includes a legal description of 
7the site, a topographic map of the site drawn to the scale of 
8200 feet to the inch or larger, a description of the operation, 
9including the area served, an estimate of the volume of 
10materials to be processed, and documentation that:
11        (1) the facility includes a setback of at least 200 
12    feet from the nearest potable water supply well;
13        (2) the facility is located outside the boundary of 
14    the 10-year floodplain or the site will be floodproofed;
15        (3) the facility is located so as to minimize 
16    incompatibility with the character of the surrounding 
17    area, including at least a 200 foot setback from any 
18    residence, and in the case of a facility that is developed 
19    or the permitted composting area of which is expanded 
20    after November 17, 1991, the composting area is located at 
21    least 1/8 mile from the nearest residence (other than a 
22    residence located on the same property as the facility);
23        (4) the design of the facility will prevent any 
24    compost material from being placed within 5 feet of the 
25    water table, will adequately control runoff from the site, 
26    and will collect and manage any leachate that is generated 
 
 
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1    on the site;
2        (5) the operation of the facility will include 
3    appropriate dust and odor control measures, limitations on 
4    operating hours, appropriate noise control measures for 
5    shredding, chipping and similar equipment, management 
6    procedures for composting, containment and disposal of 
7    non-compostable wastes, procedures to be used for 
8    terminating operations at the site, and recordkeeping 
9    sufficient to document the amount of materials received, 
10    composted, and otherwise disposed of; and
11        (6) the operation will be conducted in accordance with 
12    any applicable rules adopted by the Board.
13    The Agency shall issue renewable permits of not longer 
14than 10 years in duration for the composting of landscape 
15wastes, as defined in Section 3.155 of this Act, based on the 
16above requirements.
17    The operator of any facility permitted under this 
18subsection (m) must submit a written annual statement to the 
19Agency on or before April 1 of each year that includes an 
20estimate of the amount of material, in tons, received for 
21composting.
22    (n) The Agency shall issue permits jointly with the 
23Department of Transportation for the dredging or deposit of 
24material in Lake Michigan in accordance with Section 18 of the 
25Rivers, Lakes, and Streams Act.
26    (o) (Blank).
 
 
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1    (p) (1) Any person submitting an application for a permit 
2for a new MSWLF unit or for a lateral expansion under 
3subsection (t) of Section 21 of this Act for an existing MSWLF 
4unit that has not received and is not subject to local siting 
5approval under Section 39.2 of this Act shall publish notice 
6of the application in a newspaper of general circulation in 
7the county in which the MSWLF unit is or is proposed to be 
8located. The notice must be published at least 15 days before 
9submission of the permit application to the Agency. The notice 
10shall state the name and address of the applicant, the 
11location of the MSWLF unit or proposed MSWLF unit, the nature 
12and size of the MSWLF unit or proposed MSWLF unit, the nature 
13of the activity proposed, the probable life of the proposed 
14activity, the date the permit application will be submitted, 
15and a statement that persons may file written comments with 
16the Agency concerning the permit application within 30 days 
17after the filing of the permit application unless the time 
18period to submit comments is extended by the Agency.
19    When a permit applicant submits information to the Agency 
20to supplement a permit application being reviewed by the 
21Agency, the applicant shall not be required to reissue the 
22notice under this subsection.
23    (2) The Agency shall accept written comments concerning 
24the permit application that are postmarked no later than 30 
25days after the filing of the permit application, unless the 
26time period to accept comments is extended by the Agency.
 
 
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1    (3) Each applicant for a permit described in part (1) of 
2this subsection shall file a copy of the permit application 
3with the county board or governing body of the municipality in 
4which the MSWLF unit is or is proposed to be located at the 
5same time the application is submitted to the Agency. The 
6permit application filed with the county board or governing 
7body of the municipality shall include all documents submitted 
8to or to be submitted to the Agency, except trade secrets as 
9determined under Section 7.1 of this Act. The permit 
10application and other documents on file with the county board 
11or governing body of the municipality shall be made available 
12for public inspection during regular business hours at the 
13office of the county board or the governing body of the 
14municipality and may be copied upon payment of the actual cost 
15of reproduction.
16    (q) Within 6 months after July 12, 2011 (the effective 
17date of Public Act 97-95), the Agency, in consultation with 
18the regulated community, shall develop a web portal to be 
19posted on its website for the purpose of enhancing review and 
20promoting timely issuance of permits required by this Act. At 
21a minimum, the Agency shall make the following information 
22available on the web portal:
23        (1) Checklists and guidance relating to the completion 
24    of permit applications, developed pursuant to subsection 
25    (s) of this Section, which may include, but are not 
26    limited to, existing instructions for completing the 
 
 
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1    applications and examples of complete applications. As the 
2    Agency develops new checklists and develops guidance, it 
3    shall supplement the web portal with those materials.
4        (2) Within 2 years after July 12, 2011 (the effective 
5    date of Public Act 97-95), permit application forms or 
6    portions of permit applications that can be completed and 
7    saved electronically, and submitted to the Agency 
8    electronically with digital signatures.
9        (3) Within 2 years after July 12, 2011 (the effective 
10    date of Public Act 97-95), an online tracking system where 
11    an applicant may review the status of its pending 
12    application, including the name and contact information of 
13    the permit analyst assigned to the application. Until the 
14    online tracking system has been developed, the Agency 
15    shall post on its website semi-annual permitting 
16    efficiency tracking reports that include statistics on the 
17    timeframes for Agency action on the following types of 
18    permits received after July 12, 2011 (the effective date 
19    of Public Act 97-95): air construction permits, new NPDES 
20    permits and associated water construction permits, and 
21    modifications of major NPDES permits and associated water 
22    construction permits. The reports must be posted by 
23    February 1 and August 1 each year and shall include:
24            (A) the number of applications received for each 
25        type of permit, the number of applications on which 
26        the Agency has taken action, and the number of 
 
 
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1        applications still pending; and
2            (B) for those applications where the Agency has 
3        not taken action in accordance with the timeframes set 
4        forth in this Act, the date the application was 
5        received and the reasons for any delays, which may 
6        include, but shall not be limited to, (i) the 
7        application being inadequate or incomplete, (ii) 
8        scientific or technical disagreements with the 
9        applicant, USEPA, or other local, state, or federal 
10        agencies involved in the permitting approval process, 
11        (iii) public opposition to the permit, or (iv) Agency 
12        staffing shortages. To the extent practicable, the 
13        tracking report shall provide approximate dates when 
14        cause for delay was identified by the Agency, when the 
15        Agency informed the applicant of the problem leading 
16        to the delay, and when the applicant remedied the 
17        reason for the delay.
18    (r) Upon the request of the applicant, the Agency shall 
19notify the applicant of the permit analyst assigned to the 
20application upon its receipt.
21    (s) The Agency is authorized to prepare and distribute 
22guidance documents relating to its administration of this 
23Section and procedural rules implementing this Section. 
24Guidance documents prepared under this subsection shall not be 
25considered rules and shall not be subject to the Illinois 
26Administrative Procedure Act. Such guidance shall not be 
 
 
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1binding on any party.
2    (t) Except as otherwise prohibited by federal law or 
3regulation, any person submitting an application for a permit 
4may include with the application suggested permit language for 
5Agency consideration. The Agency is not obligated to use the 
6suggested language or any portion thereof in its permitting 
7decision. If requested by the permit applicant, the Agency 
8shall meet with the applicant to discuss the suggested 
9language.
10    (u) If requested by the permit applicant, the Agency shall 
11provide the permit applicant with a copy of the draft permit 
12prior to any public review period.
13    (v) If requested by the permit applicant, the Agency shall 
14provide the permit applicant with a copy of the final permit 
15prior to its issuance. 
16    (w) An air pollution permit shall not be required due to 
17emissions of greenhouse gases, as specified by Section 9.15 of 
18this Act.
19    (x) If, before the expiration of a State operating permit 
20that is issued pursuant to subsection (a) of this Section and 
21contains federally enforceable conditions limiting the 
22potential to emit of the source to a level below the major 
23source threshold for that source so as to exclude the source 
24from the Clean Air Act Permit Program, the Agency receives a 
25complete application for the renewal of that permit, then all 
26of the terms and conditions of the permit shall remain in 
 
 
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1effect until final administrative action has been taken on the 
2application for the renewal of the permit. 
3    (y) The Agency may issue permits exclusively under this 
4subsection to persons owning or operating a CCR surface 
5impoundment subject to Section 22.59.
6    (z) If a mass animal mortality event is declared by the 
7Department of Agriculture in accordance with the Animal 
8Mortality Act:
9        (1) the owner or operator responsible for the disposal 
10    of dead animals is exempted from the following:
11            (i) obtaining a permit for the construction, 
12        installation, or operation of any type of facility or 
13        equipment issued in accordance with subsection (a) of 
14        this Section;
15            (ii) obtaining a permit for open burning in 
16        accordance with the rules adopted by the Board; and
17            (iii) registering the disposal of dead animals as 
18        an eligible small source with the Agency in accordance 
19        with Section 9.14 of this Act; 
20        (2) as applicable, the owner or operator responsible 
21    for the disposal of dead animals is required to obtain the 
22    following permits:
23            (i) an NPDES permit in accordance with subsection 
24        (b) of this Section;
25            (ii) a PSD permit or an NA NSR permit in accordance 
26        with Section 9.1 of this Act;
 
 
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1            (iii) a lifetime State operating permit or a 
2        federally enforceable State operating permit, in 
3        accordance with subsection (a) of this Section; or
4            (iv) a CAAPP permit, in accordance with Section 
5        39.5 of this Act. 
6    All CCR surface impoundment permits shall contain those 
7terms and conditions, including, but not limited to, schedules 
8of compliance, which may be required to accomplish the 
9purposes and provisions of this Act, Board regulations, the 
10Illinois Groundwater Protection Act and regulations pursuant 
11thereto, and the Resource Conservation and Recovery Act and 
12regulations pursuant thereto, and may include schedules for 
13achieving compliance therewith as soon as possible.
14    The Board shall adopt filing requirements and procedures 
15that are necessary and appropriate for the issuance of CCR 
16surface impoundment permits and that are consistent with this 
17Act or regulations adopted by the Board, and with the RCRA, as 
18amended, and regulations pursuant thereto.
19    The applicant shall make available to the public for 
20inspection all documents submitted by the applicant to the 
21Agency in furtherance of an application, with the exception of 
22trade secrets, on its public internet website as well as at the 
23office of the county board or governing body of the 
24municipality where CCR from the CCR surface impoundment will 
25be permanently disposed. Such documents may be copied upon 
26payment of the actual cost of reproduction during regular 
 
 
10400SB0025ham003- 905 -LRB104 07069 AAS 29208 a

1business hours of the local office.
2    The Agency shall issue a written statement concurrent with 
3its grant or denial of the permit explaining the basis for its 
4decision.
5(Source: P.A. 101-171, eff. 7-30-19; 102-216, eff. 1-1-22; 
6102-558, eff. 8-20-21; 102-813, eff. 5-13-22.)
 
7    Section 90-50. The Electric Vehicle Rebate Act is amended 
8by changing Sections 35, 40, and 45 and by adding Section 36 as 
9follows:
 
10    (415 ILCS 120/35)
11    Sec. 35. User fees. 
12    (a) The Office of the Secretary of State shall collect 
13annual user fees from any individual, partnership, 
14association, corporation, or agency of the United States 
15government that registers any combination of 10 or more of the 
16following types of motor vehicles in the Covered Area: (1) 
17vehicles of the First Division, as defined in the Illinois 
18Vehicle Code; (2) vehicles of the Second Division registered 
19under the B, C, D, F, H, MD, MF, MG, MH and MJ plate 
20categories, as defined in the Illinois Vehicle Code; and (3) 
21commuter vans and livery vehicles as defined in the Illinois 
22Vehicle Code. This Section does not apply to vehicles 
23registered under the International Registration Plan under 
24Section 3-402.1 of the Illinois Vehicle Code. The user fee 
 
 
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1shall be $20 for each vehicle registered in the Covered Area 
2for each fiscal year. The Office of the Secretary of State 
3shall collect the $20 when a vehicle's registration fee is 
4paid.
5    (b) Owners of State, county, and local government 
6vehicles, rental vehicles, antique vehicles, expanded-use 
7antique vehicles, electric vehicles, and motorcycles are 
8exempt from paying the user fees on such vehicles.
9    (c) The Office of the Secretary of State shall deposit the 
10user fees collected into the Electric Vehicle and Charging    
11Rebate Fund.
12(Source: P.A. 101-505, eff. 1-1-20; 102-662, eff. 9-15-21.)
 
13    (415 ILCS 120/36 new)
14    Sec. 36. Electric vehicle and charging financial 
15assistance.    
16    (a) Beginning January 1, 2029, the Agency shall administer 
17grants and other forms of financial assistance to support the 
18electrification of the transportation sector, including 
19electric passenger vehicles, electric school buses and 
20electric transit buses, electric medium-duty and heavy-duty 
21trucks, and electric vehicle charging infrastructure. The 
22Agency shall also implement customer education and outreach 
23programs that increase awareness of the programs for and the 
24benefits of transportation electrification. The programs under 
25this Section shall be developed and implemented pursuant to 
 
 
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1the goals outlined in Section 45 of the Electric Vehicle Act.
2    (b) No later than March 1, 2028, and every 3 years 
3thereafter, the Agency shall publish a draft Transportation 
4Electrification Plan that specifies the proposed programs and 
5allocation of funds for the following 3 calendar years. The 
6Agency shall solicit public comments on the design of the Plan 
7and the funding allocations and shall incorporate any public 
8comments into the final Plan. The Plan shall take into 
9consideration lessons learned from the implementation of 
10utility Beneficial Electrification Plans under the Electric 
11Vehicle Act. Within 180 days after the publication of the 
12draft Plan, the Agency shall publish a final Plan.
13    (c) The Agency shall have broad authority to provide 
14grants and other forms of financial assistance to public and 
15private entities under this Section pursuant to the Grant 
16Accountability and Transparency Act. Awardees under this 
17Section shall comply with the requirements of the Prevailing 
18Wage Act for charging station installations. The Agency may 
19provide additional incentives for projects located in eligible 
20communities.
21    (d) Funds shall be made available from the Electric 
22Vehicle and Charging Fund to the Agency pursuant to subsection 
23(c). The annual budget for Agency-administered transportation 
24electrification programs shall be equivalent to the annual 
25budget of programs administered by utilities under the 
26Electric Vehicle Act for the years 2026 through 2028.
 
 
 
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1    (415 ILCS 120/40)
2    Sec. 40. Appropriations from the Electric Vehicle and 
3Charging Rebate Fund.     
4    (a) The Agency shall estimate the amount of user fees 
5expected to be collected under Section 35 of this Act for each 
6fiscal year. User fee funds shall be deposited into and 
7distributed from the Electric Vehicle and Charging Rebate Fund 
8in the following manner:    
9        (1) Through fiscal year 2023, an annual amount not to 
10    exceed $225,000 may be appropriated to the Agency from the 
11    Electric Vehicle and Charging Rebate Fund to pay its costs 
12    of administering the programs authorized by Section 27 of 
13    this Act. Beginning in fiscal year 2024 and in each fiscal 
14    year thereafter, an annual amount not to exceed $600,000 
15    may be appropriated to the Agency from the Electric 
16    Vehicle and Charging Rebate Fund to pay its costs of 
17    administering the programs authorized by Section 27 of 
18    this Act. An amount not to exceed $225,000 may be 
19    appropriated to the Secretary of State from the Electric 
20    Vehicle and Charging Rebate Fund to pay the Secretary of 
21    State's costs of administering the programs authorized 
22    under this Act.    
23        (2) In fiscal year 2022 and each fiscal year 
24    thereafter, after appropriation of the amounts authorized 
25    by item (1) of subsection (a) of this Section, the 
 
 
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1    remaining moneys estimated to be collected during each 
2    fiscal year shall be appropriated.    
3        (3) (Blank).    
4        (4) Moneys appropriated to fund the programs 
5    authorized in Sections 25 and 30 shall be expended only 
6    after they have been collected and deposited into the 
7    Electric Vehicle and Charging Rebate Fund.
8    (b) Amounts appropriated to and deposited into the 
9Electric Vehicle and Charging Rebate Fund from the General 
10Revenue Fund, or any other fund, shall be distributed from the 
11Electric Vehicle and Charging Rebate Fund to fund the program 
12authorized in Section 27.
13(Source: P.A. 103-8, eff. 6-7-23; 103-363, eff. 7-28-23; 
14103-605, eff. 7-1-24; 104-6, eff. 7-1-25.)
 
15    (415 ILCS 120/45)
16    Sec. 45. Electric Vehicle and Charging Rebate Fund; 
17creation; deposit of user fees. A separate fund in the State 
18treasury Treasury called the Electric Vehicle and Charging    
19Rebate Fund is created, into which shall be transferred the 
20user fees as provided in Section 35, funds as provided in 
21Section 605-1075 of the Department of Commerce and Economic 
22Opportunity Law of the Civil Administrative Code of Illinois,    
23and any other revenues, deposits, State appropriations, 
24contributions, grants, gifts, bequests, legacies of money and 
25securities, or transfers as provided by law from, without 
 
 
10400SB0025ham003- 910 -LRB104 07069 AAS 29208 a

1limitation, governmental entities, private sources, 
2foundations, trade associations, industry organizations, and 
3not-for-profit organizations.
4(Source: P.A. 102-662, eff. 9-15-21.)
 
5    Section 90-55. The Illinois Nuclear Safety Preparedness 
6Act is amended by changing Sections 3, 4, 5, 8, and 9 and by 
7adding Section 6.5 as follows:
 
8    (420 ILCS 5/3)  (from Ch. 111 1/2, par. 4303)
9    Sec. 3. Definitions. Unless the context otherwise clearly 
10requires, as used in this Act:
11    (1) "Agency" or "IEMA-OHS" means the Illinois Emergency 
12Management Agency and Office of Homeland Security, or its 
13successor agency.
14    (2) "Director" means the Director of the Agency.
15    (2.5) "Emergency planning zone" means a generic area 
16around a commercial nuclear facility used to assist in 
17off-site emergency planning and the development of a 
18significant response base.    
19    (3) "Person" means any individual, corporation, 
20partnership, firm, association, trust, estate, public or 
21private institution, group, agency, political subdivision of 
22this State, any other state or political subdivision or agency 
23thereof, and any legal successor, representative, agent, or 
24agency of the foregoing.
 
 
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1    (4) "NRC" means the United States Nuclear Regulatory 
2Commission or any agency which succeeds to its functions in 
3the licensing of nuclear power reactors or facilities for 
4storing spent nuclear fuel.
5    (5) "High-level radioactive waste" means (1) the highly 
6radioactive material resulting from the reprocessing of spent 
7nuclear fuel including liquid waste produced directly in 
8reprocessing and any solid material derived from such liquid 
9waste that contains fission products in sufficient 
10concentrations; and (2) the highly radioactive material that 
11the NRC has determined to be high-level radioactive waste 
12requiring permanent isolation.
13    (6) "Nuclear facilities" means nuclear power plants, 
14facilities housing nuclear test and research reactors, 
15facilities for the chemical conversion of uranium, and 
16facilities for the storage of spent nuclear fuel or high-level 
17radioactive waste.
18    (7) "Spent nuclear fuel" means fuel that has been 
19withdrawn from a nuclear reactor following irradiation, the 
20constituent elements of which have not been separated by 
21reprocessing.
22    (8) "Transuranic waste" means material contaminated with 
23elements that have an atomic number greater than 92, including 
24neptunium, plutonium, americium, and curium, excluding 
25radioactive wastes shipped to a licensed low-level radioactive 
26waste disposal facility.
 
 
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1    (9) "Highway route controlled quantity of radioactive 
2materials" means that quantity of radioactive materials 
3defined as a highway route controlled quantity under rules of 
4the United States Department of Transportation, or any 
5successor agency. 
6    (10) "Nuclear power plant" or "nuclear steam-generating 
7facility" means a thermal power plant in which the energy 
8(heat) released by the fissioning of nuclear fuel is used to 
9boil water to produce steam.
10    (11) "Nuclear power reactor" means an apparatus, other 
11than an atomic weapon, designed or used to sustain nuclear 
12fission in a self-supporting chain reaction.
13    (12) (Blank). "Small modular reactor" or "SMR" means an 
14advanced nuclear reactor: (1) with a rated nameplate capacity 
15of 300 electrical megawatts or less; and (2) that may be 
16constructed and operated in combination with similar reactors 
17at a single site.
18    (13) "Site boundary" means the line beyond which the land 
19or property is not owned, leased, or otherwise controlled by 
20the licensee.    
21(Source: P.A. 103-569, eff. 6-1-24.)
 
22    (420 ILCS 5/4)  (from Ch. 111 1/2, par. 4304)
23    Sec. 4. Nuclear accident plans; fees.     
24    (a) Persons engaged within this State in the production of 
25electricity utilizing nuclear energy, the operation of nuclear 
 
 
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1test and research reactors, the chemical conversion of 
2uranium, or the transportation, storage or possession of spent 
3nuclear fuel or high-level radioactive waste shall pay fees to 
4cover the cost of establishing plans and programs to deal with 
5the possibility of nuclear accidents. Except as provided 
6below, the fees shall be used to fund those Agency and local 
7government activities defined as necessary by the Director to 
8implement and maintain the plans and programs authorized by 
9this Act. 
10    (b) Local governments incurring expenses attributable to 
11implementation and maintenance of the plans and programs 
12authorized by this Act may apply to the Agency for 
13compensation for those expenses, and upon approval by the 
14Director of applications submitted by local governments, the 
15Agency shall compensate local governments from fees collected 
16under this Section. The Agency shall, by rule, determine the 
17method for compensating local governments under this Section.    
18Compensation for local governments shall include $250,000 in 
19any year through fiscal year 1993, $275,000 in fiscal year 
201994 and fiscal year 1995, $300,000 in fiscal year 1996, 
21$400,000 in fiscal year 1997, and $450,000 in fiscal year 1998 
22and thereafter.    
23    (c) Appropriations to the Agency Department of Nuclear 
24Safety (of which the Agency is the successor) for compensation 
25to local governments from the Nuclear Safety Emergency 
26Preparedness Fund provided for in this Section shall not 
 
 
10400SB0025ham003- 914 -LRB104 07069 AAS 29208 a

1exceed $1,500,000 $650,000 per State fiscal year. Expenditures 
2from these appropriations shall not exceed, in a single State 
3fiscal year, the annual compensation amount made available to 
4local governments under this Section, unexpended funds made 
5available for local government compensation in the previous 
6fiscal year, and funds recovered under the Illinois Grant 
7Funds Recovery Act during previous fiscal years. 
8Notwithstanding any other provision of this Act, the 
9expenditure limitation for fiscal year 1998 shall include the 
10additional $100,000 made available to local governments for 
11fiscal year 1997 under this amendatory Act of 1997. The Agency 
12shall, by rule, determine the method for compensating local 
13governments under this Section. The appropriation shall not 
14exceed $500,000 in any year preceding fiscal year 1996; the 
15appropriation shall not exceed $625,000 in fiscal year 1996, 
16$725,000 in fiscal year 1997, and $775,000 in fiscal year 1998 
17and thereafter. The fees shall consist of the following:
18    (d) Persons operating commercial nuclear power reactors 
19shall pay fees as follows:    
20        (1) A one-time fee per new nuclear power reactor    
21    charge of $590,000 per nuclear power station in this State 
22    to be paid pursuant to Section 5 and according to the 
23    following: by the owners of the stations.
24            (A) $1,500,000 at a new site requiring an 
25        equipotential zone;
26            (B) $500,000 at an existing site requiring an 
 
 
10400SB0025ham003- 915 -LRB104 07069 AAS 29208 a

1        equipotential zone;
2            (C) $600,000 at a new site not requiring an 
3        equipotential zone.
4        (1.5) For nuclear power reactors in operation on 
5    January 1, 2026, a fee of $500,000 per nuclear power 
6    reactor in this State to be paid pursuant to Section 5.    
7        (2) For nuclear power reactors that have a plume 
8    exposure pathway emergency planning zone that extends 
9    beyond the site boundary, an annual fee per nuclear power 
10    reactor shall be as follows: An additional charge of 
11    $240,000 per nuclear power station for which a fee under 
12    subparagraph (1) was paid before June 30, 1982.
13            (A) The base fee shall be $3,900,000 per operating 
14        reactor.
15            (B) Payment shall be made pursuant to Section 5 of 
16        this Act.
17        (3) For nuclear power reactors not required to have an 
18    emergency planning zone, an annual fee of $750,000 per 
19    reactor until the NRC terminates the license. Through June 
20    30, 1982, an annual fee of $75,000 per year for each 
21    nuclear power reactor for which an operating license has 
22    been issued by the NRC, and after June 30, 1982, and 
23    through June 30, 1984 an annual fee of $180,000 per year 
24    for each nuclear power reactor for which an operating 
25    license has been issued by the NRC, and after June 30, 
26    1984, and through June 30, 1991, an annual fee of $400,000 
 
 
10400SB0025ham003- 916 -LRB104 07069 AAS 29208 a

1    for each nuclear power reactor for which an operating 
2    license has been issued by the NRC, to be paid by the 
3    owners of nuclear power reactors operating in this State. 
4    After June 30, 1991, the owners of nuclear power reactors 
5    in this State for which operating licenses have been 
6    issued by the NRC shall pay the following fees for each 
7    such nuclear power reactor: for State fiscal year 1992, 
8    $925,000; for State fiscal year 1993, $975,000; for State 
9    fiscal year 1994; $1,010,000; for State fiscal year 1995, 
10    $1,060,000; for State fiscal years 1996 and 1997, 
11    $1,110,000; for State fiscal year 1998, $1,314,000; for 
12    State fiscal year 1999, $1,368,000; for State fiscal year 
13    2000, $1,404,000; for State fiscal year 2001, $1,696,455; 
14    for State fiscal year 2002, $1,730,636; for State fiscal 
15    year 2003 through State fiscal year 2011, $1,757,727; for 
16    State fiscal year 2012 and subsequent fiscal years, 
17    $1,903,182.
18        (3.5) The owner of a nuclear power reactor that 
19    notifies the Nuclear Regulatory Commission that the 
20    nuclear power reactor has permanently ceased operations 
21    during State fiscal year 1998 shall pay the following fees 
22    for each such nuclear power reactor: $1,368,000 for State 
23    fiscal year 1999 and $1,404,000 for State fiscal year 
24    2000.
25        (4) For nuclear power reactors with an equipotential 
26    zone constructed on a new site after January 1, 2026, the 
 
 
10400SB0025ham003- 917 -LRB104 07069 AAS 29208 a

1    operator or the owner shall reimburse the Agency for the 
2    actual costs of any equipment, materials, and labor 
3    provided for development, installation, and maintenance of 
4    monitoring systems as required under paragraphs (1), (2), 
5    (3), and (7) of subsection (a) of Section 8. The operator 
6    or owner shall be invoiced by the Agency and payment shall 
7    be due within 60 days after the date of the invoice. A 
8    capital expenditure surcharge of $1,400,000 per nuclear 
9    power station in this State, whether operating or under 
10    construction, shall be paid by the owners of the station.
11        (5) An annual fee of $25,000 per year for each site for 
12    which a valid operating license has been issued by NRC for 
13    the operation of an away-from-reactor spent nuclear fuel 
14    or high-level radioactive waste storage facility, to be 
15    paid by the owners of facilities for the storage of spent 
16    nuclear fuel or high-level radioactive waste for others in 
17    this State.
18        (6) A one-time charge of $280,000 for each facility in 
19    this State housing a nuclear test and research reactor, to 
20    be paid by the operator of the facility. However, this 
21    charge shall not be required to be paid by any 
22    tax-supported institution.
23        (7) A one-time charge of $50,000 for each facility in 
24    this State for the chemical conversion of uranium, to be 
25    paid by the owner of the facility.
26        (8) An annual fee of $150,000 per year for each 
 
 
10400SB0025ham003- 918 -LRB104 07069 AAS 29208 a

1    facility in this State housing a nuclear test and research 
2    reactor, to be paid by the operator of the facility. 
3    However, this annual fee shall not be required to be paid 
4    by any tax-supported institution.
5        (9) An annual fee of $15,000 per year for each 
6    facility in this State for the chemical conversion of 
7    uranium, to be paid by the owner of the facility.
8        (10) A fee assessed at the rate of $2,500 per truck for 
9    each truck shipment and $4,500 for the first cask and 
10    $3,000 for each additional cask for each rail shipment of 
11    spent nuclear fuel, high-level radioactive waste, 
12    transuranic waste, or a highway route controlled quantity 
13    of radioactive materials received at or departing from any 
14    nuclear power station or away-from-reactor spent nuclear 
15    fuel, high-level radioactive waste, transuranic waste 
16    storage facility, or other facility in this State to be 
17    paid by the shipper of the spent nuclear fuel, high level 
18    radioactive waste, transuranic waste, or highway route 
19    controlled quantity of radioactive material. Truck 
20    shipments of greater than 250 miles in Illinois are 
21    subject to a surcharge of $25 per mile over 250 miles for 
22    each truck in the shipment.
23        (11) A fee assessed at the rate of $2,500 per truck for 
24    each truck shipment and $4,500 for the first cask and 
25    $3,000 for each additional cask for each rail shipment of 
26    spent nuclear fuel, high-level radioactive waste, 
 
 
10400SB0025ham003- 919 -LRB104 07069 AAS 29208 a

1    transuranic waste, or a highway route controlled quantity 
2    of radioactive materials traversing the State to be paid 
3    by the shipper of the spent nuclear fuel, high level 
4    radioactive waste, transuranic waste, or highway route 
5    controlled quantity of radioactive material. Truck 
6    shipments of greater than 250 miles in Illinois are 
7    subject to a surcharge of $25 per mile over 250 miles for 
8    each truck in the shipment. For truck shipments of less 
9    than 100 miles in Illinois that consist entirely of 
10    cobalt-60 or other medical isotopes or both, the $2,500 
11    per truck fee shall be reduced to $1,500 for the first 
12    truck and $750 for each additional truck in the same 
13    shipment. 
14        (12) In each of the State fiscal years 1988 through 
15    1991, in addition to the annual fee provided for in 
16    subparagraph (3), a fee of $400,000 for each nuclear power 
17    reactor for which an operating license has been issued by 
18    the NRC, to be paid by the owners of nuclear power reactors 
19    operating in this State. Within 120 days after the end of 
20    the State fiscal years ending June 30, 1988, June 30, 
21    1989, June 30, 1990, and June 30, 1991, the Agency shall 
22    determine the expenses of the Illinois Nuclear Safety 
23    Preparedness Program paid from funds appropriated for 
24    those fiscal years.
25(Source: P.A. 97-195, eff. 7-25-11; 97-732, eff. 6-30-12; 
2698-728, eff. 1-1-15.)
 
 
 
10400SB0025ham003- 920 -LRB104 07069 AAS 29208 a

1    (420 ILCS 5/5)  (from Ch. 111 1/2, par. 4305)
2    Sec. 5. Nuclear power reactor or spent fuel storage 
3facility operating license fees.        
4    (a) Except as otherwise provided in this Section, within 
530 days after the beginning of each State fiscal year, each 
6person who possessed a valid operating license issued by the 
7NRC for a nuclear power reactor or a spent fuel storage 
8facility during any portion of the previous fiscal year shall 
9pay to the Agency the fees imposed by Section 4 of this Act. 
10    (b) The one-time nuclear power reactor fee facility charge    
11assessed pursuant to subparagraph (1) of subsection (d) of 
12Section 4 shall be paid to the Agency not less than 2 years 
13prior to scheduled commencement of commercial operation. The 
14one-time fee is only applicable to nuclear power reactors 
15constructed after January 1, 2026. The additional facility 
16charge assessed pursuant to subparagraph (2) of Section 4 
17shall be paid to the Department within 90 days of June 30, 
181982. Fees assessed pursuant to subparagraph (3) of Section 4 
19for State fiscal year 1992 shall be payable as follows: 
20$400,000 due on August 1, 1991, and $525,000 due on January 1, 
211992. Fees assessed pursuant to subparagraph (3) of Section 4 
22for State fiscal years 1993 through 2011 shall be due and 
23payable in two equal payments on July 1 and January 1 during 
24the fiscal year in which the fee is due. For State fiscal year 
252012 and subsequent fiscal years, fees shall be due and 
 
 
10400SB0025ham003- 921 -LRB104 07069 AAS 29208 a

1payable in 4 equal payments on July 1, October 1, January 1, 
2and April 1 during the fiscal year in which the fee is due. 
3Fees assessed pursuant to subparagraph (4) of Section 4 shall 
4be paid in six payments, the first, in the amount of $400,000, 
5shall be due and payable 30 days after the effective date of 
6this Amendatory Act of 1984. Subsequent payments shall be in 
7the amount of $200,000 each, and shall be due and payable 
8annually on August 1, 1985 through August 1, 1989, inclusive. 
9Fees assessed under the provisions of subparagraphs (6) and 
10(7) of Section 4 of this Act shall be paid on or before January 
111, 1990. Fees assessed under the provisions of subparagraphs 
12(8) and (9) of Section 4 of this Act shall be paid on or before 
13January 1st of each year, beginning January 1, 1990. Fees 
14assessed under the provisions of subparagraphs (10) and (11) 
15of Section 4 of this Act shall be paid to the Agency within 60 
16days after completion of such shipments within this State. 
17Fees assessed pursuant to subparagraph (12) of Section 4 shall 
18be paid to the Agency by each person who possessed a valid 
19operating license issued by the NRC for a nuclear power 
20reactor during any portion of the previous State fiscal year 
21as follows: the fee due in fiscal year 1988 shall be paid on 
22January 15, 1988, the fee due in fiscal year 1989 shall be paid 
23on December 1, 1988, and subsequent fees shall be paid 
24annually on December 1, 1989 through December 1, 1990.
25    (c) The fee assessed pursuant to subparagraph (1.5) of 
26subsection (d) of Section 4 shall be paid in 4 installments to 
 
 
10400SB0025ham003- 922 -LRB104 07069 AAS 29208 a

1the Agency on July 1, 2026, October 1, 2026, January 1, 2027, 
2and April 1, 2027.
3    (d) The annual fee for each nuclear power reactor assessed 
4pursuant to subparagraphs (2) and (3) of subsection (d) of 
5Section 4 shall be paid in 4 installments to the Agency on July 
61, October 1, January 1, and April 1 of the State fiscal year 
7the fee is due.    
8    (e) Fees assessed under the provisions of subparagraphs 
9(8) and (9) of subsection (d) of Section 4 of this Act shall be 
10paid on or before January 1 of each year.    
11    (f) Fees assessed under the provisions of subparagraphs 
12(10) and (11) of subsection (d) of Section 4 of this Act shall 
13be paid to the Agency within 60 days after completion of such 
14shipments within this State.    
15    (b) Fees assessed pursuant to paragraph (3.5) of Section 4 
16for State fiscal years 1999 and 2000 shall be due and payable 
17in 2 equal payments on July 1 and January 1 during the fiscal 
18year in which the fee is due. The fee due on July 1, 1998 shall 
19be payable on that date, or within 10 days after the effective 
20date of this amendatory Act of 1998, whichever is later.
21    (g) (c) Any person who fails to pay a fee assessed under 
22Section 4 of this Act within 90 days after the fee is payable 
23is liable in a civil action for an amount not to exceed 4 times 
24the amount assessed and not paid. The action shall be brought 
25by the Attorney General at the request of the Agency. If the 
26action involves a fixed facility in Illinois, the action shall 
 
 
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1be brought in the Circuit Court of the county in which the 
2facility is located. If the action does not involve a fixed 
3facility in Illinois, the action shall be brought in the 
4Circuit Court of Sangamon County.
5(Source: P.A. 97-195, eff. 7-25-11.)
 
6    (420 ILCS 5/6.5 new)
7    Sec. 6.5. Rulemaking. The Agency is authorized to adopt 
8rules as appropriate to implement any provision of this Act 
9not otherwise specified.
 
10    (420 ILCS 5/8)  (from Ch. 111 1/2, par. 4308)
11    Sec. 8. (a) The Illinois Nuclear Safety Preparedness 
12Program shall consist of an assessment of the potential 
13nuclear accidents, their radiological consequences, and the 
14necessary protective actions required to mitigate the effects 
15of such accidents. It shall include, but not necessarily be 
16limited to:
17        (1) Development of a remote effluent monitoring system 
18    capable of reliably detecting and quantifying accidental 
19    radioactive releases from nuclear power plants to the 
20    environment;
21        (2) Development of an environmental monitoring program 
22    for nuclear facilities other than nuclear power plants;
23        (3) Development of procedures for radiological 
24    assessment and radiation exposure control for areas 
 
 
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1    surrounding each nuclear facility in Illinois;
2        (4) Radiological training of State and local emergency 
3    response personnel in accordance with the Agency's 
4    responsibilities under the program;
5        (5) Participation in the development of accident 
6    scenarios and in the exercising of fixed facility nuclear 
7    emergency response plans;
8        (6) Development of mitigative emergency planning 
9    standards including, but not limited to, standards 
10    pertaining to evacuations, re-entry into evacuated areas, 
11    contaminated foodstuffs and contaminated water supplies;
12        (7) Provision of specialized response equipment 
13    necessary to accomplish this task;
14        (8) Implementation of the Boiler and Pressure Vessel 
15    Safety program at nuclear steam-generating facilities as 
16    mandated by Section 2005-35 of the Department of Nuclear 
17    Safety Law, or its successor statute;
18        (9) Development and implementation of a plan for 
19    inspecting and escorting all shipments of spent nuclear 
20    fuel, high-level radioactive waste, transuranic waste, and 
21    highway route controlled quantities of radioactive 
22    materials in Illinois;
23        (10) Implementation of the program under the Illinois 
24    Nuclear Facility Safety Act; and
25        (11) Development and implementation of a 
26    radiochemistry laboratory capable of preparing 
 
 
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1    environmental samples, performing analyses, 
2    quantification, and reporting for assessment and radiation 
3    exposure control due to accidental radioactive releases 
4    from nuclear power plants into the environment. 
5    (b) The Agency may incorporate data collected by the 
6operator of a nuclear facility into the Agency's remote 
7monitoring system.
8    (c) The owners of each nuclear power reactor in Illinois 
9shall provide the Agency all system status signals which 
10initiate Emergency Action Level Declarations, actuate accident 
11mitigation and provide mitigation verification as directed by 
12the Agency. The Agency shall designate by rule those system 
13status signals that must be provided. Signals providing 
14indication of operating power level shall also be provided. 
15The owners of the nuclear power reactors shall, at their 
16expense, ensure that valid signals will be provided 
17continuously 24 hours a day.
18    All such signals shall be provided in a manner and at a 
19frequency specified by the Agency for incorporation into and 
20augmentation of the remote effluent monitoring system 
21specified in paragraph (1) of subsection (a) of this Section. 
22Provision shall be made for assuring that such system status 
23and power level signals shall be available to the Agency 
24during reactor operation as well as throughout accidents and 
25subsequent recovery operations.
26    For nuclear reactors with operating licenses issued by the 
 
 
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1Nuclear Regulatory Commission prior to the effective date of 
2this amendatory Act, such system status and power level 
3signals shall be provided to the Department of Nuclear Safety 
4(of which the Agency is the successor) by March 1, 1985. For 
5reactors without such a license on the effective date of this 
6amendatory Act, such signals shall be provided to the 
7Department prior to commencing initial fuel load for such 
8reactor. Nuclear reactors receiving their operating license 
9after September 7, 1984 (the effective date of Public Act 
1083-1342), but before July 1, 1985, shall provide such system 
11status and power level signals to the Department of Nuclear 
12Safety (of which the Agency is the successor) by September 1, 
131985.
14(Source: P.A. 102-133, eff. 7-23-21; 103-154, eff. 6-30-23.)
 
15    (420 ILCS 5/9)  (from Ch. 111 1/2, par. 4309)
16    Sec. 9. Any equipment purchased by the Agency to be 
17installed on the premises of a nuclear facility pursuant to 
18the provisions of subsections (1), (2) and (7) of Section 8 of 
19this Act shall be installed by the owner of such nuclear 
20facility in accordance with criteria and standards established 
21by the Director of the Agency, including criteria for 
22location, supporting utilities, and methods of installation. 
23Such installation shall be at no cost to the Agency. The owner 
24of the nuclear facility shall also, at its expense, pay for 
25modifications of its facility as requested by the Agency    
 
 
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1Department to accommodate the Agency's equipment including 
2updated equipment, and to accommodate changes in the Agency's 
3criteria and standards.
4(Source: P.A. 93-1029, eff. 8-25-04.)
 
5
ARTICLE 99.

 
6    Section 99-97. Severability. The provisions of this Act 
7are severable under Section 1.31 of the Statute on Statutes.".